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 clean and intelligent energy management applications and services for the smart grid, which include comprehensive demand response, data-driven energy efficiency, energy price and risk management and enterprise carbon management applications and services. Our energy management applications and services enable cost effective energy management strategies for commercial, institutional and industrial end-users of energy, which we refer to as our C&I customers, and our electric power grid operator and utility customers by reducing real-time demand for electricity, increasing energy efficiency, improving energy supply transparency, and mitigating emissions.
We believe that we are the largest demand response service provider to C&I customers in the United States. As of December 31, 2010, we managed over 5,300 megawatts, or MW, of demand response capacity across a C&I customer base of approximately 3,600 accounts and 8,600 sites throughout multiple electric power grids. Demand response is an alternative to traditional power generation and transmission infrastructure projects that enables electric power grid operators and utilities to reduce the likelihood of service disruptions, such as brownouts and blackouts, during periods of peak electricity demand, and otherwise manage the electric power grid during short-term imbalances of supply and demand or during periods when energy prices are high. We use our Network Operations Center, or NOC, and comprehensive demand response application, DemandSMART, to remotely manage and reduce electricity consumption across a growing network of C&I customer sites, making demand response capacity available to electric power grid operators and utilities on demand while helping C&I customers achieve energy savings, improved financial results and environmental benefits. To date, we have received substantially all of our revenues from electric power grid operators and utilities, who make recurring payments to us for managing demand response capacity that we share with our C&I customers in exchange for those C&I customers reducing their power consumption when called upon.
We build on our position as a leading demand response services provider by using our NOC and energy management application platform to deliver a portfolio of additional energy management applications and services to new and existing C&I, electric power grid operator and utility customers. These additional energy management applications and services include our EfficiencySMART, SupplySMART and CarbonSMART applications and services. EfficiencySMART is our data-driven energy efficiency suite that includes commissioning and retro-commissioning authority services, energy consulting and engineering services, a persistent commissioning application and an enterprise energy management application for managing energy across a portfolio of sites. SupplySMART is our energy price and risk management application that provides our C&I customers located in restructured or deregulated markets throughout the United States with the ability to more effectively manage the energy supplier selection process, including energy supply product procurement and implementation, budget forecasting, and utility bill management. CarbonSMART is our enterprise carbon management application that supports and manages the measurement, tracking, analysis, reporting and management of greenhouse gas emissions.
Since inception, our business has grown substantially. We began by providing demand response services in one state in 2003 and have expanded to providing our portfolio of energy management applications and services in several regions throughout the United States, as well as internationally in Canada and the United Kingdom by December 31, 2010.
Strategy
Our strategy is to capitalize on our established track record, substantial operating experience and scalable and proprietary energy management platform, as well as our leading market position in the United States, to continue providing clean and intelligent energy management applications and services to our C&I customers
and electric power grid operators and utilities. Our goal is to become the leading outsourced energy management service provider for C&I, electric power grid and utility customers worldwide. Key elements of our strategy include:
Strengthen Demand Response Presence by Growing in Existing and New Regions in the United States. We will continue to actively pursue opportunities to provide demand response services to electric power grid operators and utilities in markets in the United States through additional long-term contracts and open market program opportunities for demand response resources. To provide these demand response resources, we expect to enter into contracts with new C&I customers. We believe that our comprehensive demand response application and services, the recurring payments that we provide to C&I customers and our national presence will enable us to continue to pursue rapid growth of our C&I customer base and strengthen our presence as a leader in providing demand response services.
Expand Sales of our Portfolio of Additional Energy Management Applications and Services. We intend to continue to leverage our leadership role in the demand response market to deliver a portfolio of additional energy management applications and services to new and existing C&I customers, including our EfficiencySMART, SupplySMART and CarbonSMART applications and services. We will continue to develop our technology, including our proprietary energy management application platform, which enables us to measure, manage, benchmark and optimize C&I customers’ energy consumption and facility operations, and connect to electric power grid operator and utility control rooms. We believe that our C&I customers will become increasingly aware of their energy costs and consumption and will look to advanced analytics and trusted third-party providers to help them better manage their overall energy expenditures. Therefore, we will continue to leverage the detailed energy information that we collect at our C&I customer sites to provide our EfficiencySMART application and services to help our C&I customers drive down operating costs associated with energy spend and help our electric power grid operator and utility customers meet their energy efficiency targets. We will also continue to aggressively promote our SupplySMART application and services to our C&I customers to enable them to mitigate risk through competitive energy supply contracts and achieve energy cost savings. In addition, as a result of voluntary or mandatory greenhouse gas reporting requirements, we believe that C&I customers will become increasingly aware of their greenhouse gas emissions and will look to third-party providers to help them better calculate, track, report and manage their carbon emissions and associated costs and risks. We therefore will continue to offer emissions tracking and trading support services to our C&I customers through our CarbonSMART application.
Actively Pursue Targeted Strategic Acquisitions. We intend to actively pursue selective acquisitions to reinforce our leadership position in the expanding clean and intelligent energy management application and services sector. This sector consists of a number of companies with technology offerings or customer relationships that present attractive acquisition opportunities. We intend to look for opportunities to acquire technologies that would support and enhance our current energy management application platform. Customer relationship acquisitions will focus on expansion into new geographic regions both in the United States and internationally. We have a strong track record of successfully integrating acquired companies to increase our customer base, entering new geographic regions, improving our offerings and enhancing our technology. For example, in January 2011, we acquired Global Energy Partners Inc., or Global Energy, a company specializing in the design and implementation of utility energy efficiency and demand response programs, and M2M Communications Corporation, or M2M, a company specializing in wireless technology solutions for energy management and demand response.
Target Expansion by Entering International Markets. We also intend to expand our addressable market by pursuing demand response and energy management opportunities in international markets. We are a leader in the development, implementation and broader adoption of clean and intelligent energy management applications and services for the smart grid and have built a national footprint in the United States. We believe we can achieve a similar significant first-mover advantage internationally, principally in Canada, the United Kingdom and Europe. 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 will provide a significant opportunity to grow our C&I customer base and provide a differentiated offering to C&I customers with international operations.
Energy Management Applications and Services
DemandSMART
Demand response is achieved when C&I customers reduce their consumption of electricity from the electric power grid in response to a market signal, such as capacity constraints, price signals or transmission-level imbalances. C&I customers can reduce their consumption of electricity by reducing demand (for example, by dimming lights, resetting air conditioning set-points or shutting down production lines) or they can self-generate electricity with onsite generation (for example, by means of a back-up generator or onsite cogeneration). Our demand response capacity provides a more timely, cost-effective and environmentally-sound alternative to building conventional supply-side resources, such as natural gas-fired peaking power plants, to meet periods of peak electricity demand.
We are a leader in the development, implementation and broader adoption of technology-enabled demand response services for the smart grid. Our DemandSMART application enables us to send control signals to, and receive bi-directional communications from, an Internet-enabled network of broadly dispersed C&I customer sites in order to initiate, monitor and complete demand response activity. Our robust and scalable technology and proprietary operational processes have the ability to automate demand response and simplify C&I customer participation by remotely reducing electricity usage in a matter of minutes, or send curtailment instructions to our C&I customers to be manually implemented on site. The devices that we install at our C&I customer sites transmit to us via the Internet near real-time electrical consumption data on a 1-minute, 5-minute, 15-minute and hourly basis. Our DemandSMART application analyzes the data from individual sites and aggregates data for specific regions. When a demand response event occurs, our NOC automatically processes the notification coming from the electric power grid operator or utility. Our NOC operators then begin activating procedures to curtail demand from the grid at our C&I customer sites. Our one-click curtailment activation sends signals to all C&I customer sites in the targeted geography where the event is occurring. Upon activation of demand reduction, DemandSMART, which receives near real-time data from each C&I customer site, is able to determine on a near real-time basis whether the location is performing as expected. Signals are relayed to our NOC operators when further steps are needed to achieve demand reductions at any given location. Each C&I customer site is monitored for the duration of the demand response event and operations are restored to normal when the event ends.
DemandSMART is designed for the C&I customer market, which represents approximately 60% of the United States electricity consumption. We provide demand response capacity to electric power grid operators and utilities by contracting with C&I customers to reduce their electricity usage on demand. We receive most of our revenues from electric power grid operators and utilities, and we make payments to our C&I customers for both contracting to reduce electricity usage and actually doing so when called upon.
We provide our demand response services to electric power grid operators and utilities under long-term contracts and pursuant to open market bidding programs. Our long-term contracts generally have terms of three to ten years and predetermined capacity commitment and payment levels. Our open market bidding program opportunities are generally characterized by flexible capacity commitments and prices that vary by hour, day, month, bidding period or supplemental, new or modified demand response programs. Within these contracts and open market programs, we offer the following services to address the needs of electric power grid operators and utilities: (i) reliability-based demand response, (ii) price-based demand response, and (iii) short-term reserve resources referred to in the electric power industry as ancillary services.
Reliability-Based Demand Response. We receive recurring capacity payments, which we share with our C&I customers, from electric power grid operators and utilities for being on call, which means having available previously registered demand response capacity that we have aggregated from our C&I customers, regardless of whether we receive a signal to reduce consumption. When we receive a signal from an electric power grid operator or utility customer, which we refer to as a dispatch signal, our DemandSMART application automatically notifies our C&I customers that a demand reduction is needed and initiates processes that reduce electrical consumption by certain of our C&I customers in the targeted area. When we are called to implement a demand reduction, we typically receive an additional payment, which we share with our C&I customers, for the energy that we reduce. We refer to this as an energy payment. We are called upon to
perform by electric power grid operators and utilities during periods of high demand or supply shortfalls, otherwise known as capacity deficiency events. By aggregating a large number of C&I customers to participate in these reliability-based programs, we believe that we have played a significant role over the past several years in helping to prevent brownouts and blackouts in some of the most capacity constrained regions in the United States. We currently provide reliability-based demand response services to ISO New England, Inc., or ISO-NE, PJM Interconnection, or PJM, and the New York Independent System Operator, or New York ISO, among others.
Price-Based Demand Response. Our price-based demand response services enable C&I customers to monitor and respond to wholesale electricity market price signals when it is cost-effective for them to do so. Our C&I customers use our DemandSMART application to register a “strike price” above which it may be economical for that customer to reduce its consumption of electricity. We receive an energy payment in the amount of the wholesale market price for the electricity that the C&I customer does not consume and share this payment with the C&I customer. If prices in a given market approach a given strike price, DemandSMART automatically notifies the C&I customer and initiates processes that reduce electrical consumption from the electric power grid. We currently participate in price-based demand response programs in the Mid-Atlantic and New England.
Ancillary Services. Demand response is utilized for short-term reserve requirements, referred to in the electric power industry as ancillary services, including operating reserves. This service is called upon by electric power grid operators and utilities during short-term contingency events such as the loss of a transmission line or large power plant. Through our technology, certain C&I customers are able to provide near instantaneous response for these short-term system dispatches, and often do so with negligible impact on their business operations. Electric power grid operators and utilities rely on a reserve pool of these quick-start resources to provide short-term support as needed during these contingency events. The goal of electric power grid operators and utilities is to get these resources back into standby mode as quickly as possible after they are dispatched so that the reserve pool of available capacity is replenished. Examples of ancillary services markets in which we participate include PJM’s Synchronized Reserves Market, in which we were the first provider of demand response capacity, and ISO-NE’s Demand Response Reserves Pilot program.
With respect to our demand response services, we match obligation, in the form of MW that we agree to deliver to our electric power grid operator and utility customers, with supply, in the form of MW that we are able to curtail from the electric power grid. We increase, and occasionally decrease, our obligation through open market programs, supplemental demand response programs, auctions or other similar capacity arrangements, open program registrations and bilateral contracts to account for changes in supply and demand forecasts in order to achieve more favorable pricing opportunities. We increase our ability to curtail demand from the electric power grid by deploying a sales team to contract with our C&I customers and by installing our equipment at these customers’ sites to connect them to our network. When we are called upon by our electric power grid operator or utility customers to deliver MW, we use our DemandSMART application to dispatch this network to meet the demands of these customers. We refer to the above activities as managing our portfolio of demand response capacity.
EfficiencySMART
EfficiencySMART is our data-driven energy efficiency suite of applications and services that includes commissioning and retro-commissioning authority services, energy consulting and engineering services, a persistent commissioning application and an enterprise energy management application for managing energy across a portfolio of C&I customer sites. We currently offer the following EfficiencySMART applications and services:
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EfficiencySMART Commissioning includes traditional and/or new building commissioning services, such as investigation, testing and verification of energy efficiency strategies, and persistent commissioning, which includes real time persistent data collection and analysis to identify operational inefficiencies.
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EfficiencySMART Insight provides our large, multi-site C&I customers with the ability to visualize energy usage, identify savings opportunities, and prioritize energy-related investments across a portfolio
of meters and buildings across their organizations. EfficiencySMART Insight provides C&I customers with the ability to remotely host and monitor large portfolios of meters, compute and compare baseline and benchmark data, identify the best and worst performing sites across a variety of energy usage and operational metrics, configure the rate engine for shadow billing analysis, set alerts on energy-related data streams and monitor demand levels.
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EfficiencySMART Services include a range of professional and consulting services, such as strategic enterprise planning, energy audits, engineering/design services, utility incentive reviews and savings verification services.
We have an expanding portfolio of EfficiencySMART applications and services. We provide our EfficiencySMART applications and services both directly to the C&I customer market and to utility customers under long-term contracts as a mechanism for the utilities to meet either mandated or voluntary energy efficiency targets in their service territory. Our EfficiencySMART applications and services are aimed at helping address increasingly complex energy challenges. We believe that the market opportunities for our EfficiencySMART applications and services are significant and will remain so as operational efficiency and energy savings are given increased priority by electric power grid operators, utilities and C&I end-users of electricity.
SupplySMART
SupplySMART is our energy price and risk management application that provides our C&I customers located in restructured or deregulated markets throughout the United States with the ability to more effectively manage the energy supplier selection process, including energy supply product procurement and implementation. SupplySMART provides a framework for developing and implementing risk management strategies and executing purchasing strategies that provide maximum price transparency and structural savings on an ongoing basis for our C&I customers. Using a competitive bid process, SupplySMART delivers recommendations on energy price structures, terms and conditions from available competitive suppliers of energy commodities, including electricity, natural gas and refined products. SupplySMART includes a set of online features including centralizing, tracking, and presenting utility bill and enterprise-wide utility financial information, such as budgets and forecasts, while assessing bill accuracy and savings opportunities. SupplySMART also includes an online procurement tool that bids commodity purchases amongst competitive suppliers.
CarbonSMART
CarbonSMART is our enterprise carbon management application that supports and manages the measurement, tracking, analysis, reporting and management of greenhouse gas emissions and mitigation strategies. C&I customers use CarbonSMART to benchmark their carbon footprint, comply with voluntary or mandatory carbon reporting requirements, including standard reporting scopes, and drive carbon savings activities. CarbonSMART utilizes a highly flexible and scalable data model, which allows our C&I customers to input a variety of fuel and emissions sources and automatically translate the resulting data into formats that match the requirements of various mandatory or voluntary carbon accounting and carbon reporting programs. In addition, CarbonSMART provides templates for common energy efficiency measures, such as lighting upgrades, allowing C&I customers to model potential energy savings projects and examine cost effectiveness and margin carbon cost.
Technology and Operations
Since inception, we have focused on delivering industry-leading, technology-enabled energy management applications and services. Our proprietary technology has been developed to be highly reliable and scalable and to provide a platform on which to design, customize, and implement our energy management applications and services. Our proprietary technology infrastructure is built on Linux, Java and Oracle and supports an open web services architecture. Our enterprise energy management application platform enables us to efficiently scale our DemandSMART, EfficiencySMART, SupplySMART and CarbonSMART applications in new geographic regions and rapidly grow the number of C&I customers in our network. Our energy
management application platform leverages web services that connect applications directly with other applications through a form of “loose coupling,” which allows connections to be established across applications without customization. As a result, these connections can be established across firewalls without regard to technology platform or programming language, making it easy to apply our technology across a broad range of C&I customers.
Our technology can be broken down into three primary components: the NOC, our energy management application platform and the EnerNOC Site Server.
Network Operations Center
Our technology enables our NOC to automatically respond to signals sent by electric power grid operators and utilities 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 an electric power grid operator or utility customer to our NOC. Following the receipt of such a signal, our NOC automatically notifies specified C&I customer personnel of the demand response event. After relaying this notification to our C&I 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 C&I 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, Canada and the United Kingdom, some of which require demand reductions within 10 minutes or less.
Energy Management Application Platform and Operational Process
Our energy management application platform is our web-based enterprise software platform used for DemandSMART, EfficiencySMART, SupplySMART and CarbonSMART, and is the underlying software that runs our NOC. It utilizes a modular web services architecture that is designed to allow application modules to be easily integrated into the platform. We believe that a key factor to successfully offering clean and intelligent energy management applications and services is integrating data from disparate sources and utilizing it to deliver customer-focused services utilizing open protocols.
Currently, our energy management application platform collects facility consumption data on a 1-minute, 5-minute, 15-minute and hourly basis and integrates that data with near real-time, historical and forecasted market variables. We use our energy management application platform to measure, manage, benchmark and optimize C&I customers’ energy consumption and facility operations. We use this data to help C&I customers analyze consumption patterns, forecast demand, 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. In addition, our energy management application platform enables us to track our C&I 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.
In 2009, we announced the deployment at certain of our DemandSMART C&I customer sites of 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 demand response network and also streamlines the site enablement process, allowing us to more efficiently equip C&I customers to participate in demand response programs. These devices are “firewall friendly” and can leverage existing C&I customer networks to facilitate secure, authenticated and encrypted communication, without the need to establish a virtual private network.
The EnerNOC Site Server
We install a hardware device, called an EnerNOC Site Server, or ESS, at each C&I customer site to collect and communicate near real-time electricity consumption data and, in certain cases, enable remote control of a C&I customer’s electricity consumption. The ESS communicates to our NOC through the customer’s LAN or other internet connection. The ESS is an open, integrated system consisting of a central hardware device residing inside a standard electrical box. The ESS allows our C&I customers to, among other things, respond quickly and completely to instructions from us to reduce electricity consumption.
Sales and Marketing
As of December 31, 2010, our sales and marketing team consisted of 193 employees. We organize our sales efforts by customer type. Our utility sales group sells to electric power grid operators and utilities, while our commercial and industrial sales group sells to C&I customers. Our utility sales group is responsible for securing long-term contracts from electric power grid operators and utilities for our DemandSMART and EfficiencySMART applications and services. We actively pursue long-term contracts in both restructured markets and in traditionally regulated markets. Our commercial and industrial sales group sells our energy management applications and services to C&I customers. Our commercial and industrial sales group is located in major electricity regions throughout North America, including New England, New York, the Mid-Atlantic, Texas, Florida, California, and internationally in Canada and the United Kingdom.
Our marketing group is responsible for influencing all market stakeholders including customers, energy users and policymakers, attracting prospects to our business, enabling the sales engagement process with messaging, training and sales tools, and sustaining and expanding relationships with existing C&I 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, 2010, our research and development team consisted of 58 employees. Our research and development team is responsible for developing and improving our existing clean and intelligent energy management applications and services, as well as the engineering and design of new clean and intelligent energy management applications and services. Our research and development expenses were approximately $10.1 million, $7.6 million and $6.1 million for the years ended December 31, 2010, 2009 and 2008, respectively. During the years ended December 31, 2010, 2009 and 2008, we capitalized internal software development costs of $6.8 million, $4.2 million and $3.2 million, respectively, and the amount is included as software in property and equipment at December 31, 2010. We also capitalized $1.3 million and $1.5 million during the years ended December 31, 2010 and 2009, respectively, related to a company-wide enterprise resource planning systems implementation project.
Customers
C&I Customers
Our clean and intelligent energy management applications and services provide cost effective energy management strategies for our C&I customers by reducing real-time demand for electricity, increasing energy efficiency, improving energy supply transparency, and mitigating emissions. One of our goals is to become the leading outsourced energy management service provider for C&I customers worldwide. Our commercial and industrial sales group primarily focuses their efforts on the following seven vertical markets: technology, education, food sales and storage, government, healthcare, manufacturing/industrial and commercial real estate. The following table lists some of our C&I customers as of December 31, 2010 in each of the seven key
vertical markets that our commercial and industrial sales group primarily targets for DemandSMART, EfficiencySMART, SupplySMART and CarbonSMART opportunities:
Our contracts with C&I customers typically take two to four months to complete and have terms that generally range between one and five years.
Grid Operator and Utility Customers
We have significantly grown our base of electric power grid operator and utility customers since inception. As of December 31, 2010, we provided our DemandSMART and EfficiencySMART applications and services to electric power grid operator and utility customers in several regions throughout the United States, as well as internationally in Canada and the United Kingdom. Our electric power grid operator and utility customers include ISO-NE, PJM, Southern California Edison Company and Tennessee Valley Authority, among others.
Our contracts with electric power grid operator and utility customers typically take 12 to 18 months to complete and, when successful, typically result in multi-million dollar contracts 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 electric power grid operator and utility customers for providing our energy management applications and services.
Competition
We face competition from other energy management service providers, advanced metering infrastructure service providers, and utilities and competitive electricity suppliers who offer their own demand response, data-driven energy efficiency, energy price and risk management, or enterprise carbon management services. We also compete with traditional supply-side resources, such as peaking power plants.
The industry in which we participate is fragmented. When competing for electric power grid operator and utility customers, we believe that the primary factors on which we compete are:
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the pricing of the demand response or energy efficiency services being offered; and
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the financial stability, historical performance levels and overall experience of the energy management service provider.
When competing for C&I customers, we believe that the primary factors on which we compete are:
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the level of demand response capacity payments shared with those C&I customers for their demand response capacity;
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the level of sophistication employed by the energy management service provider to identify and optimize energy management capabilities at their facilities; and
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the ability of the energy management service provider to service multiple sites across different geographic regions and to provide additional technology-enabled energy management applications and services.
We believe that our operational experience, first mover advantage and leadership in the clean and intelligent energy management applications and services sector gives us an advantage when competing for C&I, electric power grid operator, and utility customers. In addition, across our energy management application platform, we believe that we are unique in our ability to leverage real-time data across applications to unlock the greatest amount of value for our C&I customers, which 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, demand response, data-driven energy efficiency, energy price and risk management, or enterprise carbon management services 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 management applications and services 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, which could decrease our base of potential C&I customers and could decrease our revenues. However, demand response programs, as administered by utilities alone, are bound to standard tariffs to which all C&I 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 energy management applications and services to different C&I customers. We believe that we also have technology and operational experience at the facility-level, behind the meter, that both utilities and competitive electricity suppliers lack. Furthermore, we believe that our energy management applications and services are complementary to utilities and competitive electricity suppliers’ demand response efforts because we can help enlist C&I customers to their existing programs, reduce their workload by serving as a single point of contact for an aggregated pool of C&I customers who choose to participate in their programs, and act to uphold or enhance C&I customer satisfaction. However, utilities and competitive electricity suppliers may offer clean and intelligent energy management applications and services 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 C&I customers and could decrease our revenues.
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 demand response and even more so in energy efficiency because reducing demand can have the effect of reducing their sales of electricity. However, we believe that our energy management applications and services are gaining substantial regulatory support and will continue to do so 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 energy management applications and services in restructured electricity markets and in traditionally regulated electricity markets. Regulations within both types of markets impact how quickly our energy management applications and services may be adopted, the prices we can charge and profit margins we can earn, 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 of which potential markets to most aggressively pursue. In addition, certain of our contracts with utilities 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 profit margins we can earn can be impacted by market policies, such as program rules that discount the value of demand response resources because they can only be available during
a limited number of peak demand hours, unlike other types of capacity resources that may be available 24 hours per day, every day of the week. Similarly, regulations defining what constitutes demand response can affect the amount of demand response capacity that we are able to enroll from our C&I customers and the amount that we need to pay them for their participation. Regulations applicable to the energy management applications and services that we provide and the programs in which we participate may change at any time, which could significantly impact the way that we conduct our business and our results of operations and financial condition.
The policies regarding the measurement and verification of demand response resources, safety regulations and air quality or emissions regulations, which may vary by state, affect how we do business. For example, some environmental agencies may limit the amount of emissions allowed from back-up generators utilized by C&I customers, even when back-up generators are strictly used to maintain system reliability. For example, in California, demand response capacity is generally not permitted to come from C&I customers who activate back-up generators in order to reduce their electric power grid usage. Therefore, the use of back-up generators is limited under all of our contracts with that state’s utilities, with the exception of a contract that our subsidiary, Celerity Energy Partners San Diego, LLC, or Celerity, entered into with San Diego Gas & Electric, or SDG&E, which allows use of back-up generators on which we install emissions control equipment. Measurement and verification policies of various markets influence how we modify the metering and control devices we install and data we record at each C&I customer site in those markets. In limited cases, we provide an interconnected demand response resource that exports power to the electric power grid for resale, such as in the case of the contract between Celerity and SDG&E, and under certain circumstances our demand response resources may be used for other ancillary services, such as exporting power to the electric power grid as a short-term reserve resource. The export of power for resale or exporting power to the electric power grid for other ancillary services is subject to the requirements of the Federal Power Act and the direct regulation of the Federal Energy Regulatory Commission, or FERC.
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, 2010, in the United States we held two patents, one of which expires in 2024 and the other of which expires in 2022, and one published patent application. We also had three pending or published patent applications filed under the Patent Cooperation Treaty for Canada. Our patent applications, and any future patent applications might not result in a patent being issued with 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, 2010, we held 17 trademarks in the United States. These are EnerNOC, ENERBLOG, Get More from Energy, EnerNOC Get More from Energy, Energy for Education, Capacity on Demand, PowerTrak, PowerTalk, Celerity Energy, CarbonSMART, DemandSMART, EnergySMART, SiteSMART, SupplySMART, One-Click Curtailment, Clean Green California and CarbonTrak. Several of these trademarks are also registered in the European Community and Canada. In addition, we have a number of trademark applications pending in the United States, Canada, South Africa, Japan and the Peoples Republic of China.
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 energy management applications and services 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 over the four-month delivery period of June through September. This typically results in higher revenues in our second and third quarters as compared to our first and fourth quarters.
Employees
As of December 31, 2010, we had 484 full-time employees, including 193 in sales and marketing, 58 in research and development and 233 in general and administrative, including operations. Of these full-time employees, 274 were located in New England, 19 were located in New York, 29 were located in the Mid-Atlantic, 87 were located in California, nine were located in Canada, 16 were located in Texas, seven were located in Illinois, five were located in Tennessee, 12 were located in the United Kingdom and 26 were located in other areas across the United States. 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. Our employees are not represented by any labor unions or covered by a collective bargaining agreement and we have not experienced any work stoppages. We consider our relations with our employees to be good.
Available Information
We were incorporated in Delaware on June 5, 2003 and have our corporate headquarters at 101 Federal Street, Suite 1100, Boston, Massachusetts 02110. 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. We also maintain ENOC Securities Corporation, a Massachusetts securities corporation, to invest our cash balances on a short-term basis. Our Internet website address is www.enernoc.com. Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, are available free of charge through the investor relations page of our internet website as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission, or the SEC.
Item 1A.
Item 1A.
Risk Factors
The statements contained in this section, as well as statements described elsewhere in this Annual Report on Form 10-K or in our other SEC filings, describe risks that could materially and adversely affect our business, financial condition and results of operations and the trading price of our securities. These risks are not the only risks that we face. Our business, financial condition and results of operations could also be materially affected by additional factors that are not presently known to us or that we currently consider to be immaterial to our operations.
Risks Related to Our Business
Our future profitability may fluctuate, and we may incur net losses in the future.
As of December 31, 2010, we had an accumulated deficit of $67.8 million. Although we achieved profitability for the year ended December 31, 2010 with net income of $9.6 million, our net losses for the years ended December 31, 2009 and 2008 were $6.8 million and $36.7 million, respectively, and we may incur additional operating losses in the future. Our operating losses have historically been driven by start-up costs, costs of developing our technology, and operating expenses related to increased headcount and the expansion of the number of MW under our management. As we seek to grow our revenues and customer base, we plan to continue to expand our energy management applications and services, which will require increased operating expenses. These increased operating expenses, as well as other factors, may cause us to incur net losses in the future, and there can be no assurance that we will be able to grow our revenues at rates that will allow us to maintain profitability during every fiscal quarter, or even every fiscal year. If we fail to maintain profitability, the market price of our common stock could decline substantially.
A substantial majority of our revenues are and have been generated from contracts with, and open market program sales to, a limited number of electric power grid operator and utility customers, and the modification or termination of these open market programs or sales relationships could materially adversely affect our business.
During the years ended December 31, 2010, 2009 and 2008, revenues generated from open market sales to PJM, an electric power grid operator customer, accounted for 60%, 52% and 28%, 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, 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, beginning in June 2012, PJM will discontinue its Interruptible Load for Reliability program, or the ILR program, which is a program in which we have historically been an active participant. The discontinuance of the ILR program by PJM will reduce the flexibility that we currently have to manage our portfolio of demand response capacity in the PJM market and will negatively impact our future revenues and profit margins. In addition, in February 2011, PJM and Monitoring Analytics, LLC, the PJM market monitor, issued a joint statement concerning settlements in PJM’s demand response programs for participants using a certain baseline method of measurement and verification for demand response. We refer to this as the PJM statement. The PJM statement, among other things, asserted that certain market practices in the PJM market were no longer appropriate or acceptable and unilaterally implied that compensation should no longer be determined by actual measured reductions in C&I customers’ electrical load. We have filed for expedited declaratory relief with FERC seeking clarification that we may continue to manage our portfolio of demand response capacity in PJM as we have in the past and continue to receive settlement in accordance with the current PJM market rules approved by FERC. However, to the extent FERC does not grant us declaratory relief, or agrees with the PJM statement and modifies the PJM market rules in the future to reflect the PJM statement, or to the extent PJM is otherwise successful at modifying the market rules in the future, our ability to manage our portfolio of demand response capacity in the PJM market would be harmed, which will significantly reduce our future revenues and profit margins and which may have a material adverse effect on our results of operations and financial condition.
Revenues generated from two fixed price contracts with, and open market sales to ISO-NE, an electric power grid operator customer, accounted for 18%, 29% and 36%, respectively, of our total revenues for the years ended December 31, 2010, 2009 and 2008. The modification or termination of our sales relationship with ISO-NE, or the modification or termination of any of ISO-NE’s open market programs in which we
participate, could significantly reduce our future revenues and profit margins and have a material adverse effect on our results of operations and financial condition.
If we fail to obtain favorable prices in the open market programs in which we currently participate or choose to participate in the future, specifically in the PJM or ISO-NE 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. For example, open market auctions of capacity in the PJM and ISO-NE markets in which we currently participate have resulted in prices that are significantly lower than those achieved in prior periods. Accordingly, our revenues, gross profits and profit margins will be significantly and adversely affected in 2011 and 2012 as the lower capacity prices in the PJM market take effect for those years. To the extent we are subject to other similar price reductions, our revenues, gross profits and profit margins could be further negatively impacted. 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, for the foreseeable future, which could materially and adversely affect our results of operations and financial condition.
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. For example, if a demand response event or metering and verification test does not occur in a particular quarter, we may not be able to recognize revenues for the undemonstrated capacity in that quarter. This shortfall in revenues could adversely affect our operating results for that quarter and could cause the market price of our common stock to decline substantially.
We incur significant up-front costs associated with the expansion of the number of MW under our management and the infrastructure necessary to enable those MW. In most of the markets in which we originally focused our growth, we generally begin earning revenues from our MW under management within approximately one month from enablement. However, in certain forward capacity markets in which we participate or 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 forward capacity market, which is a market from which we derive a substantial portion of our revenues, 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 begin earning revenue until June of the following year. This results in a longer average revenue recognition lag time in our C&I customer portfolio from the point in time when we consider a MW to be under management to when we earn revenues from that MW. The up-front costs we incur to expand our MW under management 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.
The success of our business depends in part on our ability to develop new clean and intelligent energy management applications and services and increase the functionality of our current energy management applications and services.
The market for our energy management applications and services 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 clean and intelligent energy management applications and services 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.
From time to time, our customers have expressed a need for increased functionality in our energy management applications and services. In response, and as part of our strategy to enhance our clean and intelligent energy management applications and services 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 clean and intelligent energy management applications and services and enhance our existing energy management applications and services. Initiatives to develop new energy management applications and services 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 energy management applications and services. In addition, software addressing our energy management applications and services 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 clean and intelligent energy management applications and services or enhancements to our existing energy management applications and services on a timely basis, or if the market does not accept our new or enhanced energy management applications and services, we will lose opportunities to realize revenues and obtain customers, and our business and results of operations will be adversely affected.
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 currently derive substantially all of our revenues from the sale of our demand response application and services, directly or indirectly, to the electric power industry. Purchases of our demand response application and services by electric power grid operators or utilities 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 and increased electric utility capital spending on traditional supply-side resources. In addition, sales of our energy management applications and services to electric power grid operator and utility customers may be negatively impacted by changing regulations and program rules. For example, the commencement of ISO-NE’s forward capacity market in June 2010, which included new program rules that changed measurement and verification methodologies and lowered prices for certain demand response resource types as compared to the ISO-NE program in effect prior to June 2010, resulted in reduced participation by demand response resources. These changes to ISO-NE’s program rules negatively impacted our revenues, profits and profit margins in 2010 and any similar change to program rules in the other markets in which we participate 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 electric power grid operator and utility customers 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 months. As a result, our demand response revenues may be seasonal. For example, in the PJM forward capacity market, which is a market from which we derive a substantial portion of our revenues, we recognize capacity-based revenue from PJM over the four-month delivery period of June through September. This typically results in higher revenues in our second and third quarters as compared to our first and fourth quarters. As a result of this seasonality, 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 a spike in natural gas prices or potential decreases in availability, can lead electric power grid operators and utilities 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. In addition, given the current economic slowdown and the related potential reduction in demand for electricity, there can be no assurance that there will not be a corresponding reduction in the implementation of both supply and demand-side resources by electric power grid operators and utilities. 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 electric power grid operators and utilities could negatively impact our business and make it difficult for us to accurately forecast our future sales.
Varying regulatory structures, program rules and program designs or an oversupply of electric generation capacity in certain regional electric power markets could negatively affect our business and results of operations.
Unfavorable regulatory decisions in markets where we currently operate could also significantly and negatively affect our business. For example, in connection with the PJM statement, in the event that FERC does not grant us declaratory relief, or agrees with the PJM statement and modifies the PJM market rules in the future to reflect the PJM statement, or to the extent PJM is otherwise successful at modifying the market rules in the future, our future revenues and profit margins will be significantly reduced and our future results of operations and financial condition will be negatively impacted. 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. A limit on back-up generators would mean that some of the demand response capacity reductions we aggregate from C&I 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, and we would have to find alternative sources of capacity from C&I customers willing to reduce load by curtailing consumption rather than by generating electricity themselves. Market rules could also be modified to change the design of a particular demand response program, which may adversely affect our participation in that program, or a demand response program in which we currently participate could be eliminated in its entirety. Any elimination or change in the design of a demand response program, including any supplemental program, in which we participate, especially in the PJM or ISO-NE markets, could adversely impact our ability to successfully provide our demand response application and services or manage our portfolio of demand response capacity in that program.
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. In addition, 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 energy management applications and services 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 C&I 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. As part of our business strategy, we intend to expand into additional regional electricity markets. However, the combination of excess electric generation capacity and unfavorable regulatory structures could limit the number of regional electricity markets available to us for expansion.
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:
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problems may arise with our ability to successfully integrate the acquired businesses, which may result in us not operating as effectively and efficiently as expected, and may include:
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diversion of management time, 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;
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failure to retain and motivate key employees;
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failure to successfully manage relationships with customers and suppliers;
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failure of customers to accept our new energy management applications and services;
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failure to effectively coordinate sales and marketing efforts;
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failure to combine service offerings quickly and effectively;
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failure to effectively enhance acquired technology, applications and services or develop new applications and services relating to the acquired businesses;
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difficulties and inefficiencies in managing and operating businesses in multiple locations or operating businesses in which we have either limited or no direct experience;
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difficulties integrating financial reporting systems;
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difficulties in the timely filing of required reports with the SEC; and
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difficulties in implementing controls, procedures and policies, including disclosure controls and procedures and internal controls over financial reporting, appropriate for a larger public company at companies that, prior to their acquisition, lacked such controls, procedures and policies, which may result in ineffective disclosure controls and procedures or material weaknesses in internal controls over financial reporting;
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we may not be able to achieve the expected synergies from an acquisition, or it may take longer than expected to achieve those synergies;
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an acquisition may result in future impairment charges related to diminished fair value of businesses acquired as compared to the price we paid for them;
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an acquisition may involve restructuring operations or reductions in workforce, which may result in substantial charges to our operations;
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an acquisition may involve unexpected costs or liabilities, or the effects of purchase accounting may be different from our expectations; and
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future acquisitions could result in potentially dilutive issuances of equity securities, the incurrence of debt, or contingent liabilities, which could harm our financial condition.
In March 2010, we acquired substantially all of the assets and certain liabilities of SmallFoot LLC, or Smallfoot, and ZOX, LLC, or Zox, and in January 2011, we acquired Global Energy and M2M. There can be no assurance that we will be able to successfully integrate these companies or any other companies, products or technologies that we acquire.
We face risks related to our potential expansion into international markets.
We intend to expand our addressable market by pursuing opportunities to provide our clean and intelligent energy management applications and services in international markets. For example, during the third quarter of 2009, we commenced operations in the United Kingdom by enrolling MW in National Grid’s Short-Term Operating Reserve program. Prior to this, we had no experience operating in markets outside of the United States and Canada. Accordingly, new markets may require us to respond to new and unanticipated regulatory, marketing, sales and other challenges. There can be no assurance that we will be successful in responding to these and other challenges we may face as we enter and attempt to expand in international markets. International operations also entail a variety of other risks, including:
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unexpected changes in legislative or regulatory requirements of foreign countries;
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currency exchange fluctuations;
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longer payment cycles and greater difficulty in accounts receivable collection; and
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significant taxes or other burdens of complying with a variety of foreign laws.
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 than we expect and could significantly affect our results of operations and financial condition.
We have a limited operating history in an emerging market, which may make it difficult to evaluate our business and prospects, and may expose us to increased risks and uncertainties.
We were incorporated as a Delaware corporation in June 2003 and first began generating revenues in 2003. Accordingly, we have only a limited history of generating revenues, and the future revenue potential of our business in the emerging market for clean and intelligent energy management applications and services is uncertain. As a result of our short operating history, we have limited financial data that can be used to evaluate our business, strategies, performance and prospects or an investment in our common stock. Any evaluation of our business and our prospects must be considered in light of our limited operating history and the risks and uncertainties encountered by companies in an emerging market. To address these risks and uncertainties, we must do the following:
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maintain our current relationships and develop new relationships with electric power grid operators and utilities and the entities that regulate them;
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maintain and expand our current relationships and develop new relationships with C&I customers;
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maintain and enhance our existing energy management applications and services, and technology systems;
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continue to develop clean and intelligent energy management applications and services that achieve significant market acceptance;
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continue to enhance our information processing systems;
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execute our business and marketing strategies successfully, including accurately nominating demand response capacity to our electric power grid operator and utility customers, and delivering a high level of performance by assisting our C&I customers to reduce their energy usage during demand response events;
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respond to competitive developments;
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attract, integrate, retain and motivate qualified personnel; and
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continue to participate in shaping the regulatory environment.
We may be unable to accomplish one or more of these objectives, which could cause our business to suffer. In addition, accomplishing many of these goals might be very expensive, which could adversely impact our operating results and financial condition. Any predictions about our future operating results may not be as accurate as they could be if we had a longer operating history and if the market in which we operate was more mature.
We operate in highly competitive markets; if we are unable to compete successfully, we could lose market share and revenues.
The market for clean and intelligent energy management applications and services is fragmented. Some traditional providers of advanced metering infrastructure services have added, or may add, demand response or other energy management applications 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 demand response 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 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 energy management services 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 energy management applications and services.
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 electric power grid operator and utility customers either under fixed price long-term contracts, which we refer to as utility contracts, or under terms established in open market bidding programs where capacity is purchased. Under the utility contracts and open market bidding programs, electric power grid operators and utilities 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 period, or make periodic payments to us based on the amount of demand response capacity that we bid to make available to them during the relevant period. We refer to these payments as committed capacity payments. Committed capacity is negotiated and established by the utility contract or set in the open market bidding process and is subject to subsequent confirmation by measurement and verification tests or performance in a demand response event. In our open market bidding programs, we offer different amounts of committed capacity to our electric power grid operator and utility customers based on market rules on a periodic basis. We refer to measured and verified capacity as our demonstrated or proven capacity. Once demonstrated, the proven capacity amounts typically establish a baseline of capacity for each C&I 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 from us to our electric power grid operator or utility customer or an additional payment to us by such customer. Any refund payable by us would reduce our deferred revenues, but would not impact our previously recognized revenues. If there is a refund payment due to an electric power grid operator or utility customer, we generally make a corresponding adjustment in our payments to the C&I 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 can 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 such 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 to our electric power grid operator or utility customers, which could be substantial. We incurred aggregate net penalty payments of $288,527, $168,719 and $82,639 during the years ended December 31, 2010, 2009 and 2008, respectively.
Our ability to achieve our committed capacity depends on the performance of our C&I 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 electric power grid operator and utility customers.
The capacity level that we are able to achieve is dependent upon the ability of our C&I 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 C&I customers to perform when called upon by us. For example, the market rules applicable to ISO-NE’s forward capacity market, which went into effect in June 2010, are rigorous and may result in the failure by some of our C&I customers to make the appropriate levels of capacity available. In addition, if PJM dispatches a measurement and verification test and our C&I 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 C&I customers are unable to perform or perform at levels below which they agreed to perform, we may be 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 a C&I 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 C&I customers when those C&I 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.
If we fail to successfully educate existing and potential electric power grid operator and utility customers regarding the benefits of our energy management applications and services or a market otherwise fails to develop for those applications and services, our ability to sell our energy management applications and services and grow our business could be limited.
Our future success depends on commercial acceptance of our clean and intelligent energy management applications and services and our ability to enter into additional utility contracts and new open market bidding programs. We anticipate that revenues related to our demand response application and services will constitute a substantial majority of our revenues for the foreseeable future. The market for clean and intelligent energy management applications and services in general is relatively new. If we are unable to educate our potential customers about the advantages of our energy management applications and services over competing products and services, or our existing customers no longer rely on our energy management applications and services, our ability to sell our energy management applications and services will be limited. In addition, because the clean and intelligent energy management applications and services sector is rapidly evolving, 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 clean and intelligent energy management applications and services that address those needs. Further, we are subject to the risk that the current global economic and market conditions will result in lower overall demand for electricity in the United States and other markets that we are seeking to penetrate over the next few years.
Such a reduction in the demand for electricity could create a corresponding reduction in both supply- and demand-side resources being implemented by electric power grid operators and utilities. If the market for our energy management applications and services does not continue to develop, our ability to grow our business could be limited and we may not be able to maintain profitability.
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 clean and intelligent energy management applications and services.
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. However, we may become directly subject to the regulation of FERC to the extent we own, operate, or control generation used to make wholesale sales of power or provide ancillary services such as exporting power to the electric power grid as a short-term reserve resource. For example, our subsidiary, Celerity, is subject to direct regulation by FERC because Celerity exports power to the electric power grid for resale pursuant to a contract with SDG&E. In addition, in an order issued in January 2010, FERC clarified that when a demand response resource is used to provide ancillary services that involve a sale of electric energy or capacity for resale, or export power onto the electric power grid, such a transaction may be subject to direct regulation by FERC. Although we do not expect FERC’s determination that it has jurisdiction over such activity to have a material adverse effect on our consolidated financial condition, results of operations or cash flows, we may become subject to other new or modified government regulations that could have a material adverse effect on our results of operation and financial condition.
The installation of devices used in providing our services and electric generators sometimes installed or activated when providing our demand response services may be subject to governmental oversight and regulation under state and local ordinances relating to building codes, public safety regulations pertaining to electrical connections, security protocols, and local and state licensing requirements. In a relatively few instances, we have agreed to own and operate a back-up generator at a C&I customer site for a period of time and to activate the generator when capacity is called for dispatch so that the C&I customer can reduce its consumption of electricity from the electric power grid. These generators are ineligible to participate in demand response programs in certain regions, and in others they may become ineligible to participate in the future or may be compensated less for such participation, thereby reducing our revenues and adversely affecting our financial condition. In addition, certain of our utility contracts and expansion of existing utility contracts are subject to approval by federal, state, provincial or local 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 or local 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 energy management applications and services, 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 energy management applications and services.
The expiration of our existing utility contracts without obtaining renewal or replacement 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 electric power grid operator and utility customers in different geographic regions in the United States, as well as in Canada and the United Kingdom, and are regularly in discussions to enter into new utility contracts with electric power grid operators and utilities. 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.
An increased rate of terminations by our C&I 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 C&I customer base.
Our ability to provide demand response capacity under our utility contracts and in open market bidding programs depends on the amount of MW that we manage across C&I customers who enter into contracts with us to reduce electricity consumption on demand. If our existing C&I customers do not renew their contracts as they expire, we will need to acquire MW from additional C&I customers or expand our relationships with existing C&I customers in order to maintain our revenues and grow our business. The loss of revenues resulting from C&I customer contract terminations could be significant, and limiting C&I customer terminations is an important factor in our ability to maintain profitability. If we are unsuccessful in limiting our C&I customer terminations, we may be unable to acquire a sufficient amount of MW or we may incur significant costs to replace MW in our portfolio, 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 C&I customers for making capacity available, which could adversely affect our results of operations and financial condition.
The rapid growth of the clean and intelligent energy management applications and services sector is resulting in increasingly aggressive pricing, which could cause the prices in that sector to decrease over time. Our electric power grid operator and utility customers may switch to other clean and intelligent energy management applications and services providers based on price, particularly if they perceive the quality of our competitors’ products or services to be equal or superior to ours. Continued decreases in the price of demand response capacity by our competitors could result in a loss of electric power grid operator and utility customers 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. Continued increases in the percentage or fixed amount paid to C&I customers by our competitors for making capacity available could result in a loss of C&I 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 C&I 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.
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 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, 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 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 compete for personnel and advisors with other companies and other organizations, many of which are larger and have greater name recognition and financial and other resources than we do. If we are not able to hire, train and retain the necessary personnel, or if these managerial, operational, financial and reporting improvements are not implemented successfully, we could lose customers and revenues.
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 current and future utility
contracts and open market programs with grid operator and utility customers, current and future contracts with C&I 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, and the resulting demand for our energy management applications and services. However, these factors are uncertain. If our assumptions regarding these factors prove to be incorrect or if alternatives to those offered by our energy management applications and services gain further acceptance, then actual demand for our energy management applications and services could be significantly less than the demand we anticipate and we may not be able to sustain our revenue growth or maintain profitability.
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 posting financial assurances in order to enter into utility contracts and open market bidding programs with electric power grid operators and utilities, and marketing and product development of our energy management applications and services. Our capital requirements will depend on many factors, including the rate of our revenue and sales growth, our introduction of new energy management applications and services and enhancements to our existing energy management applications and services, 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, such as our acquisitions of Smallfoot and Zox in March 2010 and Global Energy and M2M in January 2011, which could require significant capital and could increase our capital expenditures related to future operation of the acquired business or technology. Because of our historical losses, we do not fit traditional credit lending criteria. Moreover, the financial turmoil affecting the banking system and financial markets in recent years has resulted in a reduction in the availability of credit in the credit markets, which could adversely affect our ability to obtain additional funding. We may not be able to obtain loans or additional capital on acceptable terms or at all.
We and one of our subsidiaries entered into a loan and security agreement with Silicon Valley Bank, or SVB, in August 2008, which was subsequently amended and which we refer to as the SVB credit facility. The SVB credit facility contains restrictions on our ability to incur additional indebtedness, which, if not waived, could prevent us from obtaining needed capital. Any future credit facilities would likely contain similar restrictions. In the event additional funding is required, we may not be able to obtain bank credit arrangements or effect an equity or debt financing on terms acceptable to us or at all. A failure to obtain additional financing when needed could adversely affect our ability to maintain and grow our business.
The SVB credit facility contains financial and operating restrictions that may limit our access to credit. If we fail to comply with covenants in the SVB credit facility, we may be required to repay our indebtedness thereunder, which may have an adverse effect on our liquidity.
Provisions in the SVB credit facility impose restrictions on our ability to, among other things:
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incur additional indebtedness;
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create liens;
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enter into transactions with affiliates;
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transfer assets;
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pay dividends or make distributions on, or repurchase, EnerNOC stock; or
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merge or consolidate.
In addition, we are required to meet certain financial covenants customary with this type of credit facility, including maintaining a minimum specified tangible net worth and a minimum specified ratio of current assets to current liabilities. The SVB 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 SVB credit facility. In addition to preventing additional borrowings under the SVB credit facility, an event of default, if not cured or waived, may result in the acceleration of the maturity of indebtedness outstanding under the SVB credit facility, which would require us to pay all amounts outstanding. 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 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.
In addition, the SVB credit facility matures on March 31, 2011. In the event that we are unable to extend or renew the SVB credit facility and we still have letters of credit outstanding under the SVB credit facility when it matures on March 31, 2011, we will be required to post 105% of the value of the letters of credit in cash with SVB to collateralize those letters of credit. As of December 31, 2010, we were contingently liable for $36.6 million in connection with outstanding letters of credit under the SVB credit facility.
If we lose key personnel upon whom we are dependent, 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 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 energy management applications and services. We rely on our operations team to install, test, deliver and manage our energy management applications and services. We rely on our sales and marketing team to sell our energy management applications and services 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.
Failure of third parties to manufacture quality products or provide reliable services in a timely manner could cause delays in the delivery of our energy management applications and services, which could damage our reputation, cause us to lose customers and negatively impact our growth.
Our success depends on our ability to provide quality, reliable, and secure energy management applications and services in a timely manner, which in part requires the proper functioning of facilities and equipment owned, operated or manufactured by third parties upon which we depend. For example, our reliance on third parties includes:
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utilizing components that we or third parties install or have installed at C&I customer sites;
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outsourcing email notification and cellular and paging wireless communications that are used to notify our C&I customers of their need to reduce electricity consumption at a particular time and to execute instructions to devices installed at our C&I customer sites and which are programmed to automatically reduce consumption on receipt of such secure communications; and
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outsourcing certain installation and maintenance operations to third-party providers.
Any delays, malfunctions, inefficiencies or interruptions in these products, services or operations could adversely affect the reliability or operation of our energy management applications and services, which could cause us to experience difficulty monitoring or retaining current customers and attracting new customers. Such
delays could also result in our making refunds or paying penalty fees to our electric power grid operator and utility customers. In addition, our brand, reputation and growth could be negatively impacted.
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 clean and intelligent energy management applications and services. We hold two issued patents, 17 registered trademarks and numerous copyrights. 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. Moreover, some of our trademarks which are not in use may become available to others. 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 are not 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 energy management applications and services infringe on intellectual property held by others, which could result in the loss of use of those applications and services.
Third-party patent applications and patents may relate to our clean and intelligent energy management applications and services. 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 energy management applications and services, which litigation could be time-consuming and expensive, divert attention and resources away from our daily operations, impede or prevent delivery of our energy management applications and services, 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 energy management applications and services 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 at a reasonable cost, or at all.
If our information technology systems fail to adequately gather, assess and protect data used in providing our clean and intelligent energy management applications and services, 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 energy management applications and services, gather and assess data used in providing our energy management applications and services, 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:
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earthquake, fire, flood and other natural disasters;
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terrorist attacks and attacks by computer viruses or hackers;
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power loss; and
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computer systems, Internet, telecommunications or data network failure.
Any interruption in the operation of our information technology systems could result in decreased revenues under our contracts and commitments, reduced profit margins on revenues where fixed payments are due to our C&I 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.
Global economic and credit market conditions, and any associated impact on spending by electric power grid operators and utilities or on the continued operations of our C&I customers, could have a material adverse effect on our business, operating results, and financial condition.
Volatility and disruption in the global capital and credit markets in 2008, 2009 and 2010 have led to a significant reduction in the availability of business credit, decreased liquidity, a contraction of consumer credit, business failures, higher unemployment, and declines in consumer confidence and spending in the United States and internationally. If global economic and financial market conditions deteriorate or remain weak for an extended period of time, numerous economic and financial factors could have a material adverse effect on our business, operating results, and financial condition, including:
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decreased spending by electric power grid operators or utilities, or by end-users of electricity, may result in reduced demand for our clean and intelligent energy management applications and services;
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consumer demand for electricity may be reduced, which could result in lower prices for both demand-side and supply-side capacity pursuant to utility contracts and in open market programs with electric power grid operators and utilities;
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if C&I customers in our demand response network experience financial difficulty, some may cease or reduce business operations, or reduce their electricity usage, all of which could reduce the number of MW of demand response capacity under our management;
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we may be unable to find suitable investments that are safe, liquid, and provide a reasonable return, which could result in lower interest income or longer investment horizons, and disruptions to capital markets or the banking system may also impair the value of investments or bank deposits we currently consider safe or liquid;
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if our C&I customers to whom we provide our EfficiencySMART, SupplySMART or CarbonSMART applications and services experience financial difficulty, it could result in their inability to timely meet their payment obligations to us, extended payment terms, higher accounts receivable, reduced cash flows, greater expense associated with collection efforts, and an increase in charges for uncollectable receivables; and
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due to stricter lending standards, C&I customers to whom we offer our SupplySMART application and services may be unable to obtain adequate credit ratings acceptable to electricity suppliers, resulting in increased costs, which might make our SupplySMART application and services less attractive or result in their inability to contract with us for SupplySMART.
Uncertainty about current global economic conditions could also continue to increase the volatility of our stock price.
Electric power industry 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 electric power grid operator and utility customers are generally long and unpredictable. The electric power grid operators 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 energy management applications and services. Accordingly, our potential electric power grid operator and utility customers may take longer to reach a decision to purchase 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 electric power grid operator or utility customer to go through the entire sales process and not accept any proposal or quote. Long and unpredictable sales cycles with electric power grid operator and utility customers could have a material adverse effect on our business, financial condition and results of operations.
We may be subject to governmental or regulatory audits and may incur significant penalties and fines if found to be in non-compliance with any applicable State or Federal regulation.
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. However, regulations by FERC related to market design, market rules, tariffs, and bidding rules impact how we can interact with our electric power grid operator and utility customers. For example, our subsidiary Celerity exports some 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. In addition, to the extent our demand response resources are used to provide ancillary services that involve a sale of electric energy or capacity for resale, or the export of power onto the electric power grid, such activities are also subject to direct regulation by FERC. Despite our efforts to manage compliance with such regulations, we may be found to be in non-compliance with such regulations and therefore subject to penalties or fines, which could have a material adverse effect on our business, financial condition and results of operations.
In addition, we may be subject to governmental or regulatory audits from time to time as part of any governmental or regulatory entity conducting routine audits of the demand response programs in which we participate. For example, in December 2010 we received a letter from FERC advising us that FERC would be conducting an audit of us and our demand response and efficiency resources within the ISO-NE and New York ISO markets. The audit is being conducted as part of FERC’s annual audit plan to determine whether jurisdictional companies are in compliance with FERC’s statutes, orders, and rules and regulations. The audit will evaluate our compliance, as a market participant, with the tariffs applicable to the ISO-NE and New York ISO markets. As part of this and any 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. Accordingly, the audit by FERC or any similar audit 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. Moreover, if the FERC audit or any similar 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.
Any internal or external security breaches involving our energy management applications and services, and even the perception of security risks involving our energy management applications and services or the transmission of data over the Internet, whether or not valid, could harm our reputation and inhibit market acceptance of our energy management applications and services and cause us to lose customers.
We use our energy management applications and services to compile and analyze sensitive or confidential information related to our customers. In addition, some of our energy management applications and services allow us to remotely control equipment at C&I customer sites. Our energy management applications and services rely on the secure transmission of proprietary data over the Internet for some of this functionality.
Well-publicized compromises of Internet security 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 energy management applications and services or our customers’ concerns about Internet security or the security of our energy management applications and services, whether or not they are warranted, could have a material adverse effect on our business, harm our reputation, inhibit market acceptance of our energy management applications and services and cause us to lose customers, any of which could have a material adverse effect on our financial condition and results of operations.
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 energy management applications and services, 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.
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, 2010 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 attest in a timely manner to our evaluation, 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 electric power grid operators and utilities.
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 electric power grid operator and utility customers. In addition, some of our electric power grid operator or utility customers 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, 2010, we had $36.6 million of letters of credit outstanding under the SVB credit facility, leaving $13.4 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. For example, because we had no additional credit available under the SVB credit facility in May 2009, we entered into a credit arrangement with a third-party in connection with bidding capacity into a certain open market bidding program. The arrangement included an up-front payment of $2.0 million, and we will be required to pay the third party an additional contingent fee, up to a maximum of $3.0 million, based on the revenue that we expect to earn and recognize in 2012 in connection with the bid. 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, if we earn net taxable income, our ability to use our pre-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.
If the software we use in providing our energy management applications and services produces inaccurate information or is incompatible with the systems used by our customers, it could preclude us from providing our energy management applications and services, 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 a C&I customer site, which could cause us to fail to meet our commitments to have capacity available. Any such failures could 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 energy management applications and services, 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 a C&I 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 energy management applications and services need to interface with these non-standard systems in order to gather and assess data and to implement changes in electricity consumption. Our business depends on the following factors, among others:
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our ability to integrate our technology with new and existing hardware and software systems, including metering, building control, process control, and distributed generation systems;
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our ability to anticipate and support new standards, especially Internet-based standards and building control and metering system protocol languages; and
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our ability to integrate additional software modules under development with our existing technology and operational processes.
If we are unable to adequately address any of these factors, our results of operations and prospects for growth could be materially adversely effected.
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 C&I 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 maintain sales and service offices outside the United States. The expenses of our international offices are denominated in local currencies. In addition, our foreign sales may be denominated in local currencies. Fluctuations in foreign currency exchange rates could affect our revenues, cost of revenues and profit margins and could result in exchange losses. In addition, currency devaluation can result in a loss if we hold deposits of that currency. 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.
Risks Related to Our Common Stock
We expect our quarterly revenues and operating results to fluctuate. If we fail to meet 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. Our revenues and operating results may fall below the expectations of securities analysts or investors in some future quarter or quarters. Our failure to meet these expectations could cause the market price of our common stock to decline substantially.
Our quarterly revenues and operating results may vary depending on a number of factors, including:
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demand for and acceptance of our clean and intelligent energy management applications and services;
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the seasonality of our demand response business in certain of the markets in which we operate, where revenues recognized under certain utility contracts and pursuant to certain open market bidding programs can be higher or concentrated in particular seasons and months;
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changes in open market bidding program rules and reductions in pricing for demand response capacity;
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delays in the implementation and delivery of our clean and intelligent energy management applications and services, which may impact the timing of our recognition of revenues;
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delays or reductions in spending for clean and intelligent energy management applications and services by our electric power grid operator or utility customers and potential customers;
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the long lead time associated with securing new customer contracts;
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the structure of any forward capacity market in which we participate, which may impact the timing of our recognition of revenues related to that market;
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the mix of our revenues during any period, particularly on a regional basis, since local fees recognized as revenues for demand response capacity tend to vary according to the level of available capacity in given regions;
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the termination or expiration of existing contracts with electric power grid operator and utility customers and C&I customers;
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the potential interruptions of our customers’ operations;
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development of new relationships and maintenance and enhancement of existing relationships with customers and strategic partners;
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temporary capacity programs that could be implemented by electric power grid operators and utilities to address short-term capacity deficiencies;
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the imposition of penalties or the reversal of deferred revenue due to our failure to meet a capacity commitment;
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flaws in the design or the elimination or modification of any demand response program in which we participate;
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global economic and credit market conditions; and
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increased expenditures for sales and marketing, software development and other corporate activities.
Our stock price has been and is likely to continue to be volatile and the market price of our common stock may fluctuate substantially.
Prior to our IPO, there was not a public market for our common stock. There is a limited history on which to gauge the volatility of our stock price; however, since our common stock began trading on The NASDAQ Global Market, or NASDAQ, on May 18, 2007 through December 31, 2010, our stock price has fluctuated from a low of $4.80 to a high of $50.50. Furthermore, the stock market has recently experienced significant volatility. The volatility of stocks for companies in the energy and technology industry often does not relate to the operating performance of the companies represented by the stock. Some of the factors that may cause the market price of our common stock to fluctuate include:
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demand for and acceptance of our clean and intelligent energy management applications and services;
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our ability to develop new relationships and maintain and enhance existing relationships with customers and strategic partners;
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changes in open market bidding program rules and reductions in pricing for demand response capacity;
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the termination or expiration of existing contracts with electric power grid operator and utility customers and C&I customers;
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general market conditions and overall fluctuations in equity markets in the United States;
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flaws in the design or the elimination or modification of any demand response program in which we participate;
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introduction of technological innovations or new energy management applications or services by us or our competitors;
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changes in estimates or recommendations by securities analysts that cover our common stock;
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delays in the implementation and delivery of our clean and intelligent energy management applications and services, which may impact the timing of our recognition of revenues;
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litigation or regulatory enforcement actions;
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changes in the regulations affecting our industry in the United States and internationally;
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the way in which we recognize revenues and the timing associated with our recognition of revenues;
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developments or disputes concerning patents or other proprietary rights;
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period-to-period fluctuations in our financial results;
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the potential interruptions of our customers’ operations;
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the seasonality of our demand response business in certain of the markets in which we operate;
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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; and
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economic and other external factors or other disasters or crises.
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, we believe due in large part to the PJM statement. Although as of the date of filing of this Annual Report on Form 10-K we have not received notice of any lawsuit brought against us by any of our stockholders, we are aware that several plantiffs’ law firms have announced that they are investigating securities claims against us. While we would vigorously defend any such lawsuit, we could incur substantial costs defending any such lawsuit. Such a lawsuit could also divert the time and attention of our management.
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 SVB 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.
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 not have the opportunity to do so. Furthermore, these provisions could prevent or frustrate attempts by our stockholders to replace or remove our management. These provisions:
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allow the authorized number of directors to be changed only by resolution of our board of directors;
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require that vacancies on the board of directors, including newly created directorships, be filled only by a majority vote of directors then in office;
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establish a classified board of directors, providing that not all members of the board be elected at one time;
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authorize our board of directors to issue, without stockholder approval, blank check preferred stock that, if issued, could operate as a “poison pill” to dilute the stock ownership of a potential hostile acquirer to prevent an acquisition that is not approved by our board of directors;
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require that stockholder actions must be effected at a duly called stockholder meeting and prohibit stockholder action by written consent;
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prohibit cumulative voting in the election of directors, which would otherwise allow holders of less than a majority of stock to elect some directors;
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establish advance notice requirements for stockholder nominations to our board of directors or for stockholder proposals that can be acted on at stockholder meetings;
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limit who may call stockholder meetings; and
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require the approval of the holders of 75% of the outstanding shares of our capital stock entitled to vote in order to amend certain provisions of our certificate of incorporation and bylaws.
Some of our employment arrangements and equity agreements provide for severance payments and accelerated vesting of benefits, including accelerated vesting of equity awards, upon a change of control. These provisions may discourage or prevent a change of control. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law, which may, unless certain criteria are met, prohibit large stockholders, in particular those owning 15% or more of our outstanding voting stock, from merging or combining with us for a proscribed period of time.
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 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 NASDAQ, 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.
Item 1B.
Unresolved Staff Comments
Not applicable.
Item 2.
Item 2.
Properties
Our corporate headquarters and principal office is located in Boston, Massachusetts, where we lease approximately 57,034 square feet under a lease agreement expiring in June 2014. We also lease approximately 8,766 square feet in San Francisco, California under a sublease agreement expiring in February 2012 and approximately 6,603 square feet in New York, New York under a lease agreement expiring in December 2011. We also lease a number of offices under various other lease agreements in the United States, Canada and the United Kingdom. We do not own any real property. We believe that our leased facilities will be adequate to meet our needs for the foreseeable future.
Item 3.
Item 3.
Legal Proceedings
We are subject to legal proceedings, claims and litigation arising in the ordinary course of business. We do not expect the ultimate costs to resolve these matters to have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
Item 4.
Item 4.
[Removed and Reserved]
PART II
Item 5.
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.
Stockholders
As of February 24, 2011, we had approximately 372 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. The terms of the SVB 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
None.
Item 6.
Item 6.
Selected Financial Data
Our selected consolidated financial data set forth below is derived from our audited financial statements 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
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 clean and intelligent energy management applications and services for the smart grid, which include comprehensive demand response, data-driven energy efficiency, energy price and risk management, and enterprise carbon management applications and services. Our energy management applications and services enable cost effective energy management strategies for our C&I customers and our electric power grid operator and utility customers by reducing real-time demand for electricity, increasing energy efficiency, improving energy supply transparency, and mitigating emissions.
We use our Network Operations Center, or NOC, and comprehensive demand response application, DemandSMART, to remotely manage and reduce electricity consumption across a growing network of C&I customer sites, making demand response capacity available to electric power grid operators and utilities on demand while helping C&I customers achieve energy savings, improved financial results and environmental benefits. As of December 31, 2010, we managed over 5,300 MW of demand response capacity across a C&I customer base of approximately 3,600 accounts and 8,600 sites throughout multiple electric power grids.
We build on our position as a leading demand response services provider by using our NOC and energy management application platform to deliver a portfolio of additional energy management applications and services to new and existing C&I, electric power grid operator and utility customers. These additional energy management applications and services include our EfficiencySMART, SupplySMART and CarbonSMART applications and services.
Since inception, our business has grown substantially. We began by providing demand response services in one state in 2003 and had expanded to providing our portfolio of energy management applications and services in several regions throughout the United States, as well as internationally in Canada and the United Kingdom by December 31, 2010.
Significant Recent Developments
In February 2011, we and Darren Brady, our then-current senior vice president and chief operating officer, agreed that Mr. Brady would resign as senior vice president and chief operating officer effective February 11, 2011.
In January 2011, we acquired M2M pursuant to an agreement and plan of merger, which we refer to as the M2M merger agreement. M2M is a leading provider of wireless technology solutions for energy management and demand response. The total merger consideration paid by us at closing was $30.0 million, plus an additional $3.3 million paid as a result of M2M having a positive capitalization amount at closing, of which $15.0 million was paid in shares of our common stock and the balance of which was paid in cash. An aggregate of $7.0 million of the merger consideration, consisting of cash and shares of our common stock, was retained by us and will be paid to the stockholders of M2M upon the satisfaction of certain conditions contained in the M2M merger agreement.
In January 2011, we also acquired all of the outstanding capital stock of Global Energy, a provider of energy efficiency and demand response programmatic solutions and innovative technology applications. The total purchase price paid by us at closing was $26.5 million, of which $6.6 million was paid in shares of our common stock and the balance of which was paid in cash.
In December 2010 and June 2010, each of James Turner and Adam Grosser, respectively, resigned from our board of directors. In February 2010, Dr. Susan F. Tierney was elected to serve as a member of our board of directors.
In April 2010, we and one of our subsidiaries entered into a second loan modification agreement to the SVB credit facility, which increased our borrowing limit from $35.0 million to $50.0 million, as well as modified certain of our financial covenant debt compliance requirements. We and SVB further modified the SVB credit facility in July 2010 and February 2011 to, among other things, extend the maturity date of the SVB credit facility through March 31, 2011.
In March 2010, we acquired substantially all of the assets and certain liabilities of Smallfoot and Zox. Smallfoot was in the process of developing wireless systems that manage and coordinate electricity demand for small commercial facilities and Zox was in the process of developing hardware and software for automated utility meter reading. The purchase price for these acquisitions was equal to approximately $1.4 million, of which $0.3 million was paid in shares of our common stock and the balance of which was paid in cash.
Revenues and Expense Components
Revenues
We derive recurring revenues from the sale of our energy management applications and services. 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 revenues from our demand response services primarily consist of capacity and energy payments, including ancillary services payments. We derive revenues from demand response capacity that we make 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 grid operators and utilities, generally ranging from three to 10 years in duration, to deploy our demand response services. We refer to these contracts as utility contracts.
Where we operate in open market programs, our revenues from demand response capacity payments may vary month-to-month based upon our enrolled capacity and the market payment rate. Where we have a utility contract, we receive periodic capacity payments, which may vary monthly or seasonally, based upon enrolled capacity and predetermined payment rates. Under both open market programs and utility contracts, we receive capacity payments regardless of whether we are called upon to reduce demand for electricity from the electric power grid, and we recognize revenue over the applicable delivery period, even where payments are made over a different period. We generally demonstrate our capacity either through a demand response event or a measurement and verification test. This demonstrated capacity is typically used to calculate the continuing periodic capacity payments to be made to us until the next demand response event or measurement and verification test establishes a new demonstrated capacity amount. In most cases, we also receive an additional payment for the amount of energy usage that we actually curtail from the grid during a demand response event. We refer to this as an energy payment.
As program rules may differ for each open market program in which we participate and for each utility contract, we assess whether or not we have met the specific service requirements under the program rules and recognize or defer revenues as necessary. We recognize demand response capacity revenues when we have provided verification to the electric power grid operator or utility of our ability to deliver the committed capacity under the open market program or utility contract. Committed capacity is verified through the results of an actual demand response event or a measurement and verification test. Once the capacity amount has been verified, the revenues are recognized and future revenues become fixed or determinable and are recognized monthly over the performance period until the next demand response event or measurement and verification test. In subsequent demand response events or measurement and verification tests, if our verified capacity is below the previously verified amount, the electric power grid operator or utility customer will reduce future payments based on the adjusted verified capacity amounts. Under certain utility contracts and open market program participation rules, our performance and related fees are measured and determined over
a period of time. If we can reliably estimate our performance for the applicable performance period, we will reserve the entire amount of estimated penalties that will be incurred, if any, as a result of estimated underperformance prior to the commencement of revenue recognition. If we are unable to reliably estimate the performance and any related penalties, we defer the recognition of revenues until the fee is fixed or determinable. Any changes to our original estimates of net revenues are recognized as a change in accounting estimate in the earliest reporting period that such a change is determined.
We defer incremental direct 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, 2010 and 2009, the incremental direct costs deferred were approximately $0.9 million and $0.9 million, respectively. These deferred expenses would not have been incurred without our participation in a certain open market program and will be expensed in proportion to the related revenue being recognized. During the years ended December 31, 2010, 2009 and 2008, we deferred contract origination costs of approximately $0.0 million, $0.8 million and $0.1 million, respectively. In addition, we capitalize the costs of our production and generation equipment utilized in the delivery of our demand response services and expense this equipment over the lesser of its useful life or the term of the contractual arrangement. These capitalized costs of $8.9 million and $9.0 million at December 31, 2010 and 2009, respectively, are included in property and equipment in our consolidated balance sheets. We believe that this accounting treatment appropriately matches expenses with the associated revenue.
As of December 31, 2010, we had over 5,300 MW under management in our demand response network, meaning that we had entered into definitive contracts with our C&I customers representing over 5,300 MW of demand response capacity. We generally begin earning revenues from our MW under management within approximately one month from the date on which we enable the MW, or the date on which we can reduce the MW from the electricity grid if called upon to do so. The most significant exception is the PJM forward capacity market, which is a market from which we derive a substantial portion of our revenues. Because PJM operates on a June to May program-year basis, a MW that we enable after June of each year may not begin earning revenue until June of the following year. This results in a longer average revenue recognition lag time in our C&I customer portfolio from the point in time when we consider a MW to be under management to when we earn revenues from that MW. Certain other markets in which we currently participate, such as the ISO-NE market, or choose to participate in the future operate or may operate in a manner that could create a delay in recognizing revenue from the MW that we enable in those markets. Additionally, not all of our MW under management may be enrolled in a demand response program or may earn revenue in a given program period or year based on the way that we manage our portfolio of demand response capacity.
Revenues generated from open market sales to PJM, a grid operator customer, accounted for 60%, 52% and 28%, respectively, of our total revenues for the years ended December 31, 2010, 2009 and 2008. Under certain utility contracts and open market programs, such as PJM’s Emergency Load Response Program, the period during which we are required to perform may be shorter than the period over which we receive payments under that contract or program. In these cases, we record revenue, net of reserves for estimated penalties related to potential delivered capacity shortfalls, over the mandatory performance obligation period, and a portion of the revenues that have been earned is recorded and accrued as unbilled revenue. Our unbilled revenue of $73.1 million as of December 31, 2010 will be billed and collected through May 31, 2011. Our unbilled revenue of $40.4 million as of December 31, 2009 was collected through May 31, 2009. Due to the lower pricing that will take effect in the PJM market in 2011 and 2012, as well as the discontinuance of the ILR program beginning in 2012 and an expected decrease in MW enrolled in the PJM market in 2012 as compared to 2011, we currently expect that our revenues derived from the PJM market will significantly decrease as a percentage of our total annual revenues in 2011 and 2012 as compared to prior years, and that our ability to grow our overall revenues in 2011 and 2012 at levels consistent with prior years will be negatively impacted. Had the lower pricing that will take effect in the PJM market beginning in 2011 been in effect during the year ended December 31, 2010, our revenues for that period would have been lower by approximately $50.0 million to $55.0 million. In addition and in connection with the PJM statement, in the event that FERC does not grant us declaratory relief, or agrees with the PJM statement and modifies the PJM market rules in the future to reflect the PJM statement, or to the extent PJM is otherwise successful at
modifying the market rules in the future, our revenues for 2011 and beyond could be significantly reduced, currently estimated to be in the range of $15.0 million to $32.0 million; however, the ultimate financial impact could deviate from this range and will depend on several factors, including the details of any modified market rule or FERC ruling and the associated timing and market impact of any such rule or ruling.
Revenues generated from open market sales to ISO-NE, a grid operator customer, accounted for 18%, 29% and 36%, respectively, of our total revenues for the years ended December 31, 2010, 2009 and 2008.
In addition to demand response revenues, we generally receive either a subscription-based fee, consulting fee or a percentage savings fee for arrangements under which we provide our other energy management applications and services, specifically our EfficiencySMART, SupplySMART and CarbonSMART applications and services. Revenues derived from our EfficiencySMART, SupplySMART and CarbonSMART applications and services were $15.5 million, $6.8 million and $6.7 million, respectively, for the years ended December 31, 2010, 2009 and 2008.
Our revenues have historically been higher in our second and third fiscal quarters compared to other quarters in our fiscal year due to seasonality related to the demand response market.
Cost of Revenues
Cost of revenues for our demand response services consists primarily of amounts owed to our C&I customers for their participation in our demand response network and are generally recognized over the same performance period as the corresponding revenue. We enter into contracts with our C&I customers under which we deliver recurring cash payments to them for the capacity they commit to make available on demand. We also generally make an additional payment when a C&I customer reduces consumption of energy from the electric power grid during a demand response event. The equipment and installation costs for our devices located at our C&I customer sites, which monitor energy usage, communicate with C&I customer sites and, in certain instances, remotely control energy usage to achieve committed capacity are capitalized and depreciated over the lesser of the remaining estimated customer relationship period or the estimated useful life of the equipment, and this depreciation is reflected in cost of revenues. We also include in cost of revenues our amortization of capitalized internal-use software costs related to our DemandSMART application, the monthly telecommunications and data costs we incur as a result of being connected to C&I customer sites and our internal payroll and related costs allocated to a C&I customer site. 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 described below during interim periods. Cost of revenues for our EfficiencySMART, SupplySMART and CarbonSMART applications and services include our amortization of capitalized internal-use software costs related to those applications and services, third party services, equipment depreciation and the wages and associated benefits that we pay to our project managers for the performance of their services.
Gross Profit and Gross Margin
Gross profit consists of our total revenues less our cost of revenues. Our gross profit has been, and will be, affected by many factors, including (a) the demand for our energy management applications and services, (b) the selling price of our energy management applications and services, (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 clean and intelligent energy management applications and services, (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. Our outcomes in negotiating favorable contracts with our C&I customers, as well as with our electric power grid operator and utility customers, the effective management of our portfolio of demand response capacity and our demand response event performance are the primary determinants of our gross profit and gross margin.
Operating Expenses
Operating expenses consist of selling and marketing, general and administrative, and research and development expenses. Personnel-related costs are the most significant component of each of these expense categories. We grew from 418 full-time employees at December 31, 2009 to 484 full-time employees at December 31, 2010. 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 MW under our management, which we expect to continue for the foreseeable future. Although we expect our overall operating expenses to increase in absolute dollar terms for the foreseeable future as we grow our MW under management, further increase our headcount and expand the development of our energy management applications and services, we expect our overall annual operating expenses to decrease as a percentage of total annual revenues as we leverage our existing employee base and continue generating revenues from our energy management applications and services.
Selling and Marketing
Selling and marketing expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our sales and marketing organization, (b) commissions, (c) travel, lodging 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 increases in selling and marketing expenses in absolute dollar terms for the foreseeable future as we further increase the number of sales professionals and, to a lesser extent, increase our marketing activities. We expect annual selling and marketing expenses to decrease as a percentage of total annual revenues as we leverage our current sales and marketing personnel.
General and Administrative
General and administrative expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards and bonuses, related to our executive, finance, human resource, information technology and operations organizations, (b) facilities expenses, (c) accounting and legal professional fees, (d) depreciation and amortization and (e) other related overhead. We expect general and administrative expenses to continue to increase in absolute dollar terms for the foreseeable future as we invest in infrastructure to support our continued growth. We expect general and administrative expenses to decrease as a percentage of total annual revenues as we leverage our current infrastructure and employee base. However, amortization expense from intangible assets acquired in future acquisitions could potentially increase our general and administrative expenses in future periods.
Research and Development
Research and development expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our research and development organization, (b) payments to suppliers for design and consulting services, (c) costs relating to the design and development of new energy management applications and services and enhancement of existing energy management applications and services, (d) quality assurance and testing and (e) other related overhead. During the years ended December 31, 2010, 2009 and 2008, we capitalized internal software development costs of $6.8 million, $4.2 million and $3.2 million, respectively, and the amount is included as software in property and equipment at December 31, 2010. We capitalized $1.3 million and $1.5 million during the years ended December 31, 2010 and 2009, respectively, related to a company-wide enterprise resource planning systems implementation project. We expect research and development expenses to increase in absolute dollar terms for the foreseeable future as we develop new technologies and to decrease as a percentage of total revenues in the long term as we leverage our existing technology.
Stock-Based Compensation
We account for stock-based compensation in accordance with Accounting Standards Codification, or ASC, 718, Stock Compensation. As such, all share-based payments to employees, including grants of stock options, restricted stock and restricted stock units, are recognized in the statement of operations based on their fair values as of the date of grant. For stock options granted prior to January 1, 2009, the fair value for these options was estimated at the date of grant using a Black-Scholes option-pricing model, and for stock options granted on or after January 1, 2009, the fair value of each award is estimated on the date of grant using a lattice valuation model. For the years ended December 31, 2010, 2009 and 2008, we recorded expenses of approximately $15.7 million, $13.1 million and $10.4 million, respectively, in connection with share-based payment awards to employees and non-employees. With respect to option grants through December 31, 2010, a future expense of non-vested options of approximately $11.0 million is expected to be recognized over a weighted average period of 2.3 years. With respect to restricted stock and restricted stock units issued through December 31, 2010, a future expense of unvested restricted stock and restricted stock unit awards of approximately $14.4 million is expected to be recognized over a weighted average period of 2.7 years.
Other Income and Expense, Net
Other income and expense consist primarily of interest income earned on cash balances, gain or loss on transactions designated in currencies other than our or our subsidiaries’ functional currency and other non-operating income. We historically have invested our cash in money market funds, treasury funds, commercial paper, municipal bonds and auction rate securities. We do not currently hold any auction rate securities.
Interest Expense
Interest expense consists of interest on our capital lease obligations, fees associated with the SVB credit facility, and fees associated with issuing letters of credit and other financial assurances.
Consolidated Results of Operations
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Revenues
The following table summarizes our revenues for the years ended December 31, 2010 and 2009 (dollars in thousands):
For the year ended December 31, 2010, our demand response revenues increased by $80.7 million, or 44%, as compared to the year ended December 31, 2009. The increase in our demand response revenues was
primarily attributable to changes in our MW under management in the following existing operating areas (dollars in thousands):
(1)
The amounts included in this category relate to increases in various demand response programs, none of which are individually material.
In addition to an increase in our MW under management, the increase in our demand response revenues for the year ended December 31, 2010 compared to the same period in 2009 was also attributable to the effective management of our portfolio of demand response capacity and more favorable pricing in certain operating areas. Additionally, approximately 10% of the increase in demand response revenues was attributable to an increase in energy payment revenues due to more demand response events occurring in 2010 as compared to 2009. These increases were offset by the commencement of a new ISO-NE program, which started on June 1, 2010, under which we enrolled fewer MW with lower pricing compared to a prior, similar ISO-NE program in which we participated.
For the year ended December 31, 2010, our EfficiencySMART, SupplySMART and CarbonSMART applications and services revenues increased by $8.7 million as compared to the year ended December 31, 2009 primarily due to our acquisition of Cogent, a company specializing in comprehensive energy consulting, engineering and building commissioning solutions to C&I customers, which occurred in December 2009.
We currently expect our revenues to increase slightly for the year ending December 31, 2011 as compared to the same period in 2010 as we further increase our MW under management in all operating regions, enroll new C&I customers in our demand response programs, expand the sales of our EfficiencySMART, SupplySMART and CarbonSMART applications and services to our new and existing C&I customers and pursue more favorable pricing opportunities with our C&I customers. Although we expect an increase in our MW under management in the PJM market in 2011 as compared to 2010, until PJM prices return in 2013 to more historical levels, we expect our revenues derived from the PJM market to decrease as a percentage of total annual revenues in 2011 and 2012 as significantly lower capacity prices in this market take effect for those years. These lower prices in PJM will negatively impact our ability to grow our overall revenues in 2011 and 2012 at levels consistent with prior years. For example, had the lower pricing that will take effect in the PJM market beginning in 2011 been in effect during the year ended December 31, 2010, our revenues for that period would have been lower by approximately $50.0 million to $55.0 million.
In addition, the discontinuance of the ILR program by PJM beginning in 2012 will reduce the flexibility that we currently have to manage our portfolio of demand response capacity in the PJM market and will negatively impact our future revenues. We also expect a decrease in MW enrolled in the PJM market in 2012 as compared to 2011, which could also negatively impact our revenues in 2012. In connection with the PJM statement, in the event that FERC does not grant us declaratory relief, or agrees with the PJM statement and modifies the PJM market rules in the future to reflect the PJM statement, or to the extent PJM is otherwise successful at modifying the market rules in the future, our revenues for 2011 and beyond could be significantly reduced, currently estimated to be in the range of $15.0 million to $32.0 million; however, the ultimate financial impact could deviate from this range and will depend on several factors, including the details of any modified market rule or FERC ruling and the associated timing and market impact of any such rule or ruling.
Gross Profit and Gross Margin
The following table summarizes our gross profit and gross margin percentages for our energy management applications and services for the years ended December 31, 2010 and 2009 (dollars in thousands):
Our gross profit increased during the year ended December 31, 2010 as compared to the same period in 2009 primarily due to the substantial increase in our revenues, as well as the effective management of our portfolio of demand response capacity and strong demand response event performance, particularly in the PJM region from which we currently derive a substantial portion of our revenues.
Our gross margin decreased during the year ended December 31, 2010 as compared to the same period in 2009 primarily due to lower prices in the ISO-NE market, an increase in cost of revenues in a certain demand response program where the associated revenues were deferred and recognition of certain project start-up costs related to an enterprise energy management arrangement pursuant to which revenue recognition has not yet commenced. Additionally, our gross margin decreased during the year ended December 31, 2010 as compared to the same period in 2009 due to increased depreciation and amortization of capitalized costs and an impairment charge of $1.6 million recognized during the year ended December 31, 2010 related to certain demand response and back-up generator equipment.
We currently expect that our gross margin for the year ending December 31, 2011 will be similar to our gross margin for the year ended December 31, 2010, and that our gross margin for the three months ending September 30, 2011 will be the highest gross margin among our four quarterly reporting periods in 2011, consistent with our gross margin pattern in 2010, due to seasonality related to the demand response market. In addition, until the prices in the PJM market improve in 2013, we expect the lower capacity prices that will take effect in the PJM market in 2011 and 2012 to negatively impact our ability to grow our overall gross profits and gross margins in 2011 and 2012 at levels consistent with prior years. Moreover, the discontinuance of the ILR program by PJM beginning in 2012 will reduce the flexibility that we currently have to manage our portfolio of demand response capacity in the PJM market and will negatively impact our future gross profits and gross margins. We also expect a decrease in MW enrolled in the PJM market in 2012 as compared to 2011, which could also negatively impact our gross profits and gross margins in 2012. In connection with the PJM statement, in the event that FERC does not grant us declaratory relief, or agrees with the PJM statement and modifies the PJM market rules in the future to reflect the PJM statement, or to the extent PJM is otherwise successful at modifying the market rules in the future, our gross profits for 2011 and beyond could be further reduced and our gross margins for the same period could be negatively impacted.
Operating Expenses
The following table summarizes our operating expenses for the years ended December 31, 2010 and 2009 (dollars in thousands):
In certain forward capacity markets in which we choose to participate, such as PJM, we may enable our C&I customers, meaning we may install our equipment at a C&I customer site to allow for the curtailment of
MW from the electric power grid, up to twelve months in advance of enrolling the C&I customer in a particular program. This market feature creates a longer average revenue recognition lag time across our C&I customer portfolio from the point in time when we consider a MW to be under management to when we earn revenues from that MW. Because we incur operational expenses, including salaries and related personnel costs, at the time of enablement, there has been a trend of incurring operating expenses associated with enabling our C&I customers in advance of recognizing the corresponding revenues.
Selling and Marketing Expenses
The increase in selling and marketing expenses for the year ended December 31, 2010 compared to the same period in 2009 was primarily driven by the payroll and related costs associated with an increase in the number of selling and marketing full-time employees from 146 at December 31, 2009 to 193 at December 31, 2010. The increase in payroll and related costs for the year ended December 31, 2010 compared to the same period in 2009 was also attributable to an increase in sales commissions payable to certain members of our sales organization of $1.3 million, as well as the timing associated with our hiring new full-time employees during 2010 as compared to 2009. These increases were offset by a decrease in salary rates per full-time employee. The increase in stock-based compensation for the year ended December 31, 2010 compared to the same period in 2009 was primarily due to annual stock-based awards granted to an officer and costs related to equity awards granted to certain existing and newly-hired employees. The increase in other selling and marketing expenses for the year ended December 31, 2010 as compared to the same period in 2009 was attributable to increases in professional services and marketing costs of $0.6 million due to our rebranding efforts, attendance at conferences and seminars, and costs associated with third-party marketing personnel. Additionally, we allocated company-wide costs to selling and marketing expenses based on headcount, which resulted in an increase in facility costs of $0.3 million due to the expansion of our existing office space and technology and communication costs of $0.5 million due to the increased utilization in our data service centers.
General and Administrative Expenses
The increase in general and administrative expenses for the year ended December 31, 2010 compared to the same period in 2009 was primarily driven by payroll and related costs due to an increase in executive compensation. The increase in payroll and related costs for the year ended December 31, 2010 compared to the same period in 2009 was also attributable to an increase in full-time employees from 223 at December 31, 2009 to 233 at December 31, 2010. The increase in stock-based compensation for the year ended December 31, 2010 compared to the same period in 2009 was primarily due to annual stock-based awards granted to our officers and directors. The increase in other general and administrative expenses for the year ended December 31, 2010 compared to the same period in 2009 was attributable to an increase in professional services fees of $1.3 million primarily due to increased legal and accounting, audit and tax fees, as well as
facility costs of $0.4 million primarily related to increased rent expense due to the expansion of our office space. Additionally, we allocated company-wide costs to general and administrative expenses based on headcount, which resulted in a $0.4 million increase of other miscellaneous expenses associated with the growth of our business.
Research and Development Expenses
The increase in research and development expenses for the year ended December 31, 2010 compared to the same period in 2009 was primarily driven by the costs associated with an increase in the number of research and development full-time employees from 49 at December 31, 2009 to 58 at December 31, 2010. The increase in research and development expenses for the year ended December 31, 2010 compared to the same period in 2009 was also attributable to lower capitalized internal payroll and related costs of $0.3 million. The increase in stock-based compensation for the year ended December 31, 2010 compared to the same period in 2009 was primarily due to stock-based awards granted to certain employees in connection with our acquisition of Smallfoot and Zox in March 2010. The increase in other research and development expenses for the year ended December 31, 2010 compared to the same period in 2009 was primarily related to a $0.6 million increase in technology and communications related to software licenses and fees used in the development of our energy management applications and $0.5 million related to professional services fees for consulting services associated with the development of our energy management applications. Additionally, we allocated company-wide costs to research and development expenses based on headcount, which resulted in a decrease of $0.1 million related to facility costs.
Other (Expense) Income, Net
Other expense, net for the year ended December 31, 2010 was $0.1 million as compared to other income, net of $0.1 million for the year ended December 31, 2009. Other expense, net for the year ended December 31, 2010 was comprised of a nominal amount of interest income due to the nominal rate of returns on our available cash and was offset by net nominal foreign currency losses in 2010. Other income, net for the year ended December 31, 2009 was comprised of a nominal amount of interest income, as well as net nominal foreign currency gains in 2009.
Interest Expense
The decrease in interest expense for the year ended December 31, 2010 compared to the same period in 2009 was due to our repayment of outstanding borrowings under the SVB credit facility of $4.4 million during the three months ended December 31, 2009, resulting in no interest expense related to any borrowings under the SVB credit facility during the year ended December 31, 2010. Additionally, the decrease in interest expense for the year ended December 31, 2010 compared to the same period in 2009 was due to $1.1 million in fees incurred during the year ended December 31, 2009 associated with outstanding letters of credit, primarily attributable to the arrangement we entered into with a third party in May 2009 in connection with bidding capacity into a certain open market program. Interest expense for the year ended December 31, 2010 included interest on our outstanding capital leases and letters of credit origination fees.
Income Taxes
We recorded a provision for income taxes of $0.8 million for the year ended December 31, 2010, which included consideration of the tax benefit recognized by us from stock option deductions generated during the
year ended December 31, 2010. Although our federal and state net operating loss carryforwards exceeded our taxable income for the year ended December 31, 2010, our annual effective tax rate was greater than zero due to the following:
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estimated foreign taxes resulting from guaranteed profit allocable to our foreign subsidiaries, which have been determined to be limited-risk service providers acting on behalf of the U.S. parent for tax purposes, for which there are no tax net operating loss carryforwards;
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certain state taxes for jurisdictions where the states currently limit or disallow the utilization of net operating loss carryforwards; and
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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, 2010 was 8.0%.
We recorded a provision for income taxes of $0.3 million for the year ended December 31, 2009, which was primarily related to the amortization of tax deductible goodwill that generated 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.
We review all available evidence to evaluate the recovery of our deferred tax assets, including the recent history of accumulated losses in all tax jurisdictions over the last three years, as well as our ability to generate income in future periods. As of December 31, 2010 and December 31, 2009, due to the uncertainty related to the ultimate use of our deferred income tax assets, we have provided a full valuation allowance against our U.S. deferred tax assets.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Revenues
The following table summarizes our revenues for the years ended December 31, 2009 and 2008 (dollars in thousands):
For the year ended December 31, 2009, our demand response revenues increased by $84.5 million, or 85%, as compared to the year ended December 31, 2008. This increase in our demand response revenues was primarily attributable to an increase in our MW under management, which increased from over 2,050 as of December 31, 2008 to over 3,550 as of December 31, 2009. The increase in our MW under management was
primarily due to increased selling of our demand response application and services in the following existing operating areas and our expansion into new markets and programs (dollars in thousands):
The increase in our demand response revenues was also attributable to more favorable pricing in certain operating areas, including PJM and ISO-NE, and our effective management of our portfolio of demand response capacity. The increase in our demand response revenues was offset by the expiration of our two fixed price contracts with ISO-NE and our fixed priced contract with The Connecticut Light and Power Company, as well as a reduction in energy payments due to lower real-time demand response prices that affected our participation in certain economic demand response programs, including the day-ahead program with ISO-NE.
For the year ended December 31, 2009, our EfficiencySMART and SupplySMART applications and services revenues were flat compared to the year ended December 31, 2008. Revenues related to our EfficiencySMART and SupplySMART applications and services for the year ended December 31, 2009 increased approximately $0.4 million compared to the same period in 2008 primarily due to a full year of recognized revenue related to our acquisition of SRC, which occurred in May 2008. This increase was offset by a $0.3 million reduction in revenue related to the discontinuation of our energy efficiency audits, which we ceased conducting at the beginning of 2009.
Gross Profit and Gross Margin
The following table summarizes our gross profit and gross margin percentages for our energy management applications and services for the years ended December 31, 2009 and 2008 (dollars in thousands):
Our gross profit increased during the year ended December 31, 2009 as compared to the year ended December 31, 2008 primarily due to the substantial increase in our revenues in 2009, as well as the effective management of our portfolio of demand response capacity and our strong demand response event performance, particularly in the PJM region from which we derive a substantial portion of our revenues. Also contributing to the increase in gross profit was our ability to achieve favorable contract terms with our C&I customers.
Our gross margin increased during the year ended December 31, 2009 as compared to the year ended December 31, 2008 primarily due to the effective management of our portfolio of demand response capacity, as well as our strong demand response event performance, particularly in the PJM region from which we derive a substantial portion of our revenues. Also contributing to the increase in gross margin was our ability to achieve favorable contract terms with our C&I customers.
Operating Expenses
The following table summarizes our operating expenses for the years ended December 31, 2009 and 2008 (dollars in thousands):
Selling and Marketing Expenses
The increase in selling and marketing expenses for the year ended December 31, 2009 compared to the same period in 2008 was primarily driven by the payroll and related costs associated with an increase in the number of selling and marketing full-time employees from 118 at December 31, 2008 to 146 at December 31, 2009. The increase in payroll and related costs for the year ended December 31, 2009 compared to the same period in 2008 was primarily attributable to an increase in sales commissions payable to certain members of our sales force of $3.0 million, as well as the timing associated with our hiring new full-time employees during 2009 as compared to 2008. The increase in stock-based compensation for the year ended December 31, 2009 compared to the same period in 2008 was primarily due to costs related to equity awards granted to certain existing and newly-hired employees. The increase in other selling and marketing expenses for the year ended December 31, 2009 as compared to the same period in 2008 was primarily due to increases in professional services of $0.2 million, third party marketing and selling costs of $0.3 million, other marketing materials, conferences and seminars of $0.5 million, facility costs of $1.3 million and technology and communication costs of $0.5 million.
General and Administrative Expenses
The increase in general and administrative expenses for the year ended December 31, 2009 compared to the same period in 2008 was primarily driven by payroll and related costs due to an increase in executive compensation and severance payments made to our former chief financial officer. The increase in payroll and related costs for the year ended December 31, 2009 compared to the same period in 2008 was also attributable to an increase in full-time employees from 182 at December 31, 2008 to 223 at December 31, 2009. The
increase in stock-based compensation for the year ended December 31, 2009 compared to the same period in 2008 was primarily due to stock-based compensation expenses associated with our current and former chief financial officer and other officers and directors, including the costs related to accelerating the vesting of a certain portion of our former chief financial officer’s options to purchase shares of our common stock. The decrease in other general and administrative expenses for the year ended December 31, 2009 compared to the same period in 2008 was primarily due to a reduction in professional services of $1.5 million, as a result of the voluntary dismissal of the class action complaint against us, offset by an increase in facility costs of $0.3 million.
Research and Development Expenses
The increase in research and development expenses for the year ended December 31, 2009 compared to the same period in 2008 was primarily driven by the costs associated with an increase in the number of research and development full-time employees from 45 at December 31, 2008 to 49 at December 31, 2009. This increase was partially offset by capitalized internal payroll and related costs of $2.1 million at December 31, 2009 and $1.3 million at December 31, 2008. The increase in other research and development expenses for the year ended December 31, 2009 compared to the same period in 2008 was primarily due to an increase in professional services of $0.3 million, facility costs of $0.3 million, and technology and communication costs of $0.3 million due to continued growth in our business and our investments in technology.
Other Income, Net
Other income for the year ended December 31, 2009 was $0.1 million as compared to $1.9 million for the year ended December 31, 2008. The decrease in other income for the year ended December 31, 2009 as compared to the same period in 2008 was primarily due to the global decrease in interest rates, which affected the yields on our investments and, to a lesser extent, lower average investment balances and the recognition of net foreign currency transactions.
Interest Expense
Interest expense for the years ended December 31, 2009 and 2008 was $1.5 million and $1.2 million, respectively. Interest expense includes interest on our outstanding debt, letters of credit origination fees, and amortization of deferred financing fees.
The increase in interest expense for the year ended December 31, 2009 compared to the same period in 2008 was due to a $1.1 million increase in fees associated with outstanding letters of credit, primarily attributable to the arrangement that we entered into with a third party in May 2009 in connection with bidding capacity into a certain open market bidding program. This was offset by a $0.4 million decrease in fees associated with our outstanding debt due to the replacement of our debt facility with BlueCrest Capital Finance, L.P., or BlueCrest, with the SVB credit facility, which occurred in August 2008.
Income Taxes
We had a provision for income taxes of $0.3 million for each of the years ended December 31, 2009 and 2008, which primarily related to the amortization of tax deductible goodwill that generated 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. We provided a full valuation allowance for our deferred tax assets because the realization of any future tax benefits could not be sufficiently assured as of December 31, 2009 and 2008.
Liquidity and Capital Resources
Overview
Since inception, we have generated significant cumulative losses. As of December 31, 2010, we had an accumulated deficit of $67.8 million. As of December 31, 2010, our principal sources of liquidity were cash and cash equivalents totaling $153.4 million, an increase of $33.7 million from the December 31, 2009 balance of $119.7 million. As of December 31, 2010, we were contingently liable for $36.6 million in connection with outstanding letters of credit under the SVB credit facility. As of December 31, 2010 and 2009, we had restricted cash balances of $1.5 million and $7.9 million, respectively, which relate to amounts to collateralize unused outstanding letters of credit and cover financial assurance requirements in certain of the programs in which we participate. At December 31, 2010 and December 31, 2009, our excess cash was primarily invested in money market funds.
We believe our existing cash and cash equivalents at December 31, 2010 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 certain of our energy management applications and services to electric power grid operators and utilities and the increasing rate at which letters of credit or security deposits are required by those electric power grid operators and utilities, the introduction and market acceptance of new energy management applications and services, the expansion of our sales and marketing and research and development activities, and the geographic expansion of our business operations. To the extent that our cash and cash equivalents and our anticipated cash flows from operating activities are insufficient to fund our future activities or planned future acquisitions, we may be required to raise additional funds through bank credit arrangements, including the potential expansion, renewal or replacement of the SVB credit facility, or public or private equity or debt financings. We also may raise additional funds in the event we determine in the future to effect one or more acquisitions of businesses, technologies or products. In addition, we may elect to raise additional funds even before we need them if the conditions for raising capital are favorable. Accordingly, we have filed a shelf registration statement with the SEC to register shares of our common stock and other securities for sale, giving us the opportunity to raise funding when needed or otherwise considered appropriate at prices and on terms to be determined at the time of any such offerings. We currently have the ability to sell approximately $62.1 million of our securities under the shelf registration statement. Any equity or equity-linked financing could be dilutive to existing stockholders. In the event we require additional cash resources, we may not be able to obtain bank credit arrangements or effect any equity or debt financing on terms acceptable to us or at all.
If we fail to extend or renew the SVB credit facility and we still have letters of credit issued and outstanding under the SVB credit facility when it matures on March 31, 2011, we will be required to post 105% of the value of the letters of credit in cash with SVB to collateralize those letters of credit.
Cash Flows
The following table summarizes our cash flows for the years ended December 31, 2010, 2009 and 2008 (dollars in thousands):
Cash Flows Provided by (Used in) Operating Activities
Cash provided by (used in) operating activities primarily consists of net income adjusted for certain non-cash items including depreciation and amortization, stock-based compensation expenses, and the effect of changes in working capital and other activities.
Cash provided by operating activities for the year ended December 31, 2010 was $45.1 million and consisted of net income of $9.6 million and $33.9 million of non-cash items, primarily consisting of depreciation and amortization, deferred taxes, stock-based compensation charges and impairment of property and equipment, as well as $1.6 million of net cash used in working capital and other activities. Cash used in working capital and other activities consisted of an increase of $32.8 million in unbilled revenues relating to the PJM demand response market, an increase of $4.9 million in accounts receivable due to the timing of cash receipts under the programs in which we participate and an increase in prepaid expenses and other assets of $0.7 million. These amounts were offset by cash provided by working capital and other activities which reflected an increase of $2.2 million in accrued payroll and related expenses, an increase of $5.8 million in accounts payable and accrued expenses due to the timing of payments, an increase in accrued capacity payments of $25.2 million, the majority of which was related to the PJM demand response market, and an increase of $6.8 million in deferred revenue.
Cash provided by operating activities for the year ended December 31, 2009 was $8.1 million and consisted of a net loss of $6.8 million and $12.1 million of net cash used for working capital and other activities, offset by $27.0 million of non-cash items, primarily consisting of depreciation and amortization, unrealized foreign exchange transaction loss, deferred tax provision, stock-based compensation charges and other miscellaneous items. Cash used for working capital and other activities consisted of an increase of $28.6 million in unbilled revenues relating to the PJM demand response market, an increase in accounts receivable of $4.6 million due to the timing of cash receipts under the demand response programs in which we participate, an increase in prepaid expenses and other assets of $3.7 million, and a decrease of $2.2 million in accounts payable and accrued expenses due to the timing of payments. These amounts were partially offset by cash provided by working capital and other activities, which reflected a $1.0 million increase in deferred revenue, a $21.9 million increase in accrued capacity payments, the majority of which was related to the PJM demand response market, a $3.9 million increase in accrued payroll and related expenses, and an increase of $0.2 million in other noncurrent liabilities.
Cash used in operating activities for the year ended December 31, 2008 was $15.2 million and consisted of a $36.7 million net loss, which was offset by approximately $0.5 million of net cash provided by working capital and other activities and by $21.0 million of non-cash items, primarily consisting of depreciation and amortization, interest expense, impairment of fixed assets and stock-based compensation charges. Cash provided by working capital consisted of an increase of $2.0 million in accounts payable and accrued expenses due to our relative size compared to the prior period, an increase in accrued capacity payments of $9.6 million, an increase in accrued payroll and related expenses of $1.4 million, an increase in other noncurrent liabilities of $0.2 million, and a decrease in prepaid expenses and other current assets of $0.7 million. These amounts were partially offset by cash used for working capital and other activities, which reflected a $0.8 million increase in accounts receivable due to increased revenues, an increase of unbilled revenues relating to the PJM demand response market of $11.6 million, an increase in other noncurrent assets of $0.1 million and a decrease of deferred revenue of $0.9 million.
Cash Flows (Used in) Provided by Investing Activities
Cash used in investing activities was $15.4 million for the year ended December 31, 2010. Our principal cash investments during the year ended December 31, 2010 related to capitalizing internal use software costs used to build out and expand our energy management applications and services and purchases of property and equipment. During the year ended December 31, 2010, we acquired Smallfoot and Zox for a purchase price of $1.4 million, of which $1.1 million was paid in cash. Additionally, our cash investments included the cash portion of the earn-out payment due in connection with our acquisition of SRC of $0.9 million. We had a decrease in restricted cash and deposits of $6.0 million primarily as a result of demand response event
performance in July 2010 under a certain open market program in which we participate, resulting in our restricted cash becoming unrestricted in July 2010. During the year ended December 31, 2010, we also incurred $19.4 million in capital expenditures primarily related to the purchase of office equipment and demand response equipment and other miscellaneous expenditures.
Cash used in investing activities was $29.2 million for the year ended December 31, 2009. Our principal cash investments during 2009 related to installation services used to build out and expand our energy management applications and services and purchases of property and equipment. Cash provided by the sales of available-for-sale securities during this period was $2.0 million, and we had an increase in restricted cash and deposits resulting in a reduction of cash of $7.1 million, primarily as a result of cash deposits made in connection with demand response programs in which we participate. During the year ended December 31, 2009, we also incurred $16.9 million in capital expenditures primarily related to the purchase of office equipment and demand response equipment and other miscellaneous expenditures. Additionally, our cash investments included $0.7 million, $0.3 million and $6.6 million, respectively, related to the cash portion of the earn-out payment due in connection with our acquisition of SRC, cash used for our acquisition of eQ and cash used for our acquisition of Cogent, net of $0.4 million of cash acquired in connection with our acquisition of Cogent.
Cash provided by investing activities was $6.9 million for the year ended December 31, 2008. In 2008, our principal cash investments related to installation services used to build out and expand our demand response programs, purchases of property and equipment of $12.5 million, a cash earn-out payment in connection with our acquisition of MDE of $3.4 million, $3.8 million of cash used for our acquisition of SRC and $0.4 million of the deferred acquisition payment made to Pinpoint Power DR, LLC. For the year ended December 31, 2008, purchases of available-for-sale securities were approximately $13.6 million and sales of available-for-sale securities were $27.1 million. Also in 2008, we had a decrease of restricted cash and deposits of $13.4 million primarily as a result of our entering into the SVB credit facility.
Cash Flows Provided by (Used in) Financing Activities
Cash provided by financing activities was $4.0 million for the year ended December 31, 2010 and consisted primarily of proceeds that we received from exercises of options to purchase shares of our common stock.
Cash provided by financing activities was $80.0 million for the year ended December 31, 2009 and cash used in financing activities was $1.1 million for the year ended December 31, 2008. In August 2009, we completed an underwritten public offering of an aggregate of 3,963,889 shares of our common stock at an offering price of $27.00 per share, which included the sale of 709,026 shares by certain selling stockholders. Net proceeds to us from the offering were approximately $83.4 million. In addition, we received approximately $1.1 million and $0.5 million, respectively, from exercises of options to purchase shares of our common stock during the years ended December 31, 2009 and 2008. During the year ended December 31, 2009 and 2008, we made scheduled payments on our outstanding debt and capital lease obligations of $4.5 million and $5.9 million, respectively.
Credit Facility Borrowings
Pursuant to the terms of the SVB credit facility, SVB will, among other things, make revolving credit and term loan advances and issue letters of credit for our account. All unpaid principal and accrued interest is due and payable in full on March 31, 2011, which is the maturity date. Our obligations under the SVB credit facility are secured by all of our assets and the assets of our subsidiaries, excluding any intellectual property. The SVB credit facility contains customary terms and conditions for credit facilities of this type. In addition, we are required to meet certain financial covenants customary with this type of facility, including maintaining a minimum specified tangible net worth and a minimum modified quick ratio. The SVB credit facility contains customary events of default. If a default occurs and is not cured within any applicable cure period or is not waived, our obligations under the SVB credit facility may be accelerated. We were in compliance with all
financial covenants under the SVB credit facility at December 31, 2010. As of December 31, 2010, we had an aggregate of $36.6 million in letters of credit issued for our account under the SVB credit facility.
In April 2010, we and one of our subsidiaries entered into a second loan modification agreement to the SVB credit facility, which increased our borrowing limit from $35.0 million to $50.0 million, as well as modified certain of our financial covenant compliance requirements. In July 2010, we and one of our subsidiaries entered into a third loan modification agreement to the SVB credit facility, which extended the maturity date of the SVB credit facility from August 5, 2010 to February 4, 2011, as well as modified certain of our financial covenant compliance requirements. In February 2011, we and SVB further extended the maturity date of the SVB credit facility through March 31, 2011. If we fail to extend or renew the SVB credit facility and we still have letters of credit issued and outstanding under the SVB credit facility when it matures on March 31, 2011, we will be required to post 105% of the value of the letters of credit in cash with SVB to collateralize those letters of credit.
In July 2010, based on our demand response event performance in connection with an open market program in which we participate, approximately $7.7 million of restricted cash that collateralized our performance obligations became unrestricted.
During the year ended December 31, 2010, we made scheduled payments on our outstanding capital lease obligations of $36,000. During the year ended December 31, 2009, we made scheduled payments on our outstanding debt and capital lease obligations of $4.5 million. During the year ended December 31, 2008, we made scheduled payments on our outstanding debt and capital lease obligations of $1.5 million and refinanced $4.4 million of our debt through borrowings of $4.4 million under the SVB credit facility.
Contingent Earn-Out Payments
In connection with our acquisition of Cogent, we agreed to make a single contingent earn-out payment of $1.5 million in cash, to be paid based on the achievement of a certain minimum revenue-based milestone and a certain earnings-based milestone of Cogent for the year ended December 31, 2010. Both of these milestones needed to be achieved in order for the earn-out payment to occur, and there would be no partial payment if the milestones were not fully achieved. As we believed that it was remote that the earn-out payment would not be made, we determined the fair value of the earn-out payment based on the present value of the $1.5 million and recorded this in connection with our purchase accounting for the acquisition of Cogent. The milestones were achieved and the earn-out payment was paid in January 2011.
In connection with our acquisition of SRC, in addition to the amounts paid at closing, we incurred a contingent obligation to pay to the former holders of SRC membership interests an earn-out amount equal to 50% to 60% of the revenues of SRC’s business during each twelve-month period from May 1, 2008 through April 30, 2010, which would be recognized as additional purchase price when earned. The earn-out payments were based on the achievement of certain minimum revenue-based milestones of SRC and paid in a combination of cash and shares of our common stock. The additional purchase price recorded in 2009, which was related to the May 1, 2008 to April 30, 2009 earn-out period, totaled $1.5 million, of which $0.7 million was paid in cash during 2009 and the remainder of which was paid by the issuance of 44,776 shares of our common stock. The additional purchase price recorded in 2010, which was related to the May 1, 2009 to April 30, 2010 earn-out period, totaled $1.8 million, of which $0.9 million was paid in cash during 2010, $39,000 was settled through a reduction of a receivable due to us from the former holders of SRC membership interests and the remainder of which was paid by the issuance of 30,879 shares of our common stock.
Capital Spending
We have made capital expenditures primarily for general corporate purposes to support our growth and for equipment installation related to our business. Our capital expenditures totalled $19.4 million in 2010, $16.9 million in 2009 and $12.5 million in 2008. As we continue to grow, we expect our capital expenditures for 2011 to increase as compared to 2010.
Contractual Obligations
Information regarding our significant contractual obligations of the types described below as of December 31, 2010 is set forth in the following table (dollars in thousands):
Our capital lease obligation consists of a telephone system we lease for which we have a bargain purchase option at the end of the five-year term.
Our operating lease obligations relate primarily to the lease of our corporate headquarters in Boston, Massachusetts and our offices in New York, New York; San Francisco, San Ramon and Concord, California; Baltimore, Maryland; Boise, ID and Dallas, Texas, as well as certain property and equipment.
As of December 31, 2010, we no longer had debt obligations under the SVB credit facility as we repaid the outstanding borrowings of $4.4 million during the fourth quarter of 2009. However, we have $36.6 million of standby letters of credit outstanding under the SVB credit facility in connection with financial assurance requirements under certain demand response programs in which we participate. We are not aware of any events of default under the SVB credit facility.
Off-Balance Sheet Arrangements
As of December 31, 2010, 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, 2010, we had outstanding letters of credit totaling $36.6 million. For information on these commitments and contingent obligations, see Note 12 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), non-GAAP net income (loss) per share, 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) is GAAP net income (loss); the GAAP measure most comparable to non-GAAP net income (loss) per share is GAAP net income (loss) per share; the GAAP measure most comparable to adjusted EBITDA is GAAP net income (loss); and the GAAP measure most comparable to free cash flow is cash flows from operating activities. Reconciliations of each of these non-GAAP financial measures to the corresponding GAAP measure are included below.
Use and Economic Substance of Non-GAAP Financial Measures Used by EnerNOC
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 (loss) to be an important indicator of the overall performance because it eliminates the effects of events that are either not part of our core operations or are non-cash compensation expenses. In addition, management considers adjusted EBITDA to be an important indicator of our operational strength and 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 for the years ended December 31, 2010, 2009 and 2008, respectively, as well as reasons for excluding these individual items:
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Management defines non-GAAP net income (loss) as net income (loss) before expenses related to stock-based compensation and amortization expenses related to acquisition-related intangible assets, net of related tax effects.
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Management defines adjusted EBITDA as net income (loss), excluding depreciation, amortization, stock-based compensation, interest, income taxes and other income (expense). Adjusted EBITDA eliminates items that are either not part of our core operations or do not require a cash outlay, such as stock-based compensation. Adjusted EBITDA also excludes depreciation and amortization expense, which is based on our estimate of the useful life of tangible and intangible assets. These estimates could vary from actual performance of the asset, are based on historic cost incurred to build out our deployed network and may not be indicative of current or future capital expenditures.
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Management defines free cash flow as net cash provided by (used in) operating activities less capital expenditures. Management defines capital expenditures as purchases of property and equipment, which includes capitalization of internal-use software development costs.
Material Limitations Associated with the Use of Non-GAAP Financial Measures
Non-GAAP net income (loss), non-GAAP net income (loss) per share, 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.
Net Income (Loss)
Net income for the year ended December 31, 2010 was $9.6 million, or $0.39 per basic share and $0.37 per diluted share, compared to a net loss of $6.8 million, or $0.32 per basic and diluted share, for the year ended December 31, 2009 and compared to a net loss of $36.7 million, or $1.88 per basic and diluted share, for the year ended December 31, 2008. Excluding stock-based compensation charges and amortization of expenses related to acquisition-related assets, net of tax effects, non-GAAP net income for the year ended December 31, 2010 was $25.4 million, or $1.03 per basic share and $0.97 per diluted share, compared to a non-GAAP net income of $7.0 million, or $0.33 per basic share and $0.30 per diluted share, for the year ended December 31, 2009 and compared to a non-GAAP net loss of $25.2 million, or $1.29 per basic and diluted share, for the year ended December 31, 2008. The reconciliation of non-GAAP net income (loss) to GAAP net income (loss) is set forth below:
(1)
Represents the increase in the income tax provision recorded for the year ended December 31, 2010 based on our effective tax rate for the year ended December 31, 2010.
Adjusted EBITDA
Adjusted EBITDA was $42.8 million and $20.1 million for the years ended December 31, 2010 and 2009, respectively. Adjusted EBITDA was negative $17.7 million for the year ended December 31, 2008. The reconciliation of adjusted EBITDA to net income (loss) is set forth below:
Free Cash Flow
Cash flow from operating activities was $45.1 million, $8.1 million and negative $15.2 million for the years ended December 31, 2010, 2009 and 2008, respectively. We generated $25.8 million, negative $8.8 million and negative $27.7 million of free cash flow for the years ended December 31, 2010, 2009 and 2008, respectively. The reconciliation of free cash flow to cash flow from operating activities is set forth below:
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 related charges, stock-based compensation, contingent liabilities, tax reserves and recoverability of our net 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.
We believe that 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, 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 (formerly Staff Accounting Bulletin No. 104, Revenue Recognition in Financial Statements, and Emerging Issues Task Force, or EITF, Issue No. 00-21, Accounting for Revenue Arrangements with Multiple Deliverables). In all of our arrangements, 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 these criteria as follows:
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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.
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Delivery has occurred. We consider delivery to have occurred when service has been delivered to the customer and no post-delivery obligations exist. In instances where customer acceptance is required, delivery is deemed to have occurred when customer acceptance has been achieved.
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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 offered payment terms significantly exceed our normal terms, we recognize revenues as the amounts become due and payable or upon the receipt of cash.
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Collection is reasonably assured. We conduct a credit review at the inception of an arrangement to determine the creditworthiness of the customer. Collection is reasonably assured if, based upon our 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 enter into utility contracts and open market bidding programs to provide demand response applications and services. Demand response revenues consist of two elements: revenue earned based on our ability to deliver committed capacity to our electric power grid operator and utility customers, which we refer to as capacity revenue; and revenue earned based on additional payments made to us for the amount of energy usage actually curtailed from the grid during a demand response event, which we refer to as energy event revenue.
We recognize demand response revenue when we have provided verification to the electric power grid operator or utility of our ability to deliver the committed capacity which entitles us to payments under the utility contract or open market program. Committed capacity is generally verified through the results of an actual demand response event or a measurement and verification test. Once the capacity amount has been verified, the revenue is recognized and future revenue becomes fixed or determinable and is recognized monthly until the next demand response event or test. In subsequent verification events, if our verified capacity is below the previously verified amount, the electric power grid operator or utility customer will reduce future payments based on the adjusted verified capacity amounts. Ongoing demand response revenue recognized between demand response events or tests that are not subject to penalty or customer refund are recognized in revenue. If the revenue is subject to refund and the amount of refund cannot be reliably estimated, the revenue is deferred until the right of refund lapses.
Certain of the forward capacity programs in which we participate may be deemed derivative contracts under ASC 815, Derivatives and Hedging (formerly SFAS No. 133, Accounting for Derivative and Hedging Activities). In such situations, we believe we meet the scope exception under ASC 815 as a normal purchase, normal sale as that term is defined in ASC and, accordingly, the arrangement is not treated as a derivative contract.
Revenue from energy events is recognized when earned. Energy event revenue is deemed to be substantive and represents the culmination of a separate earnings process and is recognized when the energy
event is initiated by the electric power grid operator or utility customer and we have responded under the terms of the utility contract or open market program.
As described above, utility contracts or open market programs may include performance guarantees. If we are unable to reliably estimate our ability to meet these guarantees, we do not recognize any revenue prior to the successful completion of the performance requirement.
In addition to demand response and energy event revenues, we generally receive either a subscription-based fee, consulting fee or a percentage savings fee for arrangements under which we provide our EfficiencySMART, SupplySMART and CarbonSMART applications and services. We generally recognize these revenues over the service delivery period as the services are delivered. If the revenue is subject to refund and the amount of refund cannot be reliably estimated, the revenue is deferred until the right of refund lapses.
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 management. 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 use the income approach to determine the estimated fair value of identifiable intangible assets, including customer contracts, 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 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.
Customer contracts represent contractual arrangements to provide ongoing energy management applications and services. Customer relationships represent established relationships with customers, which provide a ready channel for the sale of additional energy management applications and services. Non-compete agreements represent arrangements with certain employees that limit or prevent their ability to take employment at a competitor for a fixed period of time. Tradenames represent acquired product names that we intend to continue to utilize.
We have also utilized the cost approach to determine the estimated fair value of acquired indefinite-lived intangible assets related to acquired in-process research and development given the stage of development as of the acquisition date and the 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 represent the fair value at the date of acquisition and do not exceed the amount a third party would pay for the projects.
Impairment of Intangible Assets and Goodwill
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 year ended December 31, 2009, as a result of a change in the expected period of economic benefit of the trade name acquired in the acquisition of Cogent, we determined that an impairment indicator existed. Based on the analysis performed, we determined that this trade name was partially impaired and recorded an impairment charge of $135,000 during the year ended December 31, 2009, which is included in general and administrative expenses in the accompanying consolidated statements of operations. The fair market value of approximately $65,000 was determined using Level 3 inputs, as defined by ASC 820, Fair Value Measurements and Disclosures (formerly SFAS No. 157, Fair Value Measurement), based on the projected future cash flows over the revised period of economic benefit discounted based on our weighted average cost of capital of 17%.
Goodwill
In accordance with ASC 350, Intangibles - Goodwill and Other (formerly FASB SFAS No. 142, Goodwill and Other Intangible Assets), 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 the reporting unit level is the entity level as discrete financial information is not available at a lower level and our chief operating decision maker, which is our chief executive officer and executive management team, collectively, make business decisions based on the evaluation of financial information at the entity level. 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.
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, as defined, 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 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 the date of the impairment test on our weighted average cost of capital. 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.
We conducted our annual impairment test as of November 30, 2010. In order to complete the annual impairment test, we performed detailed analyses estimating the fair value of our reporting unit utilizing our forecast for the fiscal year ending December 31, 2011 with updated long-term growth assumptions. As a result of completing the first step, the fair value exceeded the carrying value, and as such the second step of the
impairment test was not required. To date, we have not been required to perform the second step of the impairment test.
The fair value of the entity is determined by use of a market approach based on the quoted market price of our common stock and the number of shares outstanding. We believe that we are not at risk of failing the first step of the goodwill impairment test.
The estimate of fair value requires significant judgment. Any loss resulting from an impairment test would be reflected in operating loss 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 Property and Equipment
We review property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of assets may not be recoverable. If these assets are considered to be impaired, the impairment is recognized in earnings and equals the amount by which the carrying value of the assets exceeds their fair market value determined by either a quoted market price, if any, or a value determined by utilizing a discounted cash flow technique. If these assets are not impaired, but their useful lives have decreased, the remaining net book value is amortized over the revised useful life.
During the three months ended December 31, 2010, we identified a potential impairment indicator related to certain demand response and back-up generator equipment as a result of lower than estimated demand response event performance by these assets. As a result of this potential indicator of impairment, we performed an impairment test during the three months ended December 31, 2010. The applicable long-lived assets were measured for impairment at the lowest level for which identifiable cash flows were largely independent of the cash flows of other assets or liabilities. We determined that the undiscounted cash flows to be generated by the asset group over its remaining estimated useful life would not be sufficient to recover the carrying value of the asset group. We determined the fair value of the asset group using a discounted cash flow technique based on Level 3 inputs, as defined by ASC 820, Fair Value Measurements and Disclosures, or ASC 820, and a discount rate of 11%, which we determined represents a market rate of return for the assets being evaluated for impairment. We determined that the fair value of the asset group was $0.8 million compared to the carrying value of the asset group of $1.1 million, and as a result recorded an impairment charge of $0.3 million during the three months ended December 31, 2010, which is reflected in cost of revenues in the accompanying consolidated statements of operations. The impairment charge was allocated to the individual assets within the asset group on a pro-rata basis using the relative carrying amounts of those assets.
During the three months ended September 30, 2010, we identified an impairment indicator related to certain demand response equipment as a result of lower than estimated demand response event performance in certain demand response programs and the removal of demand response equipment from service during the three months ended September 30, 2010. As a result of this impairment indicator, we performed an impairment test during the three months ended September 30, 2010 and recognized an impairment charge of $0.6 million during the three months ended September 30, 2010, representing the difference between the carrying value and fair market value of the demand response equipment, which is included in cost of revenues in the accompanying consolidated statements of operations. The fair market value was determined utilizing Level 3 inputs, as defined by ASC 820, based on the projected future cash flows discounted using the estimated market participant rate of return for this type of asset.
During the three months ended June 30, 2010, we identified an impairment indicator related to certain demand response and back-up generator equipment as a result of lower than estimated demand response event performance by these assets. The applicable long-lived assets were measured for impairment at the lowest level for which identifiable cash flows were largely independent of the cash flows of other assets or liabilities. We determined that the undiscounted cash flows to be generated by the asset group over its remaining estimated useful life would not be sufficient to recover the carrying value of the asset group. We determined the fair value of the asset group using a discounted cash flow technique based on Level 3 inputs, as defined by
ASC 820, and a discount rate of 11%, which we determined to represent a market rate of return for the assets being evaluated for impairment. We determined that the fair value of the asset group was $1.5 million compared to the carrying value of the asset group of $2.3 million, and as a result recorded an impairment charge of $0.8 million during the three months ended June 30, 2010, which is reflected in cost of revenues in the accompanying consolidated statements of operations. The impairment charge was allocated to the individual assets within the asset group on a pro-rata basis using the relative carrying amounts of those assets.
For the year ended December 31, 2009, the carrying value of a portion of our demand response and generation equipment exceeded the undiscounted future cash flows based upon the anticipated retirement dates. As a result, we recognized an impairment charge of $1.2 million representing the difference between the carrying value and fair market value of demand response and generation equipment, which is included in cost of revenues in the accompanying consolidated statements of operations. The fair market value of approximately $0.2 million was determined utilizing Level 3 inputs, as defined by ASC 820, based on the projected future cash flows discounted using the estimated market participant rate of return for this type of asset. We recognized an impairment charge of $0.7 million for the year ended December 31, 2008, which is included in cost of revenues in the accompanying consolidated statements of operations.
As of December 31, 2010, approximately $2.1 million of our generation equipment was utilized in open market demand response programs. The recoverability of this generation equipments’ carrying value is largely dependent on the rates that we are compensated for its committed capacity within these programs. These rates represent market rates and can fluctuate based on the supply and demand of capacity. Although these market rates are established up to three years in advance of the service delivery, these market rates have not yet been established for the entire remaining useful life of this generation equipment. In performing the relevant impairment analysis, we estimate the expected future market rates based on current existing market rates and trends. A decline in the expected future market rates of greater than 10% could result in an impairment charge related to this generation equipment.
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 who devote time to the development of internal-use computer software. We amortize these costs on a straight-line basis over the estimated useful life of the software, which is generally two to three 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. Software development costs of $6.8 million, $4.2 million and $3.2 million for the years ended December 31, 2010, 2009 and 2008, respectively, have been capitalized. We capitalized $1.3 million and $1.5 million during the years ended December 31, 2010 and 2009, respectively, related to a company-wide enterprise resource planning systems implementation project.
Stock-Based Compensation
Our Amended and Restated 2003 Stock Option and Incentive Plan, which we refer to as the 2003 plan, and our Amended and Restated 2007 Employee, Director and Consultant Stock Plan, which we refer to as the 2007 plan, provide for the grant of incentive stock options, nonqualified stock options, restricted and unrestricted stock awards and other stock-based awards to our eligible employees, directors and consultants. Options granted under both the 2003 plan and the 2007 plan are exercisable for a period determined by us, but in no event longer than ten years from the date of the grant. Option awards are generally granted with an exercise price equal to the market price of our common stock on the date of grant. Options, restricted stock awards and restricted stock unit awards generally vest ratably over four years, with certain exceptions. The 2003 plan expired upon our IPO in May 2007. Any forfeitures under the 2003 plan that occurred after the effective date of the IPO are available for future grant under the 2007 plan up to a maximum of 1,000,000 shares. During the years ended December 31, 2010 and 2009, we issued 24,681 shares of our common stock and 45,085 shares of our common stock, respectively, to certain executives to satisfy a portion
of our compensation obligations to those individuals. As of December 31, 2010, 1,946,749 shares were available for future grant under the 2007 plan.
For stock options granted prior to January 1, 2009, the fair value of each option was estimated at the date of grant using a Black-Scholes option-pricing model. For stock options granted on or after January 1, 2009, the fair value of each option is estimated on the date of grant using a lattice valuation model. The lattice model considers characteristics of fair value option pricing that are not available under the Black-Scholes model. Similar to the Black-Scholes model, the lattice model takes into account variables such as expected volatility, dividend yield rate, and risk free interest rate. However, in addition, the lattice model considers the probability that the option will be exercised prior to the end of its contractual life and the probability of termination or retirement of the option holder in computing the value of the option. For these reasons, we believe that the lattice model provides a fair value that is more representative of actual experience and future expected experience than the value calculated using the Black-Scholes model.
Volatility measures the amount that a stock price has fluctuated or is expected to fluctuate during a period. As there was no public market for our common stock prior to the effective date of the IPO, we determined volatility based on an analysis of reported data for a peer group of companies that issued options with substantially similar terms. The expected volatility of options granted has been determined using an average of the historical volatility measures of this peer group of companies, as well as the historical volatility of our common stock beginning January 1, 2008. During the three months ended September 30, 2010, we determined that we had sufficient history to utilize company-specific volatility in accordance with ASC 718, Stock Compensation , or ASC 718, and we are now calculating volatility using a component of implied volatility and historical volatility to determine the value of share-based payments. The risk-free interest rate is the rate available as of the option date on zero-coupon United States government issues with a term equal to the expected life of the option. We have not paid dividends on our common stock in the past and do not plan to pay any dividends in the foreseeable future. In addition, the terms of the SVB credit facility preclude us from paying dividends. During the year ended December 31, 2010, we updated our estimated exit rate pre-vesting and post-vesting applied to options, restricted stock and restricted stock units based on an evaluation of demographics of our employee groups and historical forfeitures for these groups in order to determine our option valuations as well as our stock-based compensation expense. The changes in estimate of the volatility, exit rate pre-vesting and exit rate post-vesting did not have a material impact on our stock-based compensation expense recorded in the accompanying consolidated statements of operations for the year ended December 31, 2010.
The amount of stock-based compensation expense recognized during a period is based on the value of the portion of the awards that are ultimately expected to vest. ASC 718 requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. The term “forfeitures” is distinct from “cancellations” or “expirations” and represents only the unvested portion of the surrendered option. We have determined a forfeiture rate of 5.95% as of December 31, 2010. Ultimately, the actual expense recognized over the vesting period will only be for those awards that vest.
For the years ended December 31, 2010, 2009 and 2008, we recorded expenses of approximately $15.7 million, $13.1 million and $10.4 million, respectively, in connection with share-based payment awards to employees and non-employees. With respect to grants through December 31, 2010, a future expense of non-vested options of approximately $11.0 million is expected to be recognized over a weighted average period of 2.3 years and a future expense of restricted stock and restricted stock units of approximately $14.4 million is expected to be recognized over a weighted average period of 2.7 years.
For awards with graded vesting, we allocate compensation costs on a straight-line basis over the requisite service period. Accordingly, we amortized the fair value of each option over each option’s service period, which is generally the vesting period.
Our accounting for stock options issued to non-employees requires valuing and remeasuring such stock options to the current fair value until the performance date has been reached. Stock-based compensation expense recorded for the years ended December 31, 2010, 2009 and 2008 related to stock options to non-employees was not material.
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 taxes 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.
We have incurred consolidated net losses since our inception and as a result, we had not recognized net United States deferred taxes as of December 31, 2010 or December 31, 2009. Our deferred tax liabilities primarily relate to deferred taxes associated with our acquisitions and property and equipment. Our deferred tax assets relate primarily to net operating loss carryforwards, accruals and reserves, and stock-based compensation. We record a valuation allowance to reduce our deferred tax assets to the amount that is more likely than not to be realized. While we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowance, in the event we were to determine that we would be able to realize our deferred tax assets in the future in excess of the net recorded amount, an adjustment to the deferred tax asset would increase income in the period such determination was made.
In accordance with ASC 740, Income Taxes, we are required to evaluate uncertainty in income taxes recognized in our financial statements (formerly FASB Interpretation No. 48, or FIN 48, Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109). ASC 740 prescribes a recognition threshold and measurement criteria for the financial statement recognition and measurement of a tax position 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 had no unrecognized tax benefits as of December 31, 2010 and 2009.
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. In our opinion, it is not required that we have a provision for income taxes for any years subject to audit. Although we believe our estimates are reasonable, no assurance can be given that the final tax outcome of matters will not be different than that which is reflected in our historical income tax provisions and accruals. In the event our assumptions are incorrect, 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 September 2009, the FASB ratified ASC Update No. 2009-13, Multiple-Deliverable Revenue Arrangements, or ASU 2009-13. ASU 2009-13 amends existing revenue recognition accounting pronouncements that are currently within the scope of ASC Subtopic 605-25 (previously included within EITF Issue No. 00-21, Revenue Arrangements with Multiple Deliverables, or EITF 00-21). ASU 2009-13 provides for two significant changes to the existing multiple element revenue recognition guidance. First, ASU 2009-13 deletes the requirement to have objective and reliable evidence of fair value for undelivered elements in an arrangement and will result in more deliverables being treated as separate units of accounting. The second change modifies the manner in which the transaction consideration is allocated across the separately identified deliverables. These changes may result in entities recognizing more revenue up-front, and entities will no longer be able to apply the residual method and defer the fair value of undelivered elements. Upon adoption of ASU 2009-13, each separate unit of accounting must have a selling price, which can be based on management’s estimate when there is no other means to determine the fair value of that undelivered item, and the arrangement consideration is allocated based on the elements’ relative selling price. Entities may elect to adopt ASU 2009-13 either through prospective application to all revenue arrangements entered into or materially modified after the date of adoption or through a retrospective application to all revenue arrangements for all periods presented in the financial statements. We will adopt ASU 2009-13 on a prospective basis for all revenue arrangements entered into or materially modified after January 1, 2011. We do not expect that the adoption of ASU 2009-13 will have a material impact on our consolidated financial position or results of operations.
In January 2010, the FASB issued ASU 2010-06, Improving Disclosure about Fair Value Measurements, or ASU 2010-06. ASU 2010-06 requires additional disclosures regarding fair value measurements, amends disclosures about post-retirement benefit plan assets and provides clarification regarding the level of disaggregation of fair value disclosures by investment class. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for certain Level 3 activity disclosure requirements that are effective for reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not have a material impact on our consolidated financial position or results of operations.
Selected Quarterly Financial Data (Unaudited)
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.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosure About Market Risk
Financial Instruments, Other Financial Instruments, and Derivative Commodity Instruments
ASC 825, Financial Instruments (formerly SFAS No. 107, Disclosure of Fair Value of 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 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.
We maintain sales and service offices outside the United States. The expenses of our international offices are denominated in local currencies. In addition, our foreign sales are denominated in local currencies. 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 hold deposits of that currency.
We believe that the operating expenses of our international subsidiaries that are incurred in local currencies will not have a material adverse effect on our business, results of operations or financial condition. 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 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. However, we believe that the foreign currency exchange risk is not significant. A hypothetical 10% increase or decrease in foreign currencies that we transact in would not have a material adverse effect on our financial condition or results of operations. During the years ended December 31, 2010, 2009 and 2008, we incurred foreign exchange losses of $133,000, $29,000 and $0, respectively.
Interest Rate Risk
As of December 31, 2010, we had no outstanding debt under the SVB credit facility. This is a result of repaying our outstanding borrowings of approximately $4.4 million under the SVB credit facility during the fourth quarter of 2009.
The recent market events have not required us to materially modify or change our financial risk management strategies with respect to our exposure to interest rate risk.
We manage our cash and cash equivalents portfolio considering investment opportunities and risks, tax consequences and overall financing strategies. Our investment portfolio consists primarily of cash and cash equivalents, money market funds, and commercial paper. We have, in the past, held municipal auction rate securities that have since been redeemed. As our investments are made with highly rated securities, we are not anticipating any significant impact in the short term from a change in interest rates.
Item 8.
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.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A.
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, 2010. 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, or the COSO criteria.
Based on this assessment, management believes that, as of December 31, 2010, our internal control over financial reporting was effective at a reasonable assurance level 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, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of EnerNOC, Inc.
We have audited EnerNOC, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (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 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 of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, EnerNOC, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010 of EnerNOC, Inc. and our report dated February 28, 2011 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Boston, Massachusetts
February 28, 2011
Item 9B.
Item 9B.
Other Information
None.
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance
The information required by this Item will be contained in our definitive proxy statement for our 2011 Annual Meeting of Stockholders under the captions “Directors and Executive Officers,” “Corporate Governance and Board Matters,” “Corporate Code of Conduct and Ethics” and “Section 16(a) Beneficial Ownership Reporting Compliance” and is incorporated by reference herein.
Item 11.
Item 11.
Executive Compensation
The information required by this Item will be contained in our definitive proxy statement for our 2011 Annual Meeting of Stockholders under the captions “Compensation Discussion and Analysis,” “Corporate Governance and Board Matters” and “Compensation Committee Report” and is incorporated by reference herein.
Item 12.
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 2011 Annual Meeting of Stockholders under the captions “Compensation Discussion and Analysis,” “Equity Compensation Plan Information” and “Security Ownership of Certain Beneficial Owners and Management” and is incorporated by reference herein.
Item 13.
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 2011 Annual Meeting of Stockholders under the captions “Certain Relationships and Related Transactions” and “Corporate Governance and Board Matters” and is incorporated by reference herein.
Item 14.
Item 14.
Principal Accounting Fees and Services
The information required by this Item will be contained in our definitive proxy statement for our 2011 Annual Meeting of Stockholders under the caption “Proposal Five - Ratification of Appointment of Independent Registered Public Accounting Firm” and is incorporated by reference herein.
PART IV
Item 15.
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 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, 2010 and 2009
•
Consolidated Statements of Operations for the Years ended December 31, 2010, 2009 and 2008
•
Consolidated Statements of Changes in Stockholders’ Equity and Comprehensive (Loss) Income for the Years ended December 31, 2010, 2009 and 2008
•
Consolidated Statements of Cash Flows for the Years ended December 31, 2010, 2009 and 2008
•
Notes to the 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.
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: February 28, 2011
By: /s/ Timothy G. Healy
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.
APPENDIX A
EnerNOC, Inc.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders of EnerNOC, Inc.
We have audited the accompanying consolidated balance sheets of EnerNOC, Inc. as of December 31, 2010 and 2009, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2010. 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, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.
We also have 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, 2010, based on criteria established in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2011 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Boston, Massachusetts
February 28, 2011
EnerNOC, Inc.
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
The accompanying notes are an integral part of these consolidated financial statements
EnerNOC, Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share and per share data)
The accompanying notes are an integral part of these consolidated financial statements.
EnerNOC, Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE (LOSS) INCOME
(In thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements.
EnerNOC, Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
The accompanying notes are an integral part of these consolidated financial statements
EnerNOC, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except share and per share data)
1.
Description of Business, Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
EnerNOC, Inc. (the Company) is a service company that was incorporated in Delaware on June 5, 2003. The Company operates in a single segment providing clean and intelligent energy management applications and services for the smart grid, which include comprehensive demand response, data-driven energy efficiency, energy price and risk management, and enterprise carbon management applications and services. The Company’s energy management applications and services enable cost effective energy management strategies for its commercial, institutional and industrial end-users of energy (C&I customers) and its electric power grid operator and utility customers by reducing real-time demand for electricity, increasing energy efficiency, improving energy supply transparency, and mitigating emissions. The Company uses its Network Operations Center (NOC) and comprehensive demand response application, DemandSMART, to remotely manage and reduce electricity consumption across a growing network of C&I customer sites, making demand response capacity available to electric power grid operators and utilities on demand while helping C&I customers achieve energy savings, improved financial results and environmental benefits. To date, the Company has received substantially all of its revenues from electric power grid operators and utilities, who make recurring payments to the Company for managing demand response capacity that it shares with its C&I customers in exchange for those C&I customers reducing their power consumption when called upon.
The Company builds on its position as a leading demand response services provider by using its NOC and energy management application platform to deliver a portfolio of additional energy management applications and services to new and existing C&I, electric power grid operator and utility customers. These additional energy management applications and services include its EfficiencySMART, SupplySMART and CarbonSMART applications and services. EfficiencySMART is its data-driven energy efficiency suite that includes commissioning and retro-commissioning authority services, energy consulting and engineering services, a persistent commissioning application and an enterprise energy management application for managing energy across a portfolio of sites. SupplySMART is its energy price and risk management application that provides its C&I customers located in restructured or deregulated markets throughout the United States with the ability to more effectively manage the energy supplier selection process, including energy supply product procurement and implementation, budget forecasting, and utility bill information management. CarbonSMART is its enterprise carbon management application that supports and manages the measurement, tracking, analysis, reporting and management of greenhouse gas emissions.
Reclassifications
Certain reclassifications have been made to the consolidated statements of cash flows for the years ended December 31, 2008 and 2009 to conform to the December 31, 2010 presentation. The reclassifications primarily consist of certain receivables, which were previously included in trade accounts receivable, that are not trade in nature. These certain receivables are now being classified in prepaid expenses, deposits and other current assets in the accompanying consolidated balance sheets. Additionally, the Company reclassified short-term restricted cash to long-term restricted cash as of December 31, 2009 as this classification more appropriately described the nature of this restricted cash as of December 31, 2009.
The Company has identified and reclassified the change in its deferred revenue, long-term balance totaling $1,251 and $1,910, which was included in the change in other noncurrent liabilities in its consolidated statements of cash flows for the six months ended June 30, 2010 and nine months ended September 30, 2010, respectively, as a change in deferred revenues for the six months ended June 30, 2010 and nine months ended September 30, 2010 to appropriately reflect the change in total deferred revenue. The Company has determined that the reclassification was not material to its consolidated financial statements and, in future quarterly filings, will continue to reclassify this change. This change will result in an increase in the cash flows attributed to a
change in deferred revenue from $2,863 to $4,114 and a corresponding decrease in cash flows attributed to a change in other noncurrent liabilities from $1,220 to ($31) for the six months ended June 30, 2010 and an increase in the cash flows attributed to a change in deferred revenue from $218 to $2,128 and a corresponding decrease in cash flows attributed to a change in other noncurrent liabilities from $1,879 to ($31) for the nine months ended September 30, 2010. This reclassification had no impact on the Company’s cash flows from operating activities for any period.
The Company has identified and reclassified certain costs totaling $399 and $457 included in selling and marketing expenses in its consolidated statements of operations for the three months ended March 31, 2010 and June 30, 2010, respectively, as general and administrative expenses for the nine months ended September 30, 2010 to more appropriately reflect the nature of these costs. The Company has determined that the reclassification was not material to its consolidated financial statements and, in future quarterly filings, will continue to reclassify these costs, resulting in an increase in general and administrative expenses and a corresponding decrease in selling and marketing expenses of $399 and $457 for the three months ended March 31, 2010 and June 30, 2010, respectively.
Basis of Consolidation
The consolidated financial statements of the Company include the accounts of its wholly-owned subsidiaries and have been prepared in conformity with accounting principles generally accepted in the United States (GAAP). Intercompany transactions and balances are eliminated upon consolidation.
On March 15, 2010, the Company acquired substantially all of the assets and certain liabilities of SmallFoot LLC (Smallfoot) and ZOX, LLC (Zox) in a purchase business combination. Accordingly, the results of Smallfoot and Zox subsequent to that date are included in the Company’s consolidated statements of operations.
On December 4, 2009, the Company acquired all of the outstanding capital stock of Cogent Energy, Inc. (Cogent) in a purchase business combination. Accordingly, the results of Cogent subsequent to that date are included in the Company’s consolidated statements of operations.
On June 11, 2009, the Company acquired all of the assets eQuilibrium Solutions Corporation (eQ) in a purchase business combination. Accordingly, the results of eQ subsequent to that date are included in the Company’s consolidated statements of operations.
On May 1, 2008, the Company acquired 100% of the membership interests of South River Consulting, LLC (SRC) in a purchase business combination. Accordingly, the results of SRC subsequent to that date are included in the Company’s consolidated statements of operations.
On September 13, 2007, the Company purchased all of the outstanding membership interests of Mdenergy, LLC (MDE) in a purchase business combination. Accordingly, the results of MDE subsequent to that date are included in the Company’s consolidated statements of operations.
Subsequent Events Consideration
The Company considers events or transactions that occur after the balance sheet date but prior to the issuance of the financial statements to provide additional evidence relative to certain estimates or to identify matters that require additional disclosure. Subsequent events have been evaluated as required.
M2M Communications Corporation Acquisition
On January 25, 2011, the Company completed its acquisition of M2M Communications Corporation (M2M) pursuant to a definitive agreement dated January 21, 2011. The Company concluded that this acquisition represents a business combination and therefore, has accounted for it as such. M2M is a leading provider of wireless technology solutions for energy management and demand response.
The Company acquired M2M for an aggregate purchase price of $29,649, plus an additional $3,297 paid as a result of M2M having a positive capitalization amount at closing, consisting of $17,597 in cash paid at
closing and $8,349 representing the fair value of 351,664 shares of stock issued as of the acquisition date and $7,000 of deferred purchase price consideration. The difference between the $29,649 aggregate purchase price disclosed above and the $30,000 aggregate purchase price set forth in the definitive agreement was due to the fact that the fair value of stock issued in connection with the acquisition was based upon the Company’s stock price as of the closing date of the acquisition of $23.74 per share, as compared to a per share value of $24.74 determined in accordance with the definitive agreement, which is based upon the average of the per share last sale price for the Company’s common stock for the ten trading day period ending two trading days prior to the closing. The deferred purchase price consideration of $7,000 will be paid upon the earlier of the satisfaction of certain conditions contained in the definitive agreement or seven years after the acquisition date. The deferred purchase price consideration is not subject to adjustment or forfeiture. The Company is still gathering information in order to determine the fair value of the deferred purchase price consideration as of the acquisition date. Any changes in fair value after the completion of this fair value analysis will be recorded to the Company’s consolidated statements of operations.
Transaction costs related to this business combination were not material and have been expensed as incurred, which are included in general and administrative expenses in the accompanying consolidated statements of operations. The Company’s consolidated financial statements will reflect M2M’s results of operations from January 25, 2011 forward.
The Company is in the process of gathering information to complete its preliminary valuation of certain assets and liabilities in order to complete a preliminary purchase price allocation.
Global Energy Partners Acquisition
On January 3, 2011, the Company completed its acquisition of Global Energy Partners, Inc. (GEP) pursuant to a definitive agreement dated December 2, 2010. The Company concluded that this acquisition represents a business combination and therefore, has accounted for it as such. GEP is a company specializing in the design and implementation of utility energy efficiency and demand response programs.
The Company acquired all of the outstanding stock of GEP for an aggregate purchase price of $26,658, consisting of approximately $19,875 in cash and $6,783 representing the fair value of 275,181 shares of stock issued as of the acquisition date. This transaction has no contingent consideration or earn-out payments. The difference between the $26,658 aggregate purchase price disclosed above and the $26,500 aggregate purchase price set forth in the definitive agreement was due to the fact that the fair value of stock issued in connection with the acquisition was based upon the Company’s stock price as of the closing date of the acquisition of $24.65 per share, as compared to a per share value of $24.08 determined in accordance with the definitive agreement, which is based upon the average of the per share last sale price for the Company’s common stock for the ten trading day period ending two trading days prior to the closing.
Transaction costs related to this business combination were not material and have been expensed as incurred, which are included in general and administrative expenses in the accompanying consolidated statements of operations. The Company’s consolidated financial statements will reflect GEP’s results of operations from January 3, 2011 forward.
The Company is in the process of gathering information to complete its preliminary valuation of certain assets and liabilities in order to complete a preliminary purchase price allocation.
There were no other material recognizable subsequent events recorded or requiring disclosure in the December 31, 2010 consolidated financial statements.
Use of Estimates in Preparation of Financial Statements
The preparation of these consolidated financial statements requires the Company 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, the Company evaluates its estimates, including those related to revenue recognition, 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 related charges, stock-based compensation, contingent liabilities, tax reserves and recoverability of the Company’s net deferred tax assets and related valuation allowance.
Although the Company regularly assesses these estimates, actual results could differ materially. Changes in estimates are recorded in the period in which they become known. The Company bases its estimates on historical experience and various other assumptions that it believes to be reasonable under the circumstances. Actual results may differ from management’s estimates if these results differ from historical experience or other assumptions prove not to be substantially accurate, even if such assumptions are reasonable when made.
The Company is subject to a number of risks similar to those of other companies of similar and different sizes both inside and outside its industry, including, but not limited to, rapid technological changes, competition from substitute energy management applications and services from larger companies, customer concentration, government regulations, market or program rule changes, protection of proprietary rights and dependence on key individuals.
Significant Accounting Policies
Restricted Cash, Cash Equivalents and Marketable Securities
Restricted cash is comprised of certificates of deposit and cash held to collateralize the Company’s outstanding letters of credit. Cash equivalents are highly liquid investments with insignificant interest rate risk and maturities of three months or less at the time of acquisition. Investments qualifying as cash equivalents consist of investments in money market funds, which have no withdrawal restrictions or penalties and totaled $108,000 and $100,520 at December 31, 2010 and 2009, respectively.
The Company held no marketable securities as of December 31, 2010 or 2009. The cost of securities sold is based on the specific identification method. Interest and dividends on securities classified as available-for-sale are included in interest and other income.
Disclosure of Fair Value of Financial Instruments
The Company’s financial instruments mainly consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable and debt obligations. The carrying amounts of the Company’s cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair value due to the short-term nature of these instruments. There are no amounts outstanding under the $50,000 secured revolving credit and term loan facility that the Company and one of its subsidiaries entered into with Silicon Valley Bank (SVB) as the Company paid the outstanding borrowings of $4,442 in 2009. For additional information regarding this credit facility with SVB (Credit Facility), see Note 7.
Concentrations of Credit Risk
Financial instruments that potentially subject the Company to significant concentrations of credit risk principally consist of cash and cash equivalents, restricted cash and billed and unbilled accounts receivable. The Company maintains its cash and cash equivalent balances with highly rated financial institutions and, consequently, such funds are subject to minimal credit risk.
The Company’s customers are principally located in the northeastern and PJM Interconnection (PJM) regions of the United States. The Company performs ongoing credit evaluations of the financial condition of its customers and generally does not require collateral. Although the Company is directly affected by the overall financial condition of the energy industry as well as global economic conditions, the Company does not believe significant credit risk exists as of December 31, 2010. The Company generally has not experienced any material losses related to receivables from individual customers or groups of customers in the energy industry. The Company maintains an allowance for doubtful accounts based on accounts past due and historical collection experience. The Company’s losses related to collection of trade receivables have
consistently been within the Company’s expectations. Due to these factors, no additional credit risk beyond amounts provided for collection losses is believed by the Company to be probable.
The following table presents the Company’s significant customers. With respect to PJM and ISO-New England, Inc. (ISO-NE), these customers are regional electric power grid operators, which are comprised of multiple utilities and were formed to control the operation of a regional power system, coordinate the supply of electricity, and establish fair and efficient markets.
Accounts receivable from PJM and ISO-NE was approximately $11,199 and $9,788 at December 31, 2010 and 2009, respectively. Southern California Edison Company was the only additional customer that provided 10% or more of the accounts receivable balance at December 31, 2010. Tennessee Valley Authority was the only additional customer that provided 10% or more of the accounts receivable balance at December 31, 2009. Unbilled revenue related to PJM was $72,887 and $40,388 at December 31, 2010 and 2009, respectively. There was no significant unbilled revenue for any other customers at December 31, 2010 and 2009.
Deposits and restricted cash consist of funds to secure performance under certain contracts and open market bidding programs with electric power grid operator and utility customers. Deposits held by these customers were $3,467 and $3,024 at December 31, 2010 and 2009, respectively. Restricted cash to secure letters of credit was $1,300 and $7,874 at December 31, 2010 and 2009, respectively. Restricted cash to secure certain other commitments was $237 and $0 at December 31, 2010 and 2009, respectively.
Property and Equipment
Property and equipment is stated at cost and depreciated using the straight-line method over the estimated useful lives of the respective assets, ranging from three to ten years. Demand response equipment is depreciated over the lesser of its useful life or the estimated C&I customer relationship period, which historically has been approximately three years. Leasehold improvements are amortized over their useful life or the life of the lease, whichever is shorter. The amortization of capital lease amounts is included in depreciation expense. Expenditures that improve or extend the life of a respective asset are capitalized while repairs and maintenance expenditures are expensed as incurred.
Software Development Costs
The Company applies the provisions of Accounting Standard Codification (ASC) 350-40 (ASC 350-40), Internal-Use Software (formerly American Institute of Certified Public Accountants (AICPA) Statement of Position (SOP) 98-1, Software Developed or Obtained for Internal Use). ASC 350-40 requires computer software costs associated with internal use software to be expensed as incurred until certain capitalization criteria are met, and it also defines which types of costs should be capitalized and which should be expensed. The Company capitalizes the payroll and payroll-related costs of employees who devote time to the development of internal-use computer software. The Company amortizes these costs on a straight-line basis over the estimated useful life of the software, which is generally two to three years. The Company’s 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.
Software development costs of $6,778, $4,162 and $3,210 for the years ended December 31, 2010, 2009 and 2008, respectively, have been capitalized in accordance with ASC 350-40. The capitalized amount was included as software in property and equipment at December 31, 2010, 2009 and 2008. The Company capitalized $1,313 and $1,541 during the years ended December 31, 2010 and 2009, respectively, related to a company-wide enterprise resource planning systems implementation project. Amortization of capitalized software development costs was $2,947, $2,311 and $1,424 for the years ended December 31, 2010, 2009 and 2008, respectively. Accumulated amortization of capitalized software development costs was $7,134 and $4,187 as of December 31, 2010 and 2009, respectively.
Impairment of Property and Equipment
The Company reviews property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of assets may not be recoverable. If these assets are considered to be impaired, the impairment is recognized in earnings and equals the amount by which the carrying value of the assets exceeds their fair market value determined by either a quoted market price, if any, or a value determined by utilizing a discounted cash flow technique. If these assets are not impaired, but their useful lives have decreased, the remaining net book value is amortized over the revised useful life.
During the three months ended December 31, 2010, the Company identified a potential impairment indicator related to certain demand response and back-up generator equipment as a result of lower than estimated demand response event performance by these assets. As a result of this potential indicator of impairment, the Company performed an impairment test during the three months ended December 31, 2010. The applicable 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. The Company determined that the undiscounted cash flows to be generated by the asset group over its remaining estimated useful life would not be sufficient to recover the carrying value of the asset group. The Company determined the fair value of the asset group using a discounted cash flow technique based on Level 3 inputs, as defined by ASC 820, Fair Value Measurements and Disclosures (ASC 820), and a discount rate of 11%, which the Company determined represents a market rate of return for the assets being evaluated for impairment. The Company determined that the fair value of the asset group was $758 compared to the carrying value of the asset group of $1,096 and, as a result, recorded an impairment charge of $338 during the three months ended December 31, 2010, which is reflected in cost of revenues in the accompanying consolidated statements of operations. The impairment charge was allocated to the individual assets within the asset group on a pro-rata basis using the relative carrying amounts of those assets.
During the three months ended September 30, 2010, the Company identified an impairment indicator related to certain demand response equipment as a result of lower than estimated demand response event performance in certain demand response programs and the removal of demand response equipment from service during the three months ended September 30, 2010. As a result of this impairment indicator, the Company performed an impairment test during the three months ended September 30, 2010 and recognized an impairment charge of $552 during the three months ended September 30, 2010, representing the difference between the carrying value and fair market value of demand response equipment, which is included in cost of revenues in the accompanying consolidated statements of operations. The fair market value was determined utilizing Level 3 inputs, as defined ASC 820, based on the projected future cash flows discounted using the estimated market participant rate of return for this type of asset.
During the three months ended June 30, 2010, the Company identified an impairment indicator related to certain demand response and back-up generator equipment as a result of lower than estimated demand response event performance by these assets. The applicable 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. The Company determined that the undiscounted cash flows to be generated by the asset group over its remaining estimated useful life would not be sufficient to recover the carrying value of the asset group. The Company determined the fair value of the asset group using a discounted cash flow technique based on Level 3 inputs, as defined by ASC 820, and a discount rate of 11%, which the Company determined to represent a market rate of return for the assets being evaluated for impairment. The Company determined that the fair
value of the asset group was $1,543 compared to the carrying value of the asset group of $2,299 and, as a result, recorded an impairment charge of $756 during the three months ended June 30, 2010, which is reflected in cost of revenues in the accompanying consolidated statements of operations. The impairment charge was allocated to the individual assets within the asset group on a pro-rata basis using the relative carrying amounts of those assets.
For the year ended December 31, 2009, the carrying value of a portion of the Company’s demand response and generation equipment exceeded the undiscounted future cash flows based upon the anticipated retirement dates. As a result, the Company recognized an impairment charge of $1,191 representing the difference between the carrying value and fair market value of demand response and generation equipment, which is included in cost of revenues in the accompanying consolidated statements of operations. The fair market value of approximately $210 was determined utilizing Level 3 inputs, as defined by ASC 820, based on the projected future cash flows discounted using the estimated market participant rate of return for this type of asset. The Company recognized an impairment charge of $701 for the year ended December 31, 2008, which is included in cost of revenues in the accompanying consolidated statements of operations.
As of December 31, 2010, approximately $2,057 of the Company’s generation equipment is utilized in open market demand response programs. The recoverability of this generation equipments’ carrying value is largely dependent on the rates that the Company is compensated for its committed capacity within these programs. These rates represent market rates and can fluctuate based on the supply and demand of capacity. Although these market rates are established up to three years in advance of the service delivery, these market rates have not yet been established for the entire remaining useful life of this generation equipment. In performing its impairment analysis, the Company estimates the expected future market rates based on current existing market rates and trends. A decline in the expected future market rates of 10% by itself would not result in an impairment charge related to this generation equipment.
Business Combinations
The Company records tangible and intangible assets acquired and liabilities assumed in business combinations under the purchase method of accounting. Amounts paid for each acquisition are allocated to the assets acquired and liabilities assumed based on their fair values at the dates of acquisition. The fair value of identifiable intangible assets is based on detailed valuations that use information and assumptions provided by the Company. The Company estimates the fair value of contingent consideration at the time of the acquisition using all pertinent information known to the Company at the time to assess the probability of payment of contingent amounts. The Company allocates any excess purchase price over the fair value of the net tangible and intangible assets acquired and liabilities assumed to goodwill.
The Company primarily uses the income approach to determine the estimated fair value of identifiable intangible assets, including customer relationships, non-compete agreements and trade names. 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. The Company bases its revenue assumptions on estimates of relevant market sizes, expected market growth rates and expected trends, including introductions by competitors of new energy management applications and services. The Company bases 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 the Company’s financial condition and results of operations.
Customer relationships represent established relationships with customers, which provide a ready channel for the sale of additional energy management applications and services. Non-compete agreements represent arrangements with certain employees that limit or prevent their ability to take employment at a competitor for a fixed period of time. Trade names represent acquired product names that the Company intends to continue to utilize.
The Company has utilized the cost approach to determine the estimated fair value of acquired indefinite-lived intangible assets related to acquired in-process research and development given the stage of development as of the acquisition date and the 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. The Company calculates the replacement cost based on actual development costs incurred through the date of acquisition. In determining the appropriate valuation methodology, the Company considers, 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. The Company believes that the estimated in-process research and development amounts so determined represent the fair value at the date of acquisition and do not exceed the amount a third party would pay for the projects.
Impairment of Intangible Assets and Goodwill
Definite-Lived Intangible Assets
The Company amortizes its intangible assets that have finite lives using either the straight-line method or, if reliably determinable, based on the pattern 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. The Company reviews its intangible assets subject to amortization to determine if any adverse conditions exist or a change in circumstances has occurred that would indicate impairment or a change in the remaining useful life. If the carrying value of an asset exceeds its undiscounted cash flows, the Company will write-down the carrying value of the intangible asset to its fair value in the period identified. In assessing recoverability, the Company must make assumptions regarding estimated future cash flows and discount rates. If these estimates or related assumptions change in the future, the Company may be required to record impairment charges. The Company generally calculates fair value as the present value of estimated future cash flows to be generated by the asset using a risk-adjusted discount rate. If the estimate of an intangible asset’s remaining useful life is changed, the Company will amortize the remaining carrying value of the intangible asset prospectively over the revised remaining useful life. During the year ended December 31, 2009, as a result of a change in the expected period of economic benefit of the trade name acquired in the acquisition of Cogent, the Company determined that an impairment indicator existed. Based on the analysis performed, the Company determined that this trade name was partially impaired and recorded an impairment charge of $135 during the year ended December 31, 2009, which is included in general and administrative expenses in the accompanying consolidated statements of operations. The fair market value of approximately $65 was determined using Level 3 inputs, as defined by ASC 820, based on the projected future cash flows over the revised period of economic benefit discounted based on the Company’s weighted average cost of capital of 17%.
The following table provides the gross carrying amount and related accumulated amortization of intangible assets as of December 31, 2010 and December 31, 2009:
The increase in patents from December 31, 2009 to December 31, 2010 was due to the allocation of purchase price related to the Smallfoot and Zox acquisition in the three months ended March 31, 2010. Amortization expense related to intangible assets amounted to $1,452, $692 and $1,019 for years ended
December 31, 2010, 2009 and 2008, respectively, and is included in general and administrative expenses in the accompanying consolidated statements of operations. The intangible asset lives range from one to ten years and the weighted average remaining life was 5.8 years at December 31, 2010. Estimated amortization is $1,136, $1,097, $1,059, $709, $644 and $1,178 for 2011, 2012, 2013, 2014, 2015 and thereafter, respectively.
Indefinite-Lived Intangible Assets
In connection with the Company’s acquisition of Smallfoot and Zox, as further discussed in Note 2, the Company acquired certain in-process research and development projects that had a fair value of $920.
An intangible asset that is deemed to have an indefinite useful life is not subject to the same impairment testing guidance as definite-lived intangible assets. The accounting guidance notes that the non-amortization of the indefinite-life asset merits a more stringent model for the measurement and recognition of impairment. Additionally, because the cash flows associated with indefinite-lived intangible assets would extend into the future indefinitely, those assets might never fail the undiscounted cash flows recoverability test that definite-lived intangible assets are subject to. As a result, the recognition of impairment losses on indefinite-lived intangible assets is based solely on a comparison of their fair value to book value, without consideration of any recoverability test.
Indefinite-lived intangible assets are to be tested for impairment annually or more frequently if events or changes in circumstances between annual tests indicate that the asset might be impaired. The impairment test requires the determination of the fair value of the intangible asset in accordance with ASC 820. If the fair value of the intangible asset is less than its carrying value, an impairment loss should be recognized in an amount equal to the difference. The asset will then be carried at its new fair value.
The Company has established November 30 as its annual impairment test date for its current indefinite-lived intangible assets. The Company completed its annual impairment test as of November 30, 2010. In order to complete the annual impairment test for Smallfoot’s in-process research and development project that relates to the development of wireless systems that manage and coordinate electricity demand for small commercial facilities, the Company utilized the income approach to assess whether the carrying value of the asset was impaired. The Company determined that the fair value exceeded the carrying value, and therefore, no impairment existed. In order to complete the annual impairment test for Zox, the Company used the cost approach to value the acquired in-process research and development project that relates to the development of hardware and software for automated utility meter reading. The cost approach calculates fair value by calculating the reproduction cost of an exact replica of the subject intangible asset. The Company calculated the replacement cost based on actual development costs incurred through the date of acquisition. Given the stage of development as of November 30, 2010 and the current lack of sufficient information regarding future expected cash flows, the Company determined that the cost approach was the most reliable valuation methodology to determine whether impairment existed. The Company concluded that the Zox technology’s fair value exceeded the carrying value and therefore, no impairment existed.
Goodwill
In accordance with ASC 350 (ASC 350), Intangibles - Goodwill and Other (formerly the Financial Accounting Standards Board (FASB) SFAS No. 142, Goodwill and Other Intangible Assets), the Company tests 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. The Company has determined that the reporting unit level is the entity level as discrete financial information is not available at a lower level and its chief operating decision maker, which is its chief executive officer and executive management team, collectively, make business decisions based on the evaluation of financial information at the entity level. 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. The Company’s annual impairment test date is November 30.
In performing the test, the Company utilizes the two-step approach prescribed under ASC 350. The first step requires a comparison of the carrying value of the reporting units, as defined, to the fair value of these units. The second step of the goodwill impairment test compares the implied fair value of a reporting unit’s goodwill to its carrying value.
The Company conducted its annual impairment test as of November 30, 2010. The fair value of the entity is determined by use of a market approach based on the quoted market price of its common stock and the number of shares outstanding. The Company believes that it is not at risk of failing the first step of the goodwill impairment test.
As a result of completing the first step, the fair value exceeded the carrying value, and as such the second step of the impairment test was not required. To date, the Company has not been required to perform the second step of the impairment test.
The estimate of fair value requires significant judgment. Any loss resulting from an impairment test would be reflected in operating loss in the Company’s 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, the Company may be required to record impairment charges for these assets not previously recorded.
The following table shows the change of the carrying amount of goodwill from December 31, 2008 to December 31, 2010:
Income Taxes
The Company uses the asset and liability method for accounting for income taxes. Under this method, the Company determines deferred tax assets and liabilities based on the difference between financial reporting and taxes bases of its assets and liabilities. The Company records its deferred tax assets and liabilities using enacted tax rates and laws that will be in effect when the Company expects the differences to reverse.
The Company has incurred consolidated net losses since its inception and, as a result, the Company has not recognized net United States deferred tax assets as of December 31, 2010 or 2009. The Company’s deferred tax liabilities primarily relate to deferred taxes associated with the Company’s acquisitions and property and equipment. The Company’s deferred tax assets relate primarily to net operating loss carryforwards, accruals and reserves, and stock-based compensation. The Company records a valuation allowance to reduce its deferred tax assets to the amount that is more likely than not to be realized. While the Company has considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowance, in the event the Company were to determine that the Company would be able to realize its deferred tax assets in the future in excess of the net recorded amount, an adjustment to the deferred tax asset would increase income in the period such determination was made.
ASC 740 (ASC 740), Income Taxes (formerly FASB Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109), prescribes a recognition threshold and measurement criteria for the financial statement recognition and measurement of a tax position 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.
The Company had no unrecognized tax benefits as of December 31, 2010 and 2009.
In the ordinary course of global business, there are many transactions and calculations where the ultimate tax outcome is uncertain. Judgment is required in determining the Company’s worldwide income tax provision. In the Company’s opinion, it is not required that the Company has a provision for income taxes for any years subject to audit. Although the Company believes its estimates are reasonable, no assurance can be given that the final tax outcome of matters will not be different than that which is reflected in the Company’s historical income tax provisions and accruals. In the event the Company’s assumptions are incorrect, the differences could have a material impact on its income tax provision and operating results in the period in which such determination is made.
Industry Segment Information
The Company is required to disclose the standards for reporting information about operating segments in annual financial statements and required selected information of these segments being presented in interim financial reports issued to stockholders. Operating segments are defined as components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in making decisions on how to allocate resources and assess performance. The Company’s chief decision maker is considered to be the team comprised of the chief executive officer and the executive management team. The Company views its operations and manages its business as one operating segment.
For the years ended December 31, 2010, 2009 and 2008, operations related to the Company’s international subsidiaries were not material to the accompanying consolidated financial statements taken as a whole. In addition, as of December 31, 2010 and 2009, the long-lived assets related to the Company’s international subsidiaries were not material to the accompanying consolidated financial statements taken as a whole.
Revenue Recognition
The Company recognizes revenues in accordance with ASC 605, Revenue Recognition (formerly Staff Accounting Bulletin No. 104, Revenue Recognition in Financial Statements, and Emerging Issues Task Force (EITF) Issue No. 00-21, Accounting for Revenue Arrangements with Multiple Deliverables). In all of the Company’s arrangements, it does not recognize any revenues until persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and it deems collection to be reasonably assured. In making these judgments, the Company evaluates these criteria as follows:
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Evidence of an arrangement. The Company considers a definitive agreement signed by the customer and the Company or an arrangement enforceable under the rules of an open market bidding program to be representative of persuasive evidence of an arrangement.
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Delivery has occurred. The Company considers delivery to have occurred when service has been delivered to the customer and no post-delivery obligations exist. In instances where customer acceptance is required, delivery is deemed to have occurred when customer acceptance has been achieved.
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Fees are fixed or determinable. The Company considers 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 the Company cannot reliably estimate this amount, the Company recognizes revenues when the right to a refund or adjustment lapses. If offered payment terms significantly exceed its normal terms, the Company recognizes revenues as the amounts become due and payable or upon the receipt of cash.
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Collection is reasonably assured. The Company conducts a credit review at the inception of an arrangement to determine the creditworthiness of the customer. Collection is reasonably assured if, based upon evaluation, the Company expects that the customer will be able to pay amounts under the arrangement as payments become due. If the Company determines that collection is not reasonably assured, revenues are deferred and recognized upon the receipt of cash.
The Company enters into agreements and open market bidding programs to provide demand response services. Demand response revenues are earned based on the Company’s ability to deliver committed capacity. Energy event revenue, which reflects additional payments made to the Company for the amount of energy usage it actually curtails from the grid, is contingent revenue earned based upon the actual amount of energy provided during the demand response event.
The Company recognizes demand response revenue when it has provided verification to the electric power grid operator or utility of its ability to deliver the committed capacity, which entitles it to payments under the agreement or open market bidding program. Committed capacity is verified through the results of an actual demand response event or a measurement and verification test. Once the capacity amount has been generally verified, the revenue is recognized and future revenue becomes fixed or determinable and is recognized monthly until the next demand response event or test. In subsequent verification events, if the Company’s verified capacity is below the previously verified amount, the electric power grid operator or utility customer will reduce future payments based on the adjusted verified capacity amounts. Ongoing demand response revenue recognized between demand response events or tests that are not subject to penalty or refund are recognized in revenue. If the revenue is subject to refund and the amount of refund cannot be reliably estimated, the revenue is deferred until the right of refund lapses.
Certain of the forward capacity programs in which the Company participates may be deemed derivative contracts under ASC 815 (ASC 815), Derivatives and Hedging (formerly SFAS No. 133, Accounting for Derivative and Hedging Activities). In such situations, the Company believes it meets the scope exception under ASC 815 as a normal purchase, normal sale as that term is defined in ASC 815 and, accordingly, the arrangement is not treated as a derivative contract.
Revenue from energy events is recognized when earned. Energy event revenue is deemed to be substantive and represents the culmination of a separate earnings process and is recognized when the energy event is initiated by the customer and the Company has responded under the terms of the agreement or open market program.
In addition to demand response revenues, the Company generally receives either a subscription-based fee, consulting fee or a percentage savings fee for arrangements under which it provides its EfficiencySMART, SupplySMART and CarbonSMART applications and services. The Company generally recognizes these revenues over the service delivery period as the services are delivered. If the revenue is subject to refund and the amount of refund cannot be determined, the revenue is deferred until the right of refund lapses.
Cost of Revenues
Cost of revenues for demand response services consists primarily of payments made to the Company’s C&I customers for their participation in the demand response network. The Company generally enters into one to five year contracts with C&I customers under which it delivers recurring cash payments to them for the capacity they commit to make available on demand. The Company also generally makes an additional payment when a C&I customer reduces consumption of energy from the electric power grid. The equipment and installation costs for devices, which monitor energy usage, communicate with sites and, in certain instances, remotely control energy usage to achieve committed capacity, at C&I customer sites are capitalized and depreciated over the lesser of the remaining estimated C&I customer relationship period, or the estimated useful life of the equipment, and this depreciation is reflected in cost of revenues. The Company also includes in cost of revenues the monthly telecommunications and data costs incurred as a result of being connected to C&I customer sites and internal payroll and related costs allocated to a C&I customer site. Cost of revenues for EfficiencySMART, SupplySMART and CarbonSMART applications and services include third party
services, equipment depreciation and the wages and associated benefits that the Company pays to its project managers for the performance of their services.
Research and Development Expenses
Research and development expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to the Company’s research and development organization, (b) payments to suppliers for design and consulting services, (c) costs relating to the design and development of new energy management applications and services and enhancement of existing energy management applications and services, (d) quality assurance and testing and (e) other related overhead. Costs incurred in research and development are expensed as incurred.
Stock-Based Compensation
As of December 31, 2010, the Company had one stock-based compensation plan, which is more fully described in Note 9 below. Generally, the Company grants stock-based awards with exercise prices equal to the estimated fair value of its common stock; however, to the extent that the deemed fair value of the common stock exceeded the exercise or purchase price of stock-based awards granted to employees on the date of grant, the Company amortizes the expense over the vesting schedule of the awards, generally four years.
For stock options granted prior to January 1, 2009, the fair value of each option was estimated at the date of grant using a Black-Scholes option-pricing model. For stock options granted on or after January 1, 2009, the fair value of each option has been and will be estimated on the date of grant using a lattice valuation model. The lattice model considers characteristics of fair value option pricing that are not available under the Black-Scholes model. Similar to the Black-Scholes model, the lattice model takes into account variables such as expected volatility, dividend yield rate, and risk free interest rate. However, in addition, the lattice model considers the probability that the option will be exercised prior to the end of its contractual life and the probability of termination or retirement of the option holder in computing the value of the option. For these reasons, the Company believes that the lattice model provides a fair value that is more representative of actual experience and future expected experience than that value calculated using the Black-Scholes model. Stock-based compensation for the years ended December 31, 2010, 2009 and 2008 was $15,742, $13,134 and $10,439, respectively. For additional information regarding stock-based compensation, see Note 9.
The Company accounts for transactions in which services are received from non-employees in exchange for equity instruments based on the fair value of such services received or of the equity instruments issued, whichever is more reliably measurable. During the years ended December 31, 2010, 2009 and 2008, the Company recognized $20, $27 and $62, respectively, of stock-based compensation to non-employees.
Foreign Currency Translation
The financial statements of the Company’s international subsidiaries are translated in accordance with ASC 830, Foreign Currency Matters (formerly SFAS No. 52, Foreign Currency Translation), into the Company’s reporting currency, which is the United States dollar. The functional currencies of the Company’s subsidiaries in Canada and the United Kingdom are the Canadian dollar and the British pound, respectively. Assets and liabilities are translated to the United States dollar from the local functional currency at the exchange rate in effect at each balance sheet date. Before translation, the Company re-measures foreign currency denominated assets and liabilities, including inter-company accounts receivable and payable, into the functional currency of the respective entity, resulting in unrealized gains or losses recorded in other (expense) income, net in the consolidated statement of operations. Revenues and expenses are translated using average exchange rates during the respective period. Foreign currency translation adjustments are recorded as a component of other comprehensive loss and included in accumulated other comprehensive loss within stockholders’ equity. Losses arising from transactions denominated in foreign currencies are included in other (expense) income, net on the consolidated statements of operations and were $133, $29 and $0 for the years ended December 31, 2010, 2009 and 2008, respectively.
Comprehensive Income (Loss)
Comprehensive income (loss) is defined as the change in equity of a business enterprise during a period resulting from transactions and other events and circumstances from non-owner sources. Comprehensive income (loss) is composed of net income (loss) and foreign currency translation adjustments. As of December 31, 2010 and 2009, accumulated other comprehensive income (loss) was comprised solely of cumulative foreign currency translation adjustments. The Company presents its components of other comprehensive income, net of related tax effects, which have not been material to date.
Recent Accounting Pronouncements
In September 2009, the FASB ratified ASC Update No. 2009-13, Multiple-Deliverable Revenue Arrangements (ASU 2009-13). ASU 2009-13 amends existing revenue recognition accounting pronouncements that are currently within the scope of FASB ASC Subtopic 605-25 (previously included within EITF Issue No. 00-21, Revenue Arrangements with Multiple Deliverables (EITF 00-21)). ASU 2009-13 provides for two significant changes to the existing multiple element revenue recognition guidance. First, ASU 2009-13 deletes the requirement to have objective and reliable evidence of fair value for undelivered elements in an arrangement and will result in more deliverables being treated as separate units of accounting. The second change modifies the manner in which the transaction consideration is allocated across the separately identified deliverables. ASU 2009-13 may result in entities recognizing more revenue up-front, and entities will no longer be able to apply the residual method and defer the fair value of undelivered elements. Upon adoption of ASU 2009-13, each separate unit of accounting must have a selling price, which can be based on management’s estimate when there is no other means to determine the fair value of that undelivered item, and the arrangement consideration is allocated based on the elements’ relative selling price. ASU 2009-13 is effective no later than fiscal years beginning on or after June 15, 2010 but may be adopted early as of the first quarter of an entity’s fiscal year. Entities may elect to adopt ASU 2009-13 either through prospective application to all revenue arrangements entered into or materially modified after the date of adoption or through a retrospective application to all revenue arrangements for all periods presented in the financial statements. The Company will adopt ASU 2009-13 on a prospective basis for all revenue arrangements entered into or materially modified after January 1, 2011. The Company does not expect the adoption of ASU 2009-13 will have a material impact on its consolidated financial condition or results of operations.
In January 2010, the FASB issued ASU 2010-06, Improving Disclosure about Fair Value Measurements (ASU 2010-06). ASU 2010-06 requires additional disclosures regarding fair value measurements, amends disclosures about post-retirement benefit plan assets and provides clarification regarding the level of disaggregation of fair value disclosures by investment class. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for certain Level 3 activity disclosure requirements that are effective for reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not have a material impact on the Company’s consolidated financial position or results of operations.
2.
Acquisitions
SmallFoot LLC and ZOX, LLC
In March 2010, the Company acquired substantially all of the assets and certain liabilities of Smallfoot and Zox, which were companies unaffiliated with the Company but were entities under common control. Smallfoot was in the process of developing wireless systems that manage and coordinate electricity demand for small commercial facilities and Zox was in the process of developing hardware and software for automated utility meter reading. The total purchase price paid by the Company at closing was approximately $1,360, of which $1,100 was paid in cash and the remainder of which was paid by the issuance of 8,758 shares of the Company’s common stock that had a fair value of approximately $260. These shares were measured as of the acquisition date using the closing price of the Company’s common stock, as reported on The NASDAQ Global Market (NASDAQ) on March 15, 2010. The Company believes that Smallfoot’s technology will reduce deployment costs and accelerate deeper market penetration into C&I customers, specifically smaller C&I customers. The Company believes Zox’s smart grid communications and metering technology provides a
platform for transforming electric industry legacy meters into smart meters at a substantially lower cost as compared to traditional replacement methods.
Although Smallfoot and Zox were development stage entities as of the acquisition close date, these entities met the definition of a business as defined under ASC 805, Business Combinations (ASC 805), as these entities had inputs and processes that have the ability to provide a return to its owners. As a result, this acquisition was treated as a business combination in accordance with ASC 805.
Transaction costs related to this business combination were not material and have been expensed as incurred. The transaction costs are included in general and administrative expenses in the accompanying consolidated statements of operations.
The allocation of the purchase price is based upon estimates of the fair value of assets acquired and liabilities assumed as of March 15, 2010. There were no net tangible assets acquired in connection with this acquisition. The components and allocation of the purchase price consists of the following approximate amounts:
As part of the purchase price allocation, the Company determined that the identifiable intangible assets include two in-process research and development projects and certain acquired patents.
The Company used the cost approach to value the two acquired in-process research and development projects that related to the development of wireless systems that manage and coordinate electricity demand for small commercial facilities and the development of hardware and software for automated utility meter reading, but had not yet reached technological feasibility and had no alternate future uses as of the acquisition date. The primary basis for determining the technological feasibility of these projects is the completion of a working model that performs all the major functions planned for the product and is ready for initial customer testing, usually identified as beta testing. ASC 805 requires that purchased research and development acquired in a business combination be recognized as an indefinite-lived intangible asset until the completion or abandonment of the associated research and development efforts. The cost approach calculates fair value by calculating the reproduction cost of an exact replica of the subject intangible asset. The Company calculated the replacement cost based on actual development costs incurred through the date of acquisition. In determining the appropriate valuation methodology, the Company considered, 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. Given the stage of development as of the acquisition date and the current lack of sufficient information regarding future expected cash flows, the Company determined that the cost approach was the most reliable valuation methodology to determine the fair value of the in-process research and development projects acquired. The Company believes that the estimated in-process research and development amounts so determined represent the fair value at the date of acquisition and do not exceed the amount a third party would pay for the projects. However, if the projects are not successful or completed in a timely manner, the Company may not realize the financial benefits expected for these projects or for the acquisition as a whole.
The estimated cost to complete the in-process research and development projects in the aggregate as of December 31, 2010 was approximately $840.
The Company used the income approach to value the acquired patents. The discount rate in connection with this valuation was 25% and was based on the commercial and technical risks related to this asset and on estimated market participant discount rates for a similar asset.
The factors contributing to the recognition of goodwill were based upon several strategic and synergistic benefits that were expected to be realized from the combination.
Cogent Energy, Inc.
In December 2009, the Company acquired all of the outstanding capital stock of Cogent, a company specializing in comprehensive energy consulting, engineering and building commissioning solutions to C&I customers. The total purchase price paid by the Company at closing was approximately $11,172, of which $6,555 was paid in cash and the remainder of which was paid by the issuance of 114,281 shares of the Company’s common stock that had a fair value of approximately $3,162. These shares were measured as of the acquisition date using the closing price of the Company’s common stock, as reported on NASDAQ on December 4, 2009. As a result of gathering information to update the Company’s valuation of certain acquired assets and liabilities, the purchase price was reduced by $94 during 2010 through the release back to the Company of 3,592 shares of the Company’s common stock that were previously held in escrow in connection with the Cogent acquisition. Upon release, the Company’s board of directors approved the retirement of these shares.
In addition to the amounts paid at closing, the Company was obligated to pay an earn-out amount of $1,500 to the former stockholders of Cogent. The earn-out payment was based on the achievement of a certain minimum revenue-based milestone and a certain earnings-based milestone of Cogent for the year ended December 31, 2010 and was paid in cash in January 2011.
Transaction costs related to this business combination were not material and were expensed as incurred. The transaction costs are included in general and administrative expenses.
The components and allocation of the purchase price consist of the following approximate amounts:
Net tangible assets acquired in the acquisition of Cogent primarily related to the following:
eQuilibrium Solutions Corporation
In June 2009, the Company acquired substantially all of the assets of eQ, a software company specializing in the development of enterprise sustainability management products and services. The total purchase price paid by the Company at closing was approximately $751, of which $250 was paid in cash and the remainder of which was paid by the issuance of 21,464 shares of the Company’s common stock that had a value of approximately $501. These shares were measured as of the acquisition date using the closing price of the Company’s common stock, as reported on NASDAQ on June 11, 2009.
Transaction costs related to this business combination were not material and were expensed as incurred. The transaction costs are included in general and administrative expenses. The Company’s consolidated financial statements reflect eQ’s results of operations from June 11, 2009 forward.
South River Consulting, LLC
In May 2008, the Company acquired 100% of the membership interests of SRC, an energy procurement and risk management services provider, for a purchase price equal to $5,524, which consisted of $3,603 in cash, $174 in related expenses and the issuance of 120,000 shares of the Company’s common stock that had a value of approximately $1,747 as of the closing date. In addition to the amounts paid at closing, the Company incurred a contingent obligation to pay to the former holders of SRC membership interests an earn-out amount equal to 50% to 60% of the revenues of SRC’s business during each twelve-month period from May 1, 2008 through April 30, 2010, which would be recognized as additional purchase price when earned. The earn-out payments were based on the achievement of certain minimum revenue-based milestones of SRC, paid in a combination of cash and shares of the Company’s common stock and recorded as additional purchase price. The additional purchase price recorded in the three months ended June 30, 2009, which was related to the May 1, 2008 to April 30, 2009 earn-out period, totaled $1,468, of which $734 was paid in cash during 2009 and the remainder of which was paid by the issuance of 44,776 shares of the Company’s common stock. The additional purchase price recorded in 2010, which was related to the May 1, 2009 to April 30, 2010 earn-out period, totaled $1,840, of which $901 was paid in cash, $39 was settled through a reduction of a receivable due to the Company from the former holders of SRC membership interests and the remainder of which was paid by the issuance of 30,879 shares of the Company’s common stock with a fair value of $900.
Pro forma information relating to the above acquisitions has not been provided since the impact to the consolidated financial statements was not material.
3.
Net Loss Per Share
A reconciliation of basic and diluted share amounts for the years ended December 31, 2010, 2009 and 2008 are as follows:
In the reporting period in which the Company has reported net income, anti-dilutive shares comprise those common stock equivalents that have either an exercise price above the average stock price for the quarter or the common stock equivalent’s related average unrecognized stock compensation expense is sufficient to “buy back” the entire amount of shares. In those reporting periods in which the Company has a net loss, anti-dilutive shares comprise the impact of those number of shares that would have been dilutive had the Company had net income plus the number of common stock equivalents that would be anti-dilutive had the Company had net income.
The Company excludes the shares issued in connection with restricted stock awards from the calculation of basic weighted average common shares outstanding until such time as those shares vest. In addition, in connection with certain of the Company’s business combinations, the Company has issued shares that were held in escrow upon closing of the applicable business combination. The Company excludes shares held in escrow from the calculation of basic weighted average common shares outstanding where the release of such shares is contingent upon an event and not solely subject to the passage of time.
4.
Fair Value Measurements
ASC 820 establishes a fair value hierarchy that requires the use of observable market data, when available, and prioritizes the inputs to valuation techniques used to measure fair value in the following categories:
•
Level 1 - Valuation is based upon quoted prices for identical instruments traded in active markets. Level 1 instruments include securities traded on active exchange markets, such as the New York Stock Exchange.
•
Level 2 - Valuation is based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active and model-based valuation techniques for which all significant assumptions are observable in the market.
•
Level 3 - Valuation is generated from model-based techniques that use significant assumptions not observable in the market. These unobservable assumptions reflect the Company’s own estimates of assumptions market participants would use in pricing the asset or liability.
The table below presents the balances of assets and liabilities measured at fair value on a recurring basis at December 31, 2010:
(1)
Included in cash and cash equivalents in the accompanying consolidated balance sheets.
(2)
Included in restricted cash in the accompanying consolidated balance sheets.
With respect to assets measured at fair value on a non-recurring basis, which would be impaired long-lived assets, refer to Note 1 for discussion of the determination of fair value of these assets. With respect to liabilities measured at fair value on a non-recurring basis, which would be contingent consideration liability, refer to Note 2 for discussion of the determination of fair value of this liability.
At December 31, 2010, the Company had restricted cash of approximately $1,300 invested in certificates of deposit and $237 of cash collateralizing certain other commitments. All certificates of deposit have contractual maturities of twelve months or less. The Company’s investments in certificates of deposit have a fair value that approximates cost.
The carrying amounts of cash and cash equivalents, restricted cash, trade accounts receivable, accounts payable and accrued expenses included in the consolidated balance sheets approximate fair value given the short-term nature of these financial instruments.
5.
Allowance for Doubtful Accounts
The Company reduces gross trade accounts receivable by an allowance for doubtful accounts. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company reviews its allowance for doubtful accounts on a regular basis and all past due balances are reviewed individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Provisions for allowance for doubtful accounts are recorded in general and administrative expenses. Below is a summary of the changes in the Company’s allowance for doubtful accounts for the years ended December 31, 2010, 2009 and 2008.
6.
Property and Equipment
Property and equipment as of December 31, 2010 and December 31, 2009 consisted of the following:
Depreciation expense was $14,414, $11,357 and $8,035 for the years ended December 31, 2010, 2009 and 2008, respectively. For the years ended December 31, 2010, 2009 and 2008, $9,907, $5,415 and $3,193, respectively, were included in cost of revenues, and $4,507, $5,942 and $4,842, respectively, were included in general and administrative expenses. The amortization expense related to assets under capital leases was included within the Company’s depreciation expense for the years ended December 31, 2010, 2009 and 2008. As of December 31, 2010 and 2009, total accumulated amortization expense related to assets under capital leases was $182 and $142, respectively.
7.
Financing Arrangements
Pursuant to the terms of the Credit Facility, SVB will, among other things, make revolving credit and term loan advances and issue letters of credit for the Company’s account. The interest on loans under the Company’s revolving credit loan accrues at interest rates based upon either SVB’s prime rate or the 30, 60 or 90-day LIBOR plus 2.25%, at the Company’s election. The interest on term loans accrues at SVB’s prime rate plus 0.50% or the 30, 60 or 90-day LIBOR plus 2.75%, at the Company’s election. The term advance is payable in thirty-six consecutive equal monthly installments of principal, calculated by SVB, based upon the amount of the term advance and an amortization schedule equal to thirty-six months. All unpaid principal and accrued interest is due and payable in full on March 31, 2011, which is the maturity date. In connection with the issuance or renewal of letters of credit for the Company’s account, the Company is charged a letter of credit fee of 1.25%. The Company expenses the interest and letter of credit fees, as applicable, in the period incurred.
The Company’s obligations under the Credit Facility are secured by all of the assets of the Company and its subsidiaries, excluding any intellectual property. The Credit Facility contains customary terms and conditions for credit facilities of this type, including restrictions on the Company’s ability to incur additional
indebtedness, create liens, enter into transactions with affiliates, transfer assets, pay dividends or make distributions on, or repurchase, the Company’s stock, consolidate or merge with other entities, or suffer a change in control. In addition, the Company is required to meet certain financial covenants customary with this type of credit facility, including maintaining a minimum specified tangible net worth and a minimum specified ratio of current assets to current liabilities. The Credit Facility contains customary events of default, including payment defaults, breaches of representations, breaches of affirmative or negative covenants, cross defaults to other material indebtedness, bankruptcy and failure to discharge certain judgments. If a default occurs and is not cured within any applicable cure period or is not waived, the Company’s obligations under the Credit Facility may be accelerated. The Company was in compliance with all financial covenants under the Credit Facility at December 31, 2010 and December 31, 2009.
In October 2009, the Company repaid the outstanding borrowings of $4,442 under the Credit Facility. The Company incurred financing costs of $120 in connection with the Credit Facility, which were deferred and are being amortized to interest expense over the life of the Credit Facility, which matures on March 31, 2011. At December 31, 2010, the Company had no borrowings and letters of credit totaling $36,561 outstanding under the Credit Facility.
In April 2010, the Company and one of its subsidiaries entered into a second loan modification agreement to the Credit Facility, which increased the Company’s borrowing limit from $35,000 to $50,000, as well as modified certain of its financial covenant debt compliance requirements. In July 2010, the Company and one of its subsidiaries entered into a third loan modification agreement to the Credit Facility, which extended the maturity date of the Credit Facility from August 5, 2010 to February 4, 2011, as well as modified certain of the Company’s financial covenant compliance requirements. In February 2011, the Company and SVB further extended the maturity date of the Credit Facility through March 31, 2011.
The Company leases certain of its office equipment under non-cancelable capital leases, which expire through 2011. The majority of the office equipment leases require payments for additional expenses such as taxes. The following is a summary of debt and capital leases as of December 31, 2010 and 2009:
8.
Stockholders’ Equity
Follow-On Public Offering
During the third quarter of 2009, the Company completed an underwritten public offering of an aggregate of 3,963,889 shares of common stock at an offering price of $27.00 per share, which included the sale of 709,026 shares by certain selling stockholders. After deducting underwriting discounts and commissions and offering expenses payable by the Company, the Company received net proceeds of approximately $83,421 from the offering.
Preferred Stock
In May 2007, the Company’s board of directors approved an amendment and restatement of the Company’s Certificate of Incorporation to increase the authorized number of shares of common stock to 50,000,000, to authorize 5,000,000 shares of undesignated preferred stock, and to eliminate all references to the designated Series Preferred Stock.
Common Stock
At December 31, 2010, the Company has authorized 50,000,000 shares of common stock, of which 25,155,067 shares were issued and outstanding and 1,946,749 shares have been reserved for issuance under the Company’s Amended and Restated 2007 Employee, Director and Consultant Stock Plan (the 2007 Plan).
9.
Stock-Based Compensation
Stock Options
The Company’s Amended and Restated 2003 Stock Option and Incentive Plan (2003 Plan) and the 2007 Plan (collectively, the Plans) provide for the grant of incentive stock options, nonqualified stock options, restricted and unrestricted stock awards and other stock-based awards to eligible employees, directors and consultants of the Company. Options granted under the Plans are exercisable for a period determined by the Company, but in no event longer than ten years from the date of the grant. Option awards are generally granted with an exercise price equal to the market price of the Company’s common stock on the date of grant. Options, restricted stock awards and restricted stock unit awards generally vest ratably over four years, with certain exceptions. The 2003 Plan expired upon the Company’s initial public offering (IPO) in May 2007. Any forfeitures under the 2003 Plan that occurred after the effective date of the IPO are available for future grant under the 2007 Plan up to a maximum of 1,000,000 shares. The 2007 Plan provides for an annual increase to the shares issuable under the 2007 Plan by an amount equal to the lesser of 520,000 shares or an amount determined by the Company’s board of directors. This annual increase is effective on the first day of each fiscal year through 2017. During the year ended December 31, 2010 and 2009, the Company issued 24,681 shares of its common stock and 45,085 shares of its common stock, respectively, to certain executives to satisfy a portion of the Company’s compensation obligations to those individuals. As of December 31, 2010, 1,946,749 shares were available for future grant under the 2007 Plan.
For stock options granted prior to January 1, 2009, the fair value of each option was estimated at the date of grant using a Black-Scholes option-pricing model. For stock options granted on or after January 1, 2009, the fair value of each option has been and will be estimated on the date of grant using a lattice valuation model. The lattice valuation model considers characteristics of fair value option pricing that are not available under the Black-Scholes option pricing model. Similar to the Black-Scholes option pricing model, the lattice valuation model takes into account variables such as expected volatility, dividend yield rate, and risk free interest rate. However, in addition, the lattice valuation model considers the probability that the option will be exercised prior to the end of its contractual life and the probability of termination or retirement of the option holder in computing the value of the option. For these reasons, the Company believes that the lattice model provides a fair value that is more representative of actual experience and future expected experience than that value calculated using the Black-Scholes option pricing model.
The fair value of options granted was estimated at the date of grant using the following weighted average assumptions:
(1)
Change in assumptions reflects the Company’s use of a lattice valuation model as of January 1, 2009.
Volatility measures the amount that a stock price has fluctuated or is expected to fluctuate during a period. As there was no public market for the Company’s common stock prior to the effective date of the IPO, the Company determined the volatility based on an analysis of reported data for a peer group of companies that issued options with substantially similar terms. The expected volatility of options granted through September 30, 2010 was determined using an average of the historical volatility measures of this peer group of companies. During the three months ended September 30, 2010, the Company determined that it had sufficient history to utilize Company-specific volatility in accordance with ASC 718, Stock Compensation (ASC
718) and is now calculating volatility using a component of implied volatility and historical volatility to determine the value of share-based payments. The risk-free interest rate is the rate available as of the option date on zero-coupon United States government issues with a term equal to the expected life of the option. During the three months ended March 31, 2010, the Company changed its vesting for new grants of stock options and restricted stock to a 25% cliff vest after one year of grant and quarterly thereafter for three years as compared to its primary vesting for historical grants of 25% cliff vest after one year of grant and monthly thereafter for three years. The change in vesting resulted in the vesting term changing in 2010 for new grants awarded with this new vesting. The Company has not paid dividends on its common stock in the past and does not plan to pay any dividends in the foreseeable future. In addition, the terms of the Credit Facility preclude the Company from paying dividends. During the year ended December 31, 2010, the Company updated its estimated exit rate pre-vesting and post-vesting applied to options, restricted stock and restricted stock units based on an evaluation of demographics of its employee groups and historical forfeitures for these groups in order to determine its option valuations as well as its stock-based compensation expense. The changes in estimate of the volatility, exit rate pre-vesting and exit rate post-vesting did not have a material impact on the Company’s stock-based compensation expense recorded in the accompanying consolidated statements of operations for the year ended December 31, 2010.
The Company accounts for transactions in which services are received from non-employees in exchange for equity instruments based on the fair value of such services received or of the equity instruments issued, whichever is more reliably measurable.
The components of stock-based compensation expense are disclosed below:
Stock based compensation is recorded in the accompanying statements of operations, as follows:
The Company recognized no material income tax benefit from share-based compensation arrangements during the years ended December 31, 2010, 2009 and 2008. In addition, no material compensation cost was capitalized during the years ended December 31, 2010, 2009 and 2008.
The following is a summary of the Company’s stock option activity during the year ended December 31, 2010:
(1)
This represents the number of vested options as of December 31, 2010 plus the number of unvested options expected to vest as of December 31, 2010 based on the unvested options outstanding at December 31, 2010, adjusted for the estimated forfeiture rate of 5.95%.
(2)
The aggregate intrinsic value was calculated based on the positive difference between the estimated fair value of the Company’s common stock on December 31, 2009 of $30.39 and the exercise price of the underlying options.
(3)
The aggregate intrinsic value was calculated based on the positive difference between the fair value of the Company’s common stock on the applicable exercise dates and the exercise price of the underlying options.
(4)
The aggregate intrinsic value was calculated based on the positive difference between the estimated fair value of the Company’s common stock on December 31, 2010 of $23.91 and the exercise price of the underlying options.
In December 2008, the Company’s board of directors approved a one-time offer to the Company’s employees, including its executive officers, and directors to exchange option grants that had an exercise price per share that was equal to or greater than the higher of $12.00 or the closing price of the Company’s common stock as reported on NASDAQ on January 21, 2009 (the Exchange). The Exchange closed on January 21, 2009, and the Company exchanged options that had exercise prices equal to or greater than $12.00 per share. As a result, an aggregate of 744,401 options, with exercise prices ranging from $12.27 to $48.54 per share, were exchanged for 424,722 options with an exercise price per share of $8.63 for employees who are not also executive officers of the Company, 142,179 options with an exercise price per share of $11.47 for executive officers who are not also directors of the Company and 45,653 options with an exercise price per share of $12.94 for the Company’s directors. On the date of the Exchange, the estimated fair value of the new options did not exceed the fair value of the exchanged stock options calculated immediately prior to the Exchange. As such, there was no incremental fair value of the new options, and the Company will not record additional compensation expense related to the Exchange. The Company will continue to recognize the remaining compensation expense related to the exchanged options over the remaining vesting period of the original options.
Additional Information About Stock Options
(1)
Represents the difference between the market price at exercise and the price paid to exercise the options.
Of the stock options outstanding as of December 31, 2010, 2,098,366 options were held by employees and directors of the Company and 13,993 options were held by non-employees. For outstanding unvested stock options related to employees as of December 31, 2010, the Company had $10,954 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.3 years. There were no material unvested non-employee options as of December 31, 2010.
Restricted Stock and Restricted Stock Units
For non-vested restricted stock and restricted stock units outstanding as of December 31, 2010, the Company had $14,376 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.7 years.
Restricted Stock
The following table summarizes the Company’s restricted stock activity during the year ended December 31, 2010:
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. Included in the above table are 3,500 shares of restricted stock granted to certain non-executive employees during the year ended December 31, 2010 that were immediately vested. The fair value of the restricted stock is expensed ratably over the vesting period. The shares of restricted stock have been issued at no cost to the recipients, except for 152,460 shares of restricted stock granted in 2006 that were purchased for $0.51 per share. The Company records any proceeds received for unvested shares of restricted stock in accrued expenses and the amount is amortized into additional paid-in capital as the shares vest. 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.
Additional Information About Restricted Stock
Restricted Stock Units
The following table summarizes the Company’s restricted stock unit activity during the year ended December 31, 2010:
Prior to 2009, the Company had not granted any restricted stock units and there were no restricted stock units that vested in 2009.
The weighted average grant date fair value of restricted stock units granted during the year ended December 31, 2010 was $28.99 per share. The total fair value of restricted stock units that vested during the year ended December 31, 2010 was $1,637. The weighted average grant date fair value of restricted stock granted during the year ended December 31, 2009 was $11.55 per share.
10.
Income Taxes
The Company accounts for income taxes using the liability method as required by ASC 740, Income Taxes. Under this method, deferred income taxes are recognized for the future tax consequences of differences between the tax and financial accounting bases of assets and liabilities at the end of each reporting period. Deferred income taxes are based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. A valuation allowance is established when necessary to reduce deferred tax assets to the amounts expected to be realized.
Domestic and foreign pre-tax income (loss) is as follows:
The provision for income taxes is as follows:
Amounts due to various states for non-income taxes are included in general and administrative expenses and accrued expenses and other current liabilities as of December 31, 2010, 2009 and 2008.
A reconciliation of income tax expense (benefit) at the statutory federal income tax rate and income taxes as reflected in the consolidated financial statements is as follows:
Deferred tax assets (liabilities) consisted of the following:
Due to the uncertainty related to the ultimate use of the Company’s U.S. deferred income tax assets, the Company has provided a full valuation allowance for these tax benefits as of December 31, 2010 and 2009. The valuation allowance decreased $3,185 during the year ended December 31, 2010, due primarily to the net decrease in certain non-deductible reserves and accruals, depreciation, stock-based compensation, net operating losses and deferred revenue. The current deferred tax asset relates to one of the Company’s foreign subsidiaries and as a result of the guaranteed profit related to this subsidiary, the Company has determined that it is more likely than not that this deferred tax asset will be realized. The Company has reflected this deferred tax asset in prepaid expenses, deposits and other current assets as of December 31, 2010 in the accompanying consolidated balance sheets.
As of December 31, 2010, the Company had federal and state net operating loss carryforwards of $65,973 and $53,021, respectively, to offset future federal and state taxable income, which expires at various times through 2030. The net operating loss carryforwards may be subject to the annual limitations under the “Change of Ownership” rules provided in Section 382 of the Internal Revenue Code of 1986, as amended. The Company’s net operating loss carryforwards at December 31, 2010 include $14,671 in income tax deductions related to stock options which will be tax effected and the benefit will be reflected as a credit to additional paid in capital as realized. Due to limitations on the use of net operating losses in certain states, the Company utilized income tax deductions related to the exercise of stock options during the year ended December 31, 2010 and recorded the benefit of $132 directly to additional paid-in capital. The Company has tax credits of $280 that are available to reduce future U.S. tax liabilities, which expire at various times through 2025.
As of December 31, 2010 and 2009, the Company determined that no liabilities for uncertain tax positions should be recorded. Therefore, the Company has not recorded any interest and penalties on any
unrecognized tax benefits since its inception. The Company has adopted a policy that it will recognize both accrued interest and penalties related to unrecognized benefits in income tax expense, when and if recorded.
The Company files income tax returns in the U.S. federal and applicable state jurisdictions, and the Canadian and United Kingdom tax jurisdictions. The tax years for 2005 through 2009 remain open for certain U.S. federal and state tax jurisdictions although carryforward attributes that were generated prior to 2005 may still be subject to examination if they either have been or will be used in future periods. The Company is currently not under examination by any tax jurisdictions for any tax years.
11.
Employee Savings and Retirement Plan
The Company has established a 401(k) Profit Sharing Plan and Trust (the 401(k) Plan) covering substantially all employees. Once the employees have met the eligibility and participation requirements under the 401(k) Plan, employees may contribute a portion of their earnings to the 401(k) Plan to be invested in various savings alternatives. Annually, at the discretion of the Company’s board of directors, the Company may make matching contributions to the 401(k) Plan, which may vest ratably over periods ranging from one to three years. The Company has not made any matching contributions to the 401(k) Plan since inception.
12.
Commitments and Contingencies
The Company leases it office facilities and certain equipment under non-cancelable operating leases, which expire through 2015. Certain of the Company’s operating leases contain escalating rent payments. The Company has straight-lined its rent expense under these operating lease arrangements. As of December 31, 2010 and 2009, the deferred rent balances are included in other liabilities in the consolidated balance sheets and were not material. The majority of the office leases require payments for additional expenses such as taxes, maintenance, and utilities. Certain of the leases contain renewal options.
At December 31, 2010, future minimum lease payments for operating leases with non-cancelable terms of more than one year were as follows:
Rent expense under operating leases amounted to $4,311, $3,484 and $2,008 during the years ended December 31, 2010, 2009 and 2008, respectively.
The Company is contingently liable under outstanding letters of credit. Restricted cash balances in the amount of $1,300 and $7,874, respectively, collateralize certain outstanding letters of credit and cover financial assurance requirements in certain of the programs in which the Company participated at December 31, 2010 and December 31, 2009. Restricted cash to secure certain other commitments was $237 and $0 at December 31, 2010 and 2009, respectively. Based on the Company’s demand response event performance in July 2010 under a certain open market demand response program in which the Company participates, approximately $7,697 of restricted cash that collateralized the Company’s performance obligations became unrestricted in July 2010.
The Company is subject to performance guarantee requirements under certain utility and electric power grid operator customer contracts and open market bidding program participation rules. The Company had deposits held by certain customers of $3,467 and $3,024, respectively, at December 31, 2010 and December 31, 2009. These amounts primarily represent up-front payments required by utility and electric power grid operator customers as a condition of participation in certain demand response programs and to ensure that the Company
will deliver its committed capacity amounts in those programs. If the Company fails to meet its minimum committed capacity requirements, a portion or all of the deposit may be forfeited. The Company assessed the probability of default under these customer contracts and open market bidding programs and has determined the likelihood of default and loss of deposits to be remote. In addition, under certain utility and electric power grid operator customer contracts, if the Company does not achieve the required performance guarantee requirements, the customer can terminate the arrangement and the Company would potentially be subject to termination penalties. Under these arrangements, the Company defers all fees received up to the amount of the potential termination penalty until the Company has concluded that it can reliably determine that the potential termination penalty will not be incurred or the termination penalty lapses. As of December 31, 2010, the Company has deferred fees totaling approximately $4,696, which are included in deferred revenue, long-term in the accompanying consolidated balance sheets. As of December 31, 2010, the maximum termination penalty that the Company is subject to under these arrangements, which the Company has not deemed probable of incurring, is approximately $5,400.
In connection with the Company’s participation in an open market bidding program, the Company entered into an arrangement with a third party during the second quarter of 2009 to bid capacity into the program and provide the corresponding financial assurance required in connection with the bid. The arrangement included an up-front payment by the Company equal to $2,000, of which $1,100 was expensed as interest expense during the second quarter of 2009 and $900 was deferred and will be recognized ratably as a charge to cost of revenues as revenue is recognized over the 2012/2013 delivery year. In addition, the Company will be required to pay the third party an additional contingent fee, up to a maximum of $3,000, based on the revenue that the Company expects to earn in 2012 in connection with the bid. This additional fee will be recognized as earned.
Indemnification Provisions
The Company includes indemnification provisions in certain of its contracts. These indemnification provisions include provisions indemnifying the customer against losses, expenses, and liabilities from damages that could be awarded against the customer in the event that the Company’s services and related enterprise software platforms are found to infringe upon a patent or copyright of a third party. The Company believes that its internal business practices and policies and the ownership of information limits the Company’s risk in paying out any claims under these indemnification provisions.
Exhibit Index
@
Management contract, compensatory plan or arrangement.
*
Filed herewith