UNITED STATES SECURITIES AND
EXCHANGE COMMISSION
Washington, D.C.
20549
Form 10-K
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(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the fiscal year ended
December 31,
2010
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or
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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For the transition period
from to
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Commission file number
001-33471
EnerNOC, Inc.
(Exact Name of
Registrant as Specified in its Charter)
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Delaware
(State or Other Jurisdiction
of
Incorporation or Organization)
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87-0698303
(IRS Employer
Identification No.)
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101 Federal Street
Suite 1100
Boston, Massachusetts
(Address of Principal
Executive Offices)
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02110
(Zip Code)
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Registrants telephone number, including area code:
(617) 224-9900
Securities registered pursuant to Section 12(b) of the
Act:
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Title of Each Class
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Name of Each Exchange on Which Registered
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Common Stock, $0.001 par value
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The NASDAQ Stock Market LLC
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(The NASDAQ Global Market)
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Securities registered pursuant to Section 12(g) of the
Act:
None
Indicate by check mark if the Registrant is a well-known
seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes o No þ
Indicate by check mark if the Registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the
Act. Yes o No þ
Indicate by check mark whether the Registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the Registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the past
90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted
electronically and posted on its corporate Web site, if any,
every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of
Regulation S-T
(§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant
was required to submit and post such
files). Yes o No o
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of
Regulation S-K
(section 229.405 of this chapter) is not contained herein,
and will not be contained, to the best of Registrants
knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this
Form 10-K
or any amendment to this
Form 10-K. þ
Indicate by check mark whether the Registrant is a large
accelerated filer, an accelerated filer, a non-accelerated filer
or a smaller reporting company. See definitions of large
accelerated filer, accelerated filer and
smaller reporting company in
Rule 12b-2
of the Exchange Act. (Check one).
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Large accelerated
filer þ
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller reporting company o
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(Do not check if a smaller
reporting company)
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Indicate by check mark whether the Registrant is a shell company
(as defined in
Rule 12b-2
of the Exchange
Act). Yes o No þ
The aggregate market value of the Registrants common stock
held by non-affiliates of the Registrant as of June 30,
2010, the last business day of the Registrants second
quarter of fiscal 2010, was approximately $704.5 million
based upon the last sale price reported for such date on The
NASDAQ Global Market.
The number of shares of the Registrants common stock (the
Registrants only outstanding class of stock) outstanding
as of February 24, 2011 was 26,238,277.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrants definitive proxy statement for
its 2011 Annual Meeting of Stockholders, to be filed with the
Securities and Exchange Commission pursuant to
Regulation 14A not later than 120 days after the end
of the Registrants fiscal year ended December 31,
2010, are incorporated by reference into this Annual Report on
Form 10-K.
EnerNOC,
Inc.
ANNUAL
REPORT ON
FORM 10-K
FOR THE
FISCAL YEAR ENDED DECEMBER 31, 2010
Table of
Contents
This Annual Report on
Form 10-K
includes forward-looking statements within the meaning of
Section 21E of the Securities Exchange Act of 1934, as
amended, and Section 27A of the Securities Act of 1933, as
amended. For this purpose, any statements contained herein
regarding our strategy, future operations, financial condition,
future revenues, profits and profit margins, projected costs,
market position, prospects, plans and objectives of management,
other than statements of historical facts, are forward-looking
statements. The words anticipates,
believes, estimates,
expects, intends, may,
plans, projects, will,
would and similar expressions are intended to
identify forward-looking statements, although not all
forward-looking statements contain these identifying words. We
cannot guarantee that we actually will achieve the plans,
intentions or expectations expressed or implied in our
forward-looking statements. Matters subject to forward-looking
statements involve known and unknown risks and uncertainties,
including economic, regulatory, competitive and other factors,
which may cause actual results, levels of activity, performance
or the timing of events to be materially different than those
exposed or implied by forward-looking statements. Important
factors that could cause or contribute to such differences
include the factors set forth under the caption Risk
Factors in Item 1A of Part I of this Annual
Report on
Form 10-K.
Although we may elect to update forward-looking statements in
the future, we specifically disclaim any obligation to do so,
even if our estimates change, and readers should not rely on
those forward-looking statements as representing our views as of
any date subsequent to February 28, 2011.
Our trademarks include: 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.
Other trademarks or service marks appearing in this Annual
Report on
Form 10-K
are the property of their respective holders.
PART I
We use the terms EnerNOC, the
Company, we, us and
our in this Annual Report on
Form 10-K
to refer to the business of EnerNOC, Inc. and its
subsidiaries.
Company
Overview
We are a leading provider of 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
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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.
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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
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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 PJMs
Synchronized Reserves Market, in which we were the first
provider of demand response capacity, and ISO-NEs 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
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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.
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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
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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 industrys 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.
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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 customers
electricity consumption. The ESS communicates to our NOC through
the customers 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
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vertical markets that our commercial and industrial sales group
primarily targets for DemandSMART, EfficiencySMART, SupplySMART
and CarbonSMART opportunities:
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Technology
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Education
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Food Sales and Storage
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Commercial Real Estate
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AT&T
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Carnegie Mellon University
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Stater Bros. Markets
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Sears
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Level 3 Communications
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University of San Diego
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Albertsons
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Morgan Stanley
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General Electric
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The California State University
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Raleys
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TransAmerica Properties
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Adobe Systems
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Southern Connecticut State University
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Pathmark
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Beacon Properties
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Genentech
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Western Connecticut State University
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Stop & Shop
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Morguard Investments Limited
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New Haven Public Schools
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Shop Rite
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Washington Realty Investment Trust
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Government
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Healthcare
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Manufacturing/Industrial
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Commonwealth of Massachusetts
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Partners Healthcare
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O&G Industries
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State of Vermont
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Adventist Hospital
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Pfizer
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State of Connecticut
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Greenwich Hospital
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Verso Paper
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City of Boston, MA
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Hartford Hospital
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Cascades
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State of Rhode Island
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Genesis Healthcare
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Southeastern Container
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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.
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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.
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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
utilitys 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
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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
states 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
10
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.
11
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 PJMs 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 PJMs 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-NEs open market programs in which we
12
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
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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-NEs 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-NEs
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
14
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.
15
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.
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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.
16
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
Grids 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.
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International operations are also subject to general
geopolitical risks, such as political, social and economic
instability and changes in diplomatic and trade relations. One
or more of these factors could adversely affect any
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.
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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.
17
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
18
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-NEs 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.
19
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 FERCs
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.
20
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
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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.
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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
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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.
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Any delays, malfunctions, inefficiencies or interruptions in
these products, services or operations could adversely affect
the reliability or operation of our energy management
applications and services, which could cause us to experience
difficulty monitoring or retaining current customers and
attracting new customers. Such
23
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
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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.
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Any interruption in the operation of our information technology
systems could result in decreased revenues under our contracts
and commitments, reduced profit margins on revenues where fixed
payments are due to our C&I 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.
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Uncertainty about current global economic conditions could also
continue to increase the volatility of our stock price.
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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 FERCs
annual audit plan to determine whether jurisdictional companies
are in compliance with FERCs 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.
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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
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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
companys 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 companys
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.
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If we are unable to adequately address any of these factors, our
results of operations and prospects for growth could be
materially adversely 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 managements 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.
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Our
stock price has been and is likely to continue to be volatile
and the market price of our common stock may fluctuate
substantially.
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;
|
|
|
|
developments or disputes concerning patents or other proprietary
rights;
|
|
|
|
period-to-period fluctuations in our financial results;
|
|
|
|
the potential interruptions of our customers operations;
|
|
|
|
the seasonality of our demand response business in certain of
the markets in which we operate;
|
|
|
|
failure to secure adequate capital to fund our operations, or
the future sale or issuance of equity securities at prices below
fair market price or in general; and
|
|
|
|
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:
|
|
|
|
|
allow the authorized number of directors to be changed only by
resolution of our board of directors;
|
31
|
|
|
|
|
require that vacancies on the board of directors, including
newly created directorships, be filled only by a majority vote
of directors then in office;
|
|
|
|
establish a classified board of directors, providing that not
all members of the board be elected at one time;
|
|
|
|
authorize our board of directors to issue, without stockholder
approval, blank check preferred stock that, if issued, could
operate as a poison pill to dilute the stock
ownership of a potential hostile acquirer to prevent an
acquisition that is not approved by our board of directors;
|
|
|
|
require that stockholder actions must be effected at a duly
called stockholder meeting and prohibit stockholder action by
written consent;
|
|
|
|
prohibit cumulative voting in the election of directors, which
would otherwise allow holders of less than a majority of stock
to elect some directors;
|
|
|
|
establish advance notice requirements for stockholder
nominations to our board of directors or for stockholder
proposals that can be acted on at stockholder meetings;
|
|
|
|
limit who may call stockholder meetings; and
|
|
|
|
require the approval of the holders of 75% of the outstanding
shares of our capital stock entitled to vote in order to amend
certain provisions of our certificate of incorporation and
bylaws.
|
Some of our employment arrangements and equity agreements
provide for severance payments and accelerated vesting of
benefits, including accelerated vesting of equity awards, upon a
change of control. These provisions may discourage or prevent a
change of control. In addition, because we are incorporated in
Delaware, we are governed by the provisions of Section 203
of the Delaware General Corporation Law, which may, unless
certain criteria are met, prohibit large stockholders, in
particular those owning 15% or more of our outstanding voting
stock, from merging or combining with us for a proscribed period
of time.
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.
|
Unresolved
Staff Comments
|
Not applicable.
32
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.
|
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.
|
[Removed
and Reserved]
|
PART II
|
|
Item 5.
|
Market
for Registrants Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
|
Price
Range of Our Common Stock
Our common stock is currently traded on The NASDAQ Global Market
under the symbol ENOC. The following table sets
forth the high and low sales prices per share of our common
stock as reported on The NASDAQ Global Market for the periods
indicated.
|
|
|
|
|
|
|
|
|
Fiscal 2010
|
|
High
|
|
Low
|
|
First Quarter
|
|
$
|
37.00
|
|
|
$
|
25.93
|
|
Second Quarter
|
|
$
|
32.41
|
|
|
$
|
24.75
|
|
Third Quarter
|
|
$
|
36.75
|
|
|
$
|
29.62
|
|
Fourth Quarter
|
|
$
|
31.79
|
|
|
$
|
23.00
|
|
|
|
|
|
|
|
|
|
|
Fiscal 2009
|
|
High
|
|
Low
|
|
First Quarter
|
|
$
|
15.61
|
|
|
$
|
7.50
|
|
Second Quarter
|
|
$
|
25.00
|
|
|
$
|
14.42
|
|
Third Quarter
|
|
$
|
34.37
|
|
|
$
|
17.65
|
|
Fourth Quarter
|
|
$
|
35.55
|
|
|
$
|
24.10
|
|
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.
33
Unregistered
Sales of Equity Securities
None.
|
|
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 Managements Discussion and
Analysis of Financial Condition and Results of Operations
and our consolidated financial statements and accompanying notes
thereto included in Item 7 and Appendix A,
respectively, to this Annual Report on
Form 10-K.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010(1)
|
|
|
2009(1)
|
|
|
2008(1)
|
|
|
2007(1)
|
|
|
2006(1)
|
|
|
|
(In thousands, except per share data)
|
|
|
Selected Balance Sheet Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
153,416
|
|
|
$
|
119,739
|
|
|
$
|
60,782
|
|
|
$
|
70,242
|
|
|
$
|
9,184
|
|
Marketable securities
|
|
|
|
|
|
|
|
|
|
|
2,000
|
|
|
|
15,500
|
|
|
|
|
|
Working capital
|
|
|
163,519
|
|
|
|
124,680
|
|
|
|
59,137
|
|
|
|
72,836
|
|
|
|
1,431
|
|
Total assets
|
|
|
325,899
|
|
|
|
255,022
|
|
|
|
136,694
|
|
|
|
155,584
|
|
|
|
29,950
|
|
Total long-term debt, including current portion
|
|
|
37
|
|
|
|
73
|
|
|
|
4,563
|
|
|
|
6,091
|
|
|
|
5,200
|
|
Redeemable convertible preferred stock warrant liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
606
|
|
Total redeemable convertible preferred stock and
stockholders equity
|
|
|
226,126
|
|
|
|
194,975
|
|
|
|
99,220
|
|
|
|
122,417
|
|
|
|
8,608
|
|
Selected Statement of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
280,157
|
|
|
$
|
190,675
|
|
|
$
|
106,115
|
|
|
$
|
60,838
|
|
|
$
|
26,100
|
|
Cost of revenues
|
|
|
159,832
|
|
|
|
104,215
|
|
|
|
64,819
|
|
|
|
38,949
|
|
|
|
16,839
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross profit
|
|
|
120,325
|
|
|
|
86,460
|
|
|
|
41,296
|
|
|
|
21,889
|
|
|
|
9,261
|
|
Selling and marketing expenses
|
|
|
45,436
|
|
|
|
39,502
|
|
|
|
30,789
|
|
|
|
18,695
|
|
|
|
5,932
|
|
General and administrative expenses
|
|
|
53,576
|
|
|
|
44,407
|
|
|
|
41,582
|
|
|
|
25,866
|
|
|
|
8,000
|
|
Research and development expenses
|
|
|
10,097
|
|
|
|
7,601
|
|
|
|
6,123
|
|
|
|
3,598
|
|
|
|
955
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
11,216
|
|
|
|
(5,050
|
)
|
|
|
(37,198
|
)
|
|
|
(26,270
|
)
|
|
|
(5,626
|
)
|
Interest and other (expense) income, net
|
|
|
(803
|
)
|
|
|
(1,446
|
)
|
|
|
798
|
|
|
|
2,788
|
|
|
|
(145
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
10,413
|
|
|
|
(6,496
|
)
|
|
|
(36,400
|
)
|
|
|
(23,482
|
)
|
|
|
(5,771
|
)
|
Provision for income taxes
|
|
|
(836
|
)
|
|
|
(333
|
)
|
|
|
(262
|
)
|
|
|
(100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
9,577
|
|
|
$
|
(6,829
|
)
|
|
$
|
(36,662
|
)
|
|
$
|
(23,582
|
)
|
|
$
|
(5,771
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share, basic(2)
|
|
$
|
0.39
|
|
|
$
|
(0.32
|
)
|
|
$
|
(1.88
|
)
|
|
$
|
(1.80
|
)
|
|
$
|
(1.60
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share, diluted(2)
|
|
$
|
0.37
|
|
|
$
|
(0.32
|
)
|
|
$
|
(1.88
|
)
|
|
$
|
(1.80
|
)
|
|
$
|
(1.60
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of basic shares(2)
|
|
|
24,611,729
|
|
|
|
21,466,813
|
|
|
|
19,505,065
|
|
|
|
13,106,114
|
|
|
|
3,607,822
|
|
Weighted average number of diluted shares(2)
|
|
|
26,054,162
|
|
|
|
21,466,813
|
|
|
|
19,505,065
|
|
|
|
13,106,114
|
|
|
|
3,607,822
|
|
|
|
|
(1) |
|
Includes the results of operations from the date of acquisition
relating to our acquisitions of Smallfoot and Zox in March 2010,
Cogent Energy, Inc., or Cogent, in December 2009, eQuilibrium
Solutions Corporation, or eQ, in June 2009, South River
Consulting, LLC, or SRC, in May 2008, Mdenergy, LLC, or MDE, in
September 2007, and eBidenergy, Inc. and Celerity in 2006. See
Note 2 of our accompanying consolidated financial
statements contained in Appendix A to this Annual Report on
Form 10-K. |
|
(2) |
|
On May 1, 2007, we effected a 2.831 for one split of our
common stock. All amounts reflect the impact of that split. |
34
|
|
Item 7.
|
Managements
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.
35
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
36
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 PJMs 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
37
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.
38
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.
39
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
Change
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Demand response
|
|
$
|
264,608
|
|
|
$
|
183,861
|
|
|
$
|
80,747
|
|
|
|
43.9
|
%
|
EfficiencySMART, SupplySMART and CarbonSMART
|
|
|
15,549
|
|
|
|
6,814
|
|
|
|
8,735
|
|
|
|
128.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
280,157
|
|
|
$
|
190,675
|
|
|
$
|
89,482
|
|
|
|
46.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
40
primarily attributable to changes in our MW under management in
the following existing operating areas (dollars in thousands):
|
|
|
|
|
|
|
Revenue Increase:
|
|
|
|
December 31, 2009
|
|
|
|
to
|
|
|
|
December 31, 2010
|
|
|
PJM
|
|
$
|
69,246
|
|
Tennessee Valley Authority
|
|
|
5,494
|
|
New England
|
|
|
(4,515
|
)
|
New York
|
|
|
934
|
|
California
|
|
|
1,790
|
|
Other(1)
|
|
|
7,798
|
|
|
|
|
|
|
Total increased demand response revenues
|
|
$
|
80,747
|
|
|
|
|
|
|
|
|
|
(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.
41
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2010
|
|
|
2009
|
|
Gross Profit
|
|
|
Gross Margin
|
|
|
Gross Profit
|
|
|
Gross Margin
|
|
|
$
|
120,325
|
|
|
|
42.9
|
%
|
|
$
|
86,460
|
|
|
|
45.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
Percentage
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Selling and marketing
|
|
$
|
45,436
|
|
|
$
|
39,502
|
|
|
|
15.0
|
%
|
General and administrative
|
|
|
53,576
|
|
|
|
44,407
|
|
|
|
20.6
|
%
|
Research and development
|
|
|
10,097
|
|
|
|
7,601
|
|
|
|
32.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
109,109
|
|
|
$
|
91,510
|
|
|
|
19.2
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
42
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
Percentage
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
Payroll and related costs
|
|
$
|
30,029
|
|
|
$
|
26,241
|
|
|
|
14.4
|
%
|
Stock-based compensation
|
|
|
4,709
|
|
|
|
3,989
|
|
|
|
18.0
|
%
|
Other
|
|
|
10,698
|
|
|
|
9,272
|
|
|
|
15.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
45,436
|
|
|
$
|
39,502
|
|
|
|
15.0
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
Percentage
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
Payroll and related costs
|
|
$
|
28,445
|
|
|
$
|
23,059
|
|
|
|
23.4
|
%
|
Stock-based compensation
|
|
|
10,126
|
|
|
|
8,471
|
|
|
|
19.5
|
%
|
Other
|
|
|
15,005
|
|
|
|
12,877
|
|
|
|
16.5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
53,576
|
|
|
$
|
44,407
|
|
|
|
20.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
43
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
Percentage
|
|
|
|
2010
|
|
|
2009
|
|
|
Change
|
|
|
Payroll and related costs
|
|
$
|
5,517
|
|
|
$
|
4,214
|
|
|
|
30.9
|
%
|
Stock-based compensation
|
|
|
907
|
|
|
|
674
|
|
|
|
34.6
|
%
|
Other
|
|
|
3,673
|
|
|
|
2,713
|
|
|
|
35.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
10,097
|
|
|
$
|
7,601
|
|
|
|
32.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
44
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:
|
|
|
|
|
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;
|
|
|
|
certain state taxes for jurisdictions where the states currently
limit or disallow the utilization of net operating loss
carryforwards; and
|
|
|
|
amortization of tax deductible goodwill, which generates a
deferred tax liability that cannot be offset by net operating
losses or other deferred tax assets since its reversal is
considered indefinite in nature.
|
Our effective tax rate for the year ended December 31, 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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
Dollar
|
|
|
Percentage
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
Change
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Demand response
|
|
$
|
183,861
|
|
|
$
|
99,394
|
|
|
$
|
84,467
|
|
|
|
85.0
|
%
|
EfficiencySMART and SupplySMART
|
|
|
6,814
|
|
|
|
6,721
|
|
|
|
93
|
|
|
|
1.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
|
$
|
190,675
|
|
|
$
|
106,115
|
|
|
$
|
84,560
|
|
|
|
79.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
45
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):
|
|
|
|
|
|
|
Revenue Increase:
|
|
|
|
December 31, 2008
|
|
|
|
to
|
|
|
|
December 31, 2009
|
|
|
PJM
|
|
$
|
68,404
|
|
TECO
|
|
|
1,515
|
|
Tennessee Valley Authority
|
|
|
5,747
|
|
California
|
|
|
2,451
|
|
New York ISO
|
|
|
1,843
|
|
Other
|
|
|
4,507
|
|
|
|
|
|
|
Total increased demand response revenues
|
|
$
|
84,467
|
|
|
|
|
|
|
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
2009
|
|
|
2008
|
|
Gross Profit
|
|
|
Gross Margin
|
|
|
Gross Profit
|
|
|
Gross Margin
|
|
|
$
|
86,460
|
|
|
|
45.3
|
%
|
|
$
|
41,296
|
|
|
|
38.9
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
46
Operating
Expenses
The following table summarizes our operating expenses for the
years ended December 31, 2009 and 2008 (dollars in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
Percentage
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
Operating Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Selling and marketing
|
|
$
|
39,502
|
|
|
$
|
30,789
|
|
|
|
28.3
|
%
|
General and administrative
|
|
|
44,407
|
|
|
|
41,582
|
|
|
|
6.8
|
%
|
Research and development
|
|
|
7,601
|
|
|
|
6,123
|
|
|
|
24.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
91,510
|
|
|
$
|
78,494
|
|
|
|
16.6
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Selling
and Marketing Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
Percentage
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
Payroll and related costs
|
|
$
|
26,241
|
|
|
$
|
20,850
|
|
|
|
25.9
|
%
|
Stock-based compensation
|
|
|
3,989
|
|
|
|
3,692
|
|
|
|
8.0
|
%
|
Other
|
|
|
9,272
|
|
|
|
6,247
|
|
|
|
48.4
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
39,502
|
|
|
$
|
30,789
|
|
|
|
28.3
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
Percentage
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
Payroll and related costs
|
|
$
|
23,059
|
|
|
$
|
21,227
|
|
|
|
8.6
|
%
|
Stock-based compensation
|
|
|
8,471
|
|
|
|
6,201
|
|
|
|
36.6
|
%
|
Other
|
|
|
12,877
|
|
|
|
14,154
|
|
|
|
(9.0
|
)%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
44,407
|
|
|
$
|
41,582
|
|
|
|
6.8
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
47
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 officers 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
|
|
|
|
|
|
|
December 31,
|
|
|
Percentage
|
|
|
|
2009
|
|
|
2008
|
|
|
Change
|
|
|
Payroll and related costs
|
|
$
|
4,214
|
|
|
$
|
3,850
|
|
|
|
9.5
|
%
|
Stock-based compensation
|
|
|
674
|
|
|
|
546
|
|
|
|
23.4
|
%
|
Other
|
|
|
2,713
|
|
|
|
1,727
|
|
|
|
57.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
7,601
|
|
|
$
|
6,123
|
|
|
|
24.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
48
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Cash flows provided by (used in) operating activities
|
|
$
|
45,148
|
|
|
$
|
8,086
|
|
|
$
|
(15,207
|
)
|
Cash flows (used in) provided by investing activities
|
|
|
(15,424
|
)
|
|
|
(29,172
|
)
|
|
|
6,894
|
|
Cash flows provided by (used in) financing activities
|
|
|
3,974
|
|
|
|
80,013
|
|
|
|
(1,070
|
)
|
Effects of exchange rate changes on cash
|
|
|
(21
|
)
|
|
|
30
|
|
|
|
(77
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
$
|
33,677
|
|
|
$
|
58,957
|
|
|
$
|
(9,460
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49
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
50
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
51
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
SRCs 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.
52
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):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due by Period
|
|
|
|
|
|
|
Less than
|
|
|
|
|
|
|
|
|
More than
|
|
Contractual Obligations
|
|
Total
|
|
|
1 Year
|
|
|
1 - 3 Years
|
|
|
3 - 5 Years
|
|
|
5 Years
|
|
|
Capital lease obligations
|
|
|
37
|
|
|
|
37
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating lease obligations
|
|
|
13,541
|
|
|
|
4,602
|
|
|
|
8,939
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
13,578
|
|
|
$
|
4,639
|
|
|
$
|
8,939
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
53
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:
|
|
|
|
|
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.
|
|
|
|
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.
|
|
|
|
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:
54
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
(In thousands, except share and per share data)
|
|
|
GAAP net income (loss)
|
|
$
|
9,577
|
|
|
$
|
(6,829
|
)
|
|
$
|
(36,662
|
)
|
ADD: Stock based compensation
|
|
|
15,742
|
|
|
|
13,134
|
|
|
|
10,439
|
|
ADD: Amortization expense of acquired intangible assets
|
|
|
1,452
|
|
|
|
692
|
|
|
|
1,019
|
|
LESS: Income tax effect on Non-GAAP adjustments(1)
|
|
|
(1,380
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP net income (loss)
|
|
$
|
25,391
|
|
|
$
|
6,997
|
|
|
$
|
(25,204
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GAAP net income (loss) per basic share
|
|
$
|
0.39
|
|
|
$
|
(0.32
|
)
|
|
$
|
(1.88
|
)
|
ADD: Stock based compensation
|
|
|
0.64
|
|
|
|
0.61
|
|
|
|
0.54
|
|
ADD: Amortization expense of acquired intangible assets
|
|
|
0.06
|
|
|
|
0.04
|
|
|
|
0.05
|
|
LESS: Income tax effect on Non-GAAP adjustments(1)
|
|
|
(0.06
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP net income (loss) per basic share
|
|
$
|
1.03
|
|
|
$
|
0.33
|
|
|
$
|
(1.29
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GAAP net income (loss) per diluted share
|
|
$
|
0.37
|
|
|
$
|
(0.32
|
)
|
|
$
|
(1.88
|
)
|
ADD: Stock based compensation
|
|
|
0.60
|
|
|
|
0.61
|
|
|
|
0.54
|
|
ADD: Amortization expense of acquired intangible assets
|
|
|
0.05
|
|
|
|
0.04
|
|
|
|
0.05
|
|
LESS: Income tax effect on Non-GAAP adjustments(1)
|
|
|
(0.05
|
)
|
|
|
|
|
|
|
|
|
LESS: Dilutive impact on weighted average common stock
equivalents
|
|
|
|
|
|
|
(0.03
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-GAAP net income (loss) per diluted share
|
|
$
|
0.97
|
|
|
$
|
0.30
|
|
|
$
|
(1.29
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
24,611,729
|
|
|
|
21,466,813
|
|
|
|
19,505,065
|
|
Diluted
|
|
|
26,054,162
|
|
|
|
23,021,435
|
|
|
|
19,505,065
|
|
|
|
|
(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:
55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Net income (loss)
|
|
$
|
9,577
|
|
|
$
|
(6,829
|
)
|
|
$
|
(36,662
|
)
|
Add back:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
15,866
|
|
|
|
12,049
|
|
|
|
9,054
|
|
Stock-based compensation expense
|
|
|
15,742
|
|
|
|
13,134
|
|
|
|
10,439
|
|
Other expense (income)
|
|
|
85
|
|
|
|
(98
|
)
|
|
|
(1,949
|
)
|
Interest expense
|
|
|
718
|
|
|
|
1,544
|
|
|
|
1,151
|
|
Provision for income tax
|
|
|
836
|
|
|
|
333
|
|
|
|
262
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA
|
|
$
|
42,824
|
|
|
$
|
20,133
|
|
|
$
|
(17,705
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Net cash provided by (used in) operating activities
|
|
$
|
45,148
|
|
|
$
|
8,086
|
|
|
$
|
(15,207
|
)
|
Subtract:
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of property and equipment
|
|
|
(19,394
|
)
|
|
|
(16,901
|
)
|
|
|
(12,459
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Free cash flow
|
|
$
|
25,754
|
|
|
$
|
(8,815
|
)
|
|
$
|
(27,666
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
56
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:
|
|
|
|
|
Evidence of an arrangement. We consider a
definitive agreement signed by the customer and us or an
arrangement enforceable under the rules of an open market
bidding program to be representative of persuasive evidence of
an arrangement.
|
|
|
|
Delivery has occurred. We consider delivery to
have occurred when service has been delivered to the customer
and no post-delivery obligations exist. In instances where
customer acceptance is required, delivery is deemed to have
occurred when customer acceptance has been achieved.
|
|
|
|
Fees are fixed or determinable. We consider
the fee to be fixed or determinable unless the fee is subject to
refund or adjustment or is not payable within normal payment
terms. If the fee is subject to refund or adjustment and we
cannot reliably estimate this amount, we recognize revenues when
the right to a refund or adjustment lapses. If offered payment
terms significantly exceed our normal terms, we recognize
revenues as the amounts become due and payable or upon the
receipt of cash.
|
|
|
|
Collection is reasonably assured. We conduct 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
57
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.
58
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
assets 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 units 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
59
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
60
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
61
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 options 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.
62
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 managements 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.
63
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2010
|
|
1st Qtr
|
|
2nd Qtr
|
|
3rd Qtr
|
|
4th Qtr
|
|
|
(In thousands, except per share data)
|
|
Revenues
|
|
$
|
28,121
|
|
|
$
|
66,548
|
|
|
$
|
162,798
|
|
|
$
|
22,690
|
|
Gross profit
|
|
|
9,575
|
|
|
|
28,992
|
|
|
|
77,736
|
|
|
|
4,022
|
|
Operating expenses
|
|
|
24,920
|
|
|
|
27,177
|
|
|
|
29,938
|
|
|
|
27,074
|
|
(Loss) Income from operations
|
|
|
(15,345
|
)
|
|
|
1,815
|
|
|
|
47,798
|
|
|
|
(23,052
|
)
|
Net (loss) income
|
|
|
(14,200
|
)
|
|
|
1,078
|
|
|
|
43,866
|
|
|
|
(21,167
|
)
|
Basic net (loss) income per share:
|
|
$
|
(0.59
|
)
|
|
$
|
0.04
|
|
|
$
|
1.76
|
|
|
$
|
(0.86
|
)
|
Diluted net (loss) income per share:
|
|
$
|
(0.59
|
)
|
|
$
|
0.04
|
|
|
$
|
1.67
|
|
|
$
|
(0.86
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009
|
|
1st Qtr
|
|
2nd Qtr
|
|
3rd Qtr
|
|
4th Qtr
|
|
|
(In thousands, except per share data)
|
|
Revenues
|
|
$
|
18,423
|
|
|
$
|
42,402
|
|
|
$
|
103,117
|
|
|
$
|
26,733
|
|
Gross profit
|
|
|
7,898
|
|
|
|
18,135
|
|
|
|
51,677
|
|
|
|
8,750
|
|
Operating expenses
|
|
|
19,906
|
|
|
|
22,483
|
|
|
|
25,868
|
|
|
|
23,253
|
|
(Loss) Income from operations
|
|
|
(12,008
|
)
|
|
|
(4,348
|
)
|
|
|
25,809
|
|
|
|
(14,503
|
)
|
Net (loss) income
|
|
|
(12,534
|
)
|
|
|
(5,729
|
)
|
|
|
26,637
|
|
|
|
(15,203
|
)
|
Basic net (loss) income per share:
|
|
$
|
(0.63
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
1.21
|
|
|
$
|
(0.64
|
)
|
Diluted net (loss) income per share:
|
|
$
|
(0.63
|
)
|
|
$
|
(0.29
|
)
|
|
$
|
1.12
|
|
|
$
|
(0.64
|
)
|
|
|
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
64
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.
|
Financial
Statements and Supplementary Data
|
All financial statements and schedules required to be filed
hereunder are included as Appendix A hereto and
incorporated into this Annual Report on
Form 10-K
by reference.
|
|
Item 9.
|
Changes
in and Disagreements With Accountants on Accounting and
Financial Disclosure
|
None.
|
|
Item 9A.
|
Controls
and Procedures
|
Disclosure
Controls and Procedures.
Our principal executive officer and principal financial officer,
after evaluating the effectiveness of our disclosure controls
and procedures (as defined in Exchange Act
Rules 13a-15(e)
and
15d-15(e))
as of the end of the period covered by this Annual Report on
Form 10-K,
have concluded that, based on such evaluation, our disclosure
controls and procedures were effective to ensure that
information required to be disclosed by us in the reports that
we file or submit under the Exchange Act is recorded, processed,
summarized and reported, within the time periods specified in
the SECs 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.
Managements
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
65
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.
66
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
Managements Annual Report on Internal Control Over
Financial Reporting. Our responsibility is to express an opinion
on the Companys 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 companys 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 companys
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
companys 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
67
|
|
Item 9B.
|
Other
Information
|
None.
PART III
|
|
Item 10.
|
Directors,
Executive Officers and Corporate Governance
|
The information required by this Item will be contained in our
definitive proxy statement for our 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.
|
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.
|
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.
|
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.
|
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.
|
Exhibits,
Financial Statement Schedules
|
(a) The following are filed as part of this Annual Report
on
Form 10-K:
1. Financial Statements
The following consolidated financial statements beginning on
page F-1
of Appendix A are included in this Annual Report on
Form 10-K:
|
|
|
|
|
Report of Independent Registered Public Accounting Firm
|
|
|
|
Consolidated Balance Sheets as of December 31, 2010 and 2009
|
|
|
|
Consolidated Statements of Operations for the Years ended
December 31, 2010, 2009 and 2008
|
68
|
|
|
|
|
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.
69
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.
|
|
|
|
|
|
|
Signature
|
|
Title
|
|
Date
|
|
|
|
|
|
|
/s/ Timothy
G. Healy
Timothy
G. Healy
|
|
Chairman of the Board,
Chief Executive Officer and Director (principal executive
officer)
|
|
February 28, 2011
|
|
|
|
|
|
/s/ Timothy
Weller
Timothy
Weller
|
|
Chief Financial Officer and Treasurer (principal financial
officer)
|
|
February 28, 2011
|
|
|
|
|
|
/s/ Kevin
J. Bligh
Kevin
J. Bligh
|
|
Chief Accounting Officer
(principal accounting officer)
|
|
February 28, 2011
|
|
|
|
|
|
/s/ David
B. Brewster
David
B. Brewster
|
|
Director and President
|
|
February 28, 2011
|
|
|
|
|
|
/s/ Arthur
W. Coviello, Jr.
Arthur
W. Coviello, Jr.
|
|
Director
|
|
February 28, 2011
|
|
|
|
|
|
/s/ Richard
Dieter
Richard
Dieter
|
|
Director
|
|
February 28, 2011
|
|
|
|
|
|
/s/ TJ
Glauthier
TJ
Glauthier
|
|
Director
|
|
February 28, 2011
|
|
|
|
|
|
/s/ Susan
F. Tierney
Susan
F. Tierney, Ph.D.
|
|
Director
|
|
February 28, 2011
|
70
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
Companys 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.
Boston, Massachusetts
February 28, 2011
F-2
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December 31,
|
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2010
|
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2009
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ASSETS
|
Current assets
|
|
|
|
|
|
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|
Cash and cash equivalents
|
|
$
|
153,416
|
|
|
$
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119,739
|
|
Restricted cash
|
|
|
1,537
|
|
|
|
|
|
Trade accounts receivable, net of allowance for doubtful
accounts of $150 and $57 at December 31, 2010 and 2009,
respectively
|
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|
22,137
|
|
|
|
17,421
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|
Unbilled revenue
|
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|
73,144
|
|
|
|
40,388
|
|
Prepaid expenses, deposits and other current assets
|
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|
6,707
|
|
|
|
4,725
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|
|
|
|
|
|
|
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|
Total current assets
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|
256,941
|
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|
|
182,273
|
|
Property and equipment, net of accumulated depreciation of
$36,309 and $22,420 at December 31, 2010 and 2009,
respectively
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|
34,690
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31,344
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Goodwill
|
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24,653
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|
22,553
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Definite-lived intangible assets, net
|
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|
5,823
|
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|
7,075
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Indefinite-lived intangible assets
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|
920
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Deposits and other assets
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2,872
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|
3,903
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Restricted cash
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7,874
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|
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Total assets
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$
|
325,899
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|
$
|
255,022
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LIABILITIES AND STOCKHOLDERS EQUITY
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Current liabilities
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Accounts payable
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$
|
111
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$
|
55
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|
Accrued capacity payments
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65,792
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40,534
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Accrued payroll and related expenses
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|
11,135
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9,688
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Accrued expenses and other current liabilities
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9,307
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|
3,706
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Accrued acquisition contingent consideration
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|
1,500
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|
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|
1,455
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Deferred revenue
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5,540
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2,119
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Current portion of long-term debt
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37
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36
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Total current liabilities
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93,422
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57,593
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Long-term liabilities
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Long-term debt, net of current portion
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37
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Deferred tax liability
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1,141
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|
654
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Deferred revenue, long-term
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4,696
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1,200
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Other liabilities
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|
514
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|
563
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Total long-term liabilities
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6,351
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|
2,454
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Commitments and contingencies (Note 7 and Note 12)
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Stockholders equity
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Undesignated preferred stock, $0.001 par value;
5,000,000 shares authorized; no shares issued
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Common stock, $0.001 par value; 50,000,000 shares
authorized,
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25,155,067 and 24,233,448 shares issued and outstanding at
December 31, 2010 and 2009, respectively
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25
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24
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Additional paid-in capital
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293,942
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272,350
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Accumulated other comprehensive loss
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(75
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)
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(56
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)
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Accumulated deficit
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|
(67,766
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)
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(77,343
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)
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Total stockholders equity
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226,126
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194,975
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Total liabilities and stockholders equity
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$
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325,899
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$
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255,022
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The accompanying notes are an integral part of these
consolidated financial statements
F-3
EnerNOC,
Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share and per
share data)
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Year Ended December 31,
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2010
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2009
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2008
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Revenues
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$
|
280,157
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$
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190,675
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$
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106,115
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Cost of revenues
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159,832
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104,215
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64,819
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Gross profit
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120,325
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86,460
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41,296
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Operating expenses:
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Selling and marketing
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45,436
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39,502
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30,789
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General and administrative
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53,576
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44,407
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41,582
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Research and development
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10,097
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7,601
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6,123
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Total operating expenses
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109,109
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91,510
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78,494
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Income (loss) from operations
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11,216
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(5,050
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)
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(37,198
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)
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Other (expense) income
|
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|
(85
|
)
|
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|
98
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|
|
|
1,949
|
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Interest expense
|
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|
(718
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)
|
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|
(1,544
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)
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(1,151
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)
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|
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Income (loss) before income tax
|
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|
10,413
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|
(6,496
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)
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(36,400
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)
|
Provision for income tax
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|
|
(836
|
)
|
|
|
(333
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)
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|
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(262
|
)
|
|
|
|
|
|
|
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|
|
|
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Net income (loss)
|
|
$
|
9,577
|
|
|
$
|
(6,829
|
)
|
|
$
|
(36,662
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)
|
|
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|
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Income (loss) per common share
|
|
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|
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|
|
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Basic
|
|
$
|
0.39
|
|
|
$
|
(0.32
|
)
|
|
$
|
(1.88
|
)
|
Diluted
|
|
$
|
0.37
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|
|
$
|
(0.32
|
)
|
|
$
|
(1.88
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)
|
Weighted average number of common shares outstanding
|
|
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|
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Basic
|
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|
24,611,729
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|
21,466,813
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|
|
19,505,065
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|
Diluted
|
|
|
26,054,162
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|
|
21,466,813
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|
|
19,505,065
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-4
EnerNOC,
Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS
EQUITY
AND COMPREHENSIVE (LOSS) INCOME
(In thousands, except share
data)
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|
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|
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Accumulated
|
|
|
|
|
|
|
|
|
|
|
|
|
Common Stock
|
|
|
Additional
|
|
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Other
|
|
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Number of
|
|
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|
|
Paid in
|
|
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Comprehensive
|
|
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Accumulated
|
|
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|
Comprehensive
|
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|
Shares
|
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Amount
|
|
|
Capital
|
|
|
Loss
|
|
|
Deficit
|
|
|
Total
|
|
|
(Loss) Income
|
|
|
Balances as of December 31, 2007
|
|
|
19,180,504
|
|
|
$
|
19
|
|
|
$
|
156,250
|
|
|
$
|
|
|
|
$
|
(33,852
|
)
|
|
$
|
122,417
|
|
|
$
|
|
|
Issuance of common stock upon exercise of stock options
|
|
|
706,823
|
|
|
|
1
|
|
|
|
456
|
|
|
|
|
|
|
|
|
|
|
|
457
|
|
|
|
|
|
Issuance of restricted stock
|
|
|
177,500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vesting of restricted stock
|
|
|
|
|
|
|
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
20
|
|
|
|
|
|
Cancellation of restricted stock
|
|
|
(1,500
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock in satisfaction of bonuses
|
|
|
26,961
|
|
|
|
|
|
|
|
845
|
|
|
|
|
|
|
|
|
|
|
|
845
|
|
|
|
|
|
Issuance of common stock in connection with the acquisition of
Pinpoint Power DR LLC
|
|
|
44,260
|
|
|
|
|
|
|
|
44
|
|
|
|
|
|
|
|
|
|
|
|
44
|
|
|
|
|
|
Issuance of common stock in connection with the acquisition of
South River Consulting, LLC
|
|
|
120,000
|
|
|
|
|
|
|
|
1,746
|
|
|
|
|
|
|
|
|
|
|
|
1,746
|
|
|
|
|
|
Stock based compensation expense
|
|
|
|
|
|
|
|
|
|
|
10,439
|
|
|
|
|
|
|
|
|
|
|
|
10,439
|
|
|
|
|
|
Unrealized gain on marketable securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5
|
|
|
|
|
|
|
|
5
|
|
|
|
5
|
|
Foreign currency translation loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(91
|
)
|
|
|
|
|
|
|
(91
|
)
|
|
|
(91
|
)
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(36,662
|
)
|
|
|
(36,662
|
)
|
|
|
(36,662
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances as of December 31, 2008
|
|
|
20,254,548
|
|
|
|
20
|
|
|
|
169,800
|
|
|
|
(86
|
)
|
|
|
(70,514
|
)
|
|
|
99,220
|
|
|
|
(36,748
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock upon exercise of stock options
|
|
|
426,744
|
|
|
|
|
|
|
|
1,078
|
|
|
|
|
|
|
|
|
|
|
|
1,078
|
|
|
|
|
|
Issuance of restricted stock
|
|
|
81,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vesting of restricted stock
|
|
|
|
|
|
|
|
|
|
|
20
|
|
|
|
|
|
|
|
|
|
|
|
20
|
|
|
|
|
|
Cancellation of restricted stock
|
|
|
(10,063
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock in satisfaction of bonuses
|
|
|
45,085
|
|
|
|
|
|
|
|
500
|
|
|
|
|
|
|
|
|
|
|
|
500
|
|
|
|
|
|
Issuance of common stock in connection with the acquisition of
Cogent Energy, Inc.
|
|
|
114,281
|
|
|
|
|
|
|
|
3,162
|
|
|
|
|
|
|
|
|
|
|
|
3,162
|
|
|
|
|
|
Issuance of common stock in connection with the acquisition of
eQuilibrium Solutions Corporation
|
|
|
21,464
|
|
|
|
|
|
|
|
501
|
|
|
|
|
|
|
|
|
|
|
|
501
|
|
|
|
|
|
Issuance of common stock in connection with the public offering,
net of issuance costs of $4,468
|
|
|
3,254,863
|
|
|
|
4
|
|
|
|
83,421
|
|
|
|
|
|
|
|
|
|
|
|
83,425
|
|
|
|
|
|
Earn-out payment of common stock to South River Consulting, LLC
|
|
|
44,776
|
|
|
|
|
|
|
|
734
|
|
|
|
|
|
|
|
|
|
|
|
734
|
|
|
|
|
|
Stock based compensation expense
|
|
|
|
|
|
|
|
|
|
|
13,134
|
|
|
|
|
|
|
|
|
|
|
|
13,134
|
|
|
|
|
|
Foreign currency translation gain
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30
|
|
|
|
|
|
|
|
30
|
|
|
|
30
|
|
Net loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,829
|
)
|
|
|
(6,829
|
)
|
|
|
(6,829
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances as of December 31, 2009
|
|
|
24,233,448
|
|
|
|
24
|
|
|
|
272,350
|
|
|
|
(56
|
)
|
|
|
(77,343
|
)
|
|
|
194,975
|
|
|
|
(6,799
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock upon exercise of stock options
|
|
|
583,796
|
|
|
|
|
|
|
|
3,861
|
|
|
|
|
|
|
|
|
|
|
|
3,861
|
|
|
|
|
|
Issuance of restricted stock
|
|
|
247,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vesting of restricted stock
|
|
|
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
17
|
|
|
|
|
|
Vesting of restricted stock units
|
|
|
51,876
|
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cancellation of restricted stock
|
|
|
(22,679
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock in satisfaction of bonuses
|
|
|
24,681
|
|
|
|
|
|
|
|
775
|
|
|
|
|
|
|
|
|
|
|
|
775
|
|
|
|
|
|
Issuance of common stock in connection with the acquisition of
SmallFoot LLC and ZOX, LLC
|
|
|
8,758
|
|
|
|
|
|
|
|
260
|
|
|
|
|
|
|
|
|
|
|
|
260
|
|
|
|
|
|
Earn-out payment of common stock to South River Consulting, LLC
|
|
|
30,879
|
|
|
|
|
|
|
|
900
|
|
|
|
|
|
|
|
|
|
|
|
900
|
|
|
|
|
|
Release and retirement of escrow shares to satisfy purchase
accounting obligation from Cogent Energy, Inc.
|
|
|
(3,592
|
)
|
|
|
|
|
|
|
(94
|
)
|
|
|
|
|
|
|
|
|
|
|
(94
|
)
|
|
|
|
|
Stock based compensation expense
|
|
|
|
|
|
|
|
|
|
|
15,742
|
|
|
|
|
|
|
|
|
|
|
|
15,742
|
|
|
|
|
|
Tax benefit related to exercise of stock options and vesting of
restricted stock and restricted stock units
|
|
|
|
|
|
|
|
|
|
|
132
|
|
|
|
|
|
|
|
|
|
|
|
132
|
|
|
|
|
|
Foreign currency translation loss
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19
|
)
|
|
|
|
|
|
|
(19
|
)
|
|
|
(19
|
)
|
Net income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,577
|
|
|
|
9,577
|
|
|
|
9,577
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balances as of December 31, 2010
|
|
|
25,155,067
|
|
|
$
|
25
|
|
|
$
|
293,942
|
|
|
$
|
(75
|
)
|
|
$
|
(67,766
|
)
|
|
$
|
226,126
|
|
|
$
|
9,558
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements.
F-5
EnerNOC,
Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Cash flow from operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
9,577
|
|
|
$
|
(6,829
|
)
|
|
$
|
(36,662
|
)
|
Adjustments to reconcile net income (loss) to net cash provided
by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
|
|
|
14,414
|
|
|
|
11,357
|
|
|
|
8,035
|
|
Amortization of acquired intangible assets
|
|
|
1,452
|
|
|
|
692
|
|
|
|
1,019
|
|
Write-down of intangible assets
|
|
|
|
|
|
|
135
|
|
|
|
|
|
Stock based compensation expense
|
|
|
15,742
|
|
|
|
13,134
|
|
|
|
10,439
|
|
Excess tax benefit related to exercise of options and vesting of
restricted stock and restricted stock units
|
|
|
(132
|
)
|
|
|
|
|
|
|
|
|
Impairment of property and equipment
|
|
|
1,646
|
|
|
|
1,191
|
|
|
|
701
|
|
Unrealized foreign exchange transaction loss
|
|
|
133
|
|
|
|
86
|
|
|
|
|
|
Deferred taxes
|
|
|
469
|
|
|
|
292
|
|
|
|
262
|
|
Non-cash interest expense
|
|
|
26
|
|
|
|
60
|
|
|
|
520
|
|
Loss on disposal of equipment
|
|
|
|
|
|
|
26
|
|
|
|
|
|
Other, net
|
|
|
143
|
|
|
|
33
|
|
|
|
|
|
Changes in operating assets and liabilities, net of effects of
acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable, trade
|
|
|
(4,886
|
)
|
|
|
(4,582
|
)
|
|
|
(887
|
)
|
Unbilled revenue
|
|
|
(32,754
|
)
|
|
|
(28,622
|
)
|
|
|
(11,585
|
)
|
Prepaid expenses and other current assets
|
|
|
(666
|
)
|
|
|
(2,778
|
)
|
|
|
657
|
|
Other assets
|
|
|
3
|
|
|
|
(940
|
)
|
|
|
(103
|
)
|
Other noncurrent liabilities
|
|
|
|
|
|
|
254
|
|
|
|
247
|
|
Deferred revenue
|
|
|
6,751
|
|
|
|
997
|
|
|
|
(884
|
)
|
Accrued capacity payments
|
|
|
25,223
|
|
|
|
21,871
|
|
|
|
9,579
|
|
Accrued payroll and related expenses
|
|
|
2,199
|
|
|
|
3,873
|
|
|
|
1,408
|
|
Accounts payable and accrued expenses
|
|
|
5,808
|
|
|
|
(2,164
|
)
|
|
|
2,047
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) operating activities
|
|
|
45,148
|
|
|
|
8,086
|
|
|
|
(15,207
|
)
|
Cash flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchase of marketable securities
|
|
|
|
|
|
|
|
|
|
|
(13,637
|
)
|
Sales and maturities of marketable securities
|
|
|
|
|
|
|
2,000
|
|
|
|
27,142
|
|
Payments made for acquisitions of businesses, net of cash
acquired
|
|
|
(2,001
|
)
|
|
|
(7,203
|
)
|
|
|
(7,523
|
)
|
Purchases of property and equipment
|
|
|
(19,394
|
)
|
|
|
(16,901
|
)
|
|
|
(12,459
|
)
|
Change in restricted cash and deposits
|
|
|
5,971
|
|
|
|
(7,068
|
)
|
|
|
13,371
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash (used in) provided by investing activities
|
|
|
(15,424
|
)
|
|
|
(29,172
|
)
|
|
|
6,894
|
|
Cash flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from public offerings of common stock, net of issuance
costs
|
|
|
|
|
|
|
83,425
|
|
|
|
|
|
Proceeds from exercises of stock options
|
|
|
3,878
|
|
|
|
1,078
|
|
|
|
457
|
|
Proceeds from borrowings
|
|
|
|
|
|
|
|
|
|
|
4,352
|
|
Repayment of borrowings and payments under capital leases
|
|
|
(36
|
)
|
|
|
(4,490
|
)
|
|
|
(5,879
|
)
|
Excess tax benefit related to exercise of options and vesting of
restricted stock and restricted stock units
|
|
|
132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by (used in) financing activities
|
|
|
3,974
|
|
|
|
80,013
|
|
|
|
(1,070
|
)
|
Effects of exchange rate changes on cash and cash equivalents
|
|
|
(21
|
)
|
|
|
30
|
|
|
|
(77
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in cash and cash equivalents
|
|
|
33,677
|
|
|
|
58,957
|
|
|
|
(9,460
|
)
|
Cash and cash equivalents at beginning of period
|
|
|
119,739
|
|
|
|
60,782
|
|
|
|
70,242
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period
|
|
$
|
153,416
|
|
|
$
|
119,739
|
|
|
$
|
60,782
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental disclosure of cash flow information
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
699
|
|
|
$
|
1,536
|
|
|
$
|
524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for income taxes
|
|
$
|
360
|
|
|
$
|
|
|
|
$
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-cash financing and investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred related party stock issuance for Pinpoint Power DR LLC
|
|
$
|
|
|
|
$
|
|
|
|
$
|
44
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock in connection with acquisitions
|
|
$
|
1,066
|
|
|
$
|
4,397
|
|
|
$
|
1,746
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Issuance of common stock in satisfaction of bonuses
|
|
$
|
775
|
|
|
$
|
500
|
|
|
$
|
845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of these
consolidated financial statements
F-6
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 Companys
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
F-7
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 Companys 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 Companys
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
Companys 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 Companys 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 Companys 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 Companys
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
F-8
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 Companys 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 Companys 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
Companys 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 Companys
consolidated financial statements will reflect M2Ms
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 Companys 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 Companys 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 Companys
consolidated financial statements will reflect GEPs
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
F-9
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 Companys 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 managements
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 Companys 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 Companys financial instruments mainly consist of cash
and cash equivalents, restricted cash, accounts receivable,
accounts payable and debt obligations. The carrying amounts of
the Companys 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 Companys 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 Companys losses
related to collection of trade receivables have
F-10
consistently been within the Companys 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 Companys 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
% of Total
|
|
|
|
|
|
% of Total
|
|
|
|
|
|
% of Total
|
|
|
|
Revenues
|
|
|
Revenues
|
|
|
Revenues
|
|
|
Revenues
|
|
|
Revenues
|
|
|
Revenues
|
|
|
PJM Interconnection
|
|
$
|
167,662
|
|
|
|
60
|
%
|
|
$
|
98,416
|
|
|
|
52
|
%
|
|
$
|
30,012
|
|
|
|
28
|
%
|
ISO-New England, Inc.
|
|
|
51,592
|
|
|
|
18
|
%
|
|
|
56,107
|
|
|
|
29
|
%
|
|
|
38,638
|
|
|
|
36
|
%
|
Connecticut Light and Power
|
|
|
|
|
|
|
|
%
|
|
|
|
|
|
|
|
%
|
|
|
16,118
|
|
|
|
15
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
219,254
|
|
|
|
78
|
%
|
|
$
|
154,523
|
|
|
|
81
|
%
|
|
$
|
84,768
|
|
|
|
79
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 Companys 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.
F-11
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
F-12
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 Companys 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
Companys 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 Companys 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
F-13
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
assets 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 Companys 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
As of December 31, 2010
|
|
|
As of December 31, 2009
|
|
|
|
Amortization
|
|
|
Gross
|
|
|
|
|
|
Gross
|
|
|
|
|
|
|
Period (in
|
|
|
Carrying
|
|
|
Accumulated
|
|
|
Carrying
|
|
|
Accumulated
|
|
|
|
Years)
|
|
|
Amount
|
|
|
Amortization
|
|
|
Amount
|
|
|
Amortization
|
|
|
Customer contracts
|
|
|
6.27
|
|
|
$
|
4,217
|
|
|
$
|
(1,593
|
)
|
|
$
|
4,217
|
|
|
$
|
(1,180
|
)
|
Employment agreements and non-compete agreements
|
|
|
2.34
|
|
|
|
772
|
|
|
|
(309
|
)
|
|
|
772
|
|
|
|
(118
|
)
|
Software
|
|
|
1.48
|
|
|
|
120
|
|
|
|
(63
|
)
|
|
|
120
|
|
|
|
(23
|
)
|
Customer relationships
|
|
|
6.08
|
|
|
|
3,510
|
|
|
|
(1,016
|
)
|
|
|
3,510
|
|
|
|
(333
|
)
|
Trade name
|
|
|
|
|
|
|
115
|
|
|
|
(115
|
)
|
|
|
115
|
|
|
|
(5
|
)
|
Patents
|
|
|
9.19
|
|
|
|
200
|
|
|
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
$
|
8,934
|
|
|
$
|
(3,111
|
)
|
|
$
|
8,734
|
|
|
$
|
(1,659
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
F-14
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 Companys 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 Smallfoots 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 technologys 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 Companys annual impairment test date is
November 30.
F-15
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 units 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 Companys 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:
|
|
|
|
|
Balance at December 31, 2008
|
|
$
|
13,395
|
|
SRC earn-out
|
|
|
1,468
|
|
Acquisition of eQ
|
|
|
153
|
|
Acquisition of Cogent
|
|
|
7,537
|
|
|
|
|
|
|
Balance at December 31, 2009
|
|
|
22,553
|
|
Acquisition of Smallfoot and Zox
|
|
|
240
|
|
Purchase price adjustments related to Cogent
|
|
|
20
|
|
SRC earn-out
|
|
|
1,840
|
|
|
|
|
|
|
Balance at December 31, 2010
|
|
$
|
24,653
|
|
|
|
|
|
|
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 Companys deferred tax liabilities primarily
relate to deferred taxes associated with the Companys
acquisitions and property and equipment. The Companys
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,
F-16
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
Companys worldwide income tax provision. In the
Companys 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
Companys historical income tax provisions and accruals. In
the event the Companys 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
Companys 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 Companys 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 Companys 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 Companys 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:
|
|
|
|
|
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.
|
|
|
|
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.
|
|
|
|
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.
|
F-17
|
|
|
|
|
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 Companys 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 Companys 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 Companys 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
F-18
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
Companys 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 Companys international
subsidiaries are translated in accordance with ASC 830,
Foreign Currency Matters (formerly SFAS No. 52,
Foreign Currency Translation), into the Companys
reporting currency, which is the United States dollar. The
functional currencies of the Companys 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.
F-19
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 managements 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 entitys 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 Companys consolidated
financial position or results of operations.
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 Companys 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
Companys common stock, as reported on The NASDAQ Global
Market (NASDAQ) on March 15, 2010. The Company believes
that Smallfoots technology will reduce deployment costs
and accelerate deeper market penetration into C&I
customers, specifically smaller C&I customers. The Company
believes Zoxs smart grid communications and metering
technology provides a
F-20
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:
|
|
|
|
|
In-process research and development
|
|
$
|
920
|
|
Patents
|
|
|
200
|
|
Goodwill
|
|
|
240
|
|
|
|
|
|
|
Total
|
|
$
|
1,360
|
|
|
|
|
|
|
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.
F-21
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 Companys 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 Companys common stock, as reported on
NASDAQ on December 4, 2009. As a result of gathering
information to update the Companys 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 Companys common stock that were
previously held in escrow in connection with the Cogent
acquisition. Upon release, the Companys 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 as of December 4, 2009
|
|
$
|
1,331
|
|
Customer relationships
|
|
|
1,400
|
|
Non-compete agreements
|
|
|
590
|
|
Trade name
|
|
|
200
|
|
Goodwill
|
|
|
7,557
|
|
|
|
|
|
|
Total
|
|
$
|
11,078
|
|
|
|
|
|
|
Net tangible assets acquired in the acquisition of Cogent
primarily related to the following:
|
|
|
|
|
Cash
|
|
$
|
336
|
|
Accounts receivable
|
|
|
1,777
|
|
Prepaids and other assets
|
|
|
77
|
|
Accounts payable
|
|
|
(331
|
)
|
Accrued expenses
|
|
|
(528
|
)
|
|
|
|
|
|
Total
|
|
$
|
1,331
|
|
|
|
|
|
|
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 Companys common stock that had a
value of approximately $501. These shares were measured as of
the acquisition date using the closing price of the
Companys 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
Companys consolidated financial statements reflect
eQs results of operations from June 11, 2009 forward.
F-22
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 Companys 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 SRCs 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 Companys 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 Companys 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
Companys 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.
A reconciliation of basic and diluted share amounts for the
years ended December 31, 2010, 2009 and 2008 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
Basic weighted average common shares outstanding
|
|
|
24,612
|
|
|
|
21,467
|
|
|
|
19,505
|
|
Weighted average common stock equivalents
|
|
|
1,442
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted weighted average common shares outstanding
|
|
|
26,054
|
|
|
|
21,467
|
|
|
|
19,505
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average anti-dilutive shares related to:
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options
|
|
|
497
|
|
|
|
3,239
|
|
|
|
2,841
|
|
Nonvested restricted stock
|
|
|
127
|
|
|
|
200
|
|
|
|
280
|
|
Restricted stock units
|
|
|
22
|
|
|
|
106
|
|
|
|
|
|
Escrow shares
|
|
|
|
|
|
|
129
|
|
|
|
100
|
|
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
equivalents 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
Companys 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.
F-23
|
|
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:
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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.
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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.
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Level 3 Valuation is generated from model-based
techniques that use significant assumptions not observable in
the market. These unobservable assumptions reflect the
Companys own estimates of assumptions market participants
would use in pricing the asset or liability.
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The table below presents the balances of assets and liabilities
measured at fair value on a recurring basis at December 31,
2010:
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Fair Value Measurement at December 31, 2010 Using
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Quoted Prices
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Significant
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in Active
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Other
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Markets for
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Observable
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Unobservable
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Identical Assets
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Inputs
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Inputs
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Totals
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(Level 1)
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(Level 2)
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(Level 3)
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Money market funds(1)
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$
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108,000
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$
|
108,000
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|
$
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$
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Certificates of deposit(2)
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1,300
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1,300
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$
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109,300
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$
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109,300
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$
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$
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(1) |
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Included in cash and cash equivalents in the accompanying
consolidated balance sheets. |
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(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 Companys 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.
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5.
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Allowance
for Doubtful Accounts
|
The Company reduces gross trade accounts receivable by an
allowance for doubtful accounts. The allowance for doubtful
accounts is the Companys best estimate of the amount of
probable credit losses in the Companys 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 Companys allowance for
doubtful accounts for the years ended December 31, 2010,
2009 and 2008.
F-24
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Balance at
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Additions
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Deductions Write-
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Beginning of
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Charged to
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Offs, Payments and
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Balance at
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Period
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Expense
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Other Adjustments
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End of Period
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Year ended December 31, 2010
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$
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57
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$
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160
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$
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(67
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)
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$
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150
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Year ended December 31, 2009
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$
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37
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$
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33
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$
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(13
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)
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$
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57
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Year ended December 31, 2008
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$
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368
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$
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$
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(331
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)
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$
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37
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6.
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Property
and Equipment
|
Property and equipment as of December 31, 2010 and
December 31, 2009 consisted of the following:
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Estimated Useful Life (Years)
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December 31, 2010
|
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December 31, 2009
|
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Computers and office equipment
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3
|
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$
|
12,374
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|
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$
|
10,549
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Software
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2 - 3
|
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16,652
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9,874
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Demand response equipment
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Lesser of useful life or estimated
commercial, institutional and industrial
customer relationship period
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24,849
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17,362
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Back-up
generators
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5 - 10
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9,560
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10,431
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Furniture and fixtures
|
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5
|
|
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1,490
|
|
|
|
1,072
|
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Leasehold improvements
|
|
Lesser of the useful life
or original lease term
|
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1,998
|
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|
1,952
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Assets under capital lease
|
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Lesser of the useful life
or original lease term
|
|
|
222
|
|
|
|
222
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Construction-in-progress
|
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3,854
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2,302
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|
|
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70,999
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|
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53,764
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Accumulated depreciation
|
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|
(36,309
|
)
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(22,420
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)
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Property and equipment, net
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$
|
34,690
|
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$
|
31,344
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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 Companys 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.
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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 Companys account. The
interest on loans under the Companys revolving credit loan
accrues at interest rates based upon either SVBs prime
rate or the 30, 60 or
90-day LIBOR
plus 2.25%, at the Companys election. The interest on term
loans accrues at SVBs prime rate plus 0.50% or the 30, 60
or 90-day
LIBOR plus 2.75%, at the Companys 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 Companys 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 Companys 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
Companys ability to incur additional
F-25
indebtedness, create liens, enter into transactions with
affiliates, transfer assets, pay dividends or make distributions
on, or repurchase, the Companys 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 Companys
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 Companys 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 Companys 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:
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|
|
|
|
|
|
December 31, 2010
|
|
|
December 31, 2009
|
|
|
Obligations under capital leases
|
|
$
|
37
|
|
|
$
|
73
|
|
Less current maturities
|
|
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|
(36
|
)
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|
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|
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$
|
37
|
|
|
$
|
37
|
|
|
|
|
|
|
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|
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 Companys board of directors approved an
amendment and restatement of the Companys 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
Companys Amended and Restated 2007 Employee, Director and
Consultant Stock Plan (the 2007 Plan).
F-26
|
|
9.
|
Stock-Based
Compensation
|
Stock
Options
The Companys 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 Companys 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
Companys 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
Companys 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 Companys
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:
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|
|
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|
|
Year Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
Risk-free interest rate
|
|
|
3.5
|
%
|
|
|
3.2
|
%
|
|
2.9%
|
Expected term of options, in years(1)
|
|
|
|
|
|
|
|
|
|
4.256.25
|
Vesting term, in years(1)
|
|
|
2.17
|
|
|
|
2.16
|
|
|
|
Expected annual volatility
|
|
|
85
|
%
|
|
|
86
|
%
|
|
87%
|
Expected dividend yield
|
|
|
|
%
|
|
|
|
%
|
|
%
|
Exit rate pre-vesting(1)
|
|
|
5.95
|
%
|
|
|
4.88
|
%
|
|
%
|
Exit rate post-vesting(1)
|
|
|
11.49
|
%
|
|
|
10.89
|
%
|
|
%
|
|
|
|
(1) |
|
Change in assumptions reflects the Companys 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 Companys 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
F-27
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 Companys 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:
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Stock options
|
|
$
|
9,406
|
|
|
$
|
9,781
|
|
|
$
|
9,398
|
|
Restricted stock and restricted stock units
|
|
|
6,336
|
|
|
|
3,353
|
|
|
|
1,041
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
15,742
|
|
|
$
|
13,134
|
|
|
$
|
10,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock based compensation is recorded in the accompanying
statements of operations, as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Selling and marketing expenses
|
|
$
|
4,709
|
|
|
$
|
3,989
|
|
|
$
|
3,692
|
|
General and administrative expenses
|
|
|
10,126
|
|
|
|
8,471
|
|
|
|
6,201
|
|
Research and development expenses
|
|
|
907
|
|
|
|
674
|
|
|
|
546
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$
|
15,742
|
|
|
$
|
13,134
|
|
|
$
|
10,439
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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.
F-28
The following is a summary of the Companys stock option
activity during the year ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of
|
|
|
|
|
|
Weighted-
|
|
|
|
|
|
|
Shares
|
|
|
|
|
|
Average
|
|
|
Aggregate
|
|
|
|
Underlying
|
|
|
Exercise Price
|
|
|
Exercise Price
|
|
|
Intrinsic
|
|
|
|
Options
|
|
|
Per Share
|
|
|
Per Share
|
|
|
Value
|
|
|
Outstanding at December 31, 2009
|
|
|
2,503,975
|
|
|
$
|
0.11$48.54
|
|
|
$
|
10.84
|
|
|
$
|
49,599
|
(2)
|
Granted
|
|
|
312,868
|
|
|
|
|
|
|
|
29.61
|
|
|
|
|
|
Exercised
|
|
|
(583,796
|
)
|
|
|
|
|
|
|
6.61
|
|
|
$
|
13,702
|
(3)
|
Cancelled
|
|
|
(120,688
|
)
|
|
|
|
|
|
|
18.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2010
|
|
|
2,112,359
|
|
|
$
|
0.17$48.06
|
|
|
|
14.38
|
|
|
$
|
23,948
|
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average remaining contractual life in years: 5.8
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at end of period
|
|
|
1,320,574
|
|
|
$
|
0.17$48.06
|
|
|
$
|
9.93
|
|
|
$
|
19,794
|
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average remaining contractual life in years: 5.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested or expected to vest at December 31, 2010(1)
|
|
|
2,065,298
|
|
|
$
|
0.17$48.06
|
|
|
$
|
14.12
|
|
|
$
|
23,837
|
(4)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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
Companys 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 Companys
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
Companys common stock on December 31, 2010 of $23.91
and the exercise price of the underlying options. |
In December 2008, the Companys board of directors approved
a one-time offer to the Companys 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
Companys 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 Companys 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.
F-29
Additional
Information About Stock Options
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
In thousands, except share and
|
|
|
per share amounts
|
|
Total number of options granted during the year
|
|
|
312,868
|
|
|
|
1,161,504
|
|
|
|
707,151
|
|
Weighted-average fair value per share of options granted
|
|
$
|
18.81
|
|
|
$
|
13.16
|
|
|
$
|
14.80
|
|
Total intrinsic value of options exercised(1)
|
|
$
|
13,702
|
|
|
$
|
8,267
|
|
|
$
|
4,799
|
|
|
|
|
(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 Companys restricted
stock activity during the year ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
Number of
|
|
Grant Date Fair
|
|
|
Shares
|
|
Value Per Share
|
|
Nonvested at December 31, 2009
|
|
|
188,618
|
|
|
$
|
23.42
|
|
Granted
|
|
|
247,900
|
|
|
|
30.14
|
|
Vested
|
|
|
(158,943
|
)
|
|
|
22.68
|
|
Cancelled
|
|
|
(22,679
|
)
|
|
|
27.74
|
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2010
|
|
|
254,896
|
|
|
$
|
29.99
|
|
|
|
|
|
|
|
|
|
|
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.
F-30
Additional
Information About Restricted Stock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
2010
|
|
2009
|
|
2008
|
|
|
In thousands, except share and per share amounts
|
|
Total number of shares of restricted stock granted during the
year
|
|
|
247,900
|
|
|
|
81,750
|
|
|
|
177,500
|
|
Weighted average fair value per share of restricted stock granted
|
|
$
|
30.14
|
|
|
$
|
28.06
|
|
|
$
|
26.41
|
|
Total number of shares of restricted stock vested during the year
|
|
|
158,943
|
|
|
|
159,603
|
|
|
|
54,135
|
|
Total fair value of shares of restricted stock vested during the
year
|
|
$
|
4,691
|
|
|
$
|
3,088
|
|
|
$
|
907
|
|
Restricted
Stock Units
The following table summarizes the Companys restricted
stock unit activity during the year ended December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
Number of
|
|
|
Grant Date Fair
|
|
|
|
Shares
|
|
|
Value Per Share
|
|
|
Nonvested at December 31, 2009
|
|
|
114,000
|
|
|
$
|
11.55
|
|
Granted
|
|
|
326,000
|
|
|
|
28.99
|
|
Vested
|
|
|
(51,876
|
)
|
|
|
12.21
|
|
Cancelled
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonvested at December 31, 2010
|
|
|
388,124
|
|
|
$
|
26.11
|
|
|
|
|
|
|
|
|
|
|
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.
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
United States
|
|
$
|
10,086
|
|
|
$
|
(5,223
|
)
|
|
$
|
(36,500
|
)
|
Foreign
|
|
|
327
|
|
|
|
(1,273
|
)
|
|
|
100
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
10,413
|
|
|
$
|
(6,496
|
)
|
|
$
|
(36,400
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-31
The provision for income taxes is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
|
|
|
$
|
|
|
|
$
|
|
|
State
|
|
|
165
|
|
|
|
|
|
|
|
|
|
Foreign
|
|
|
202
|
|
|
|
41
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
367
|
|
|
|
41
|
|
|
|
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
401
|
|
|
|
248
|
|
|
|
222
|
|
State
|
|
|
87
|
|
|
|
44
|
|
|
|
40
|
|
Foreign
|
|
|
(19
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
469
|
|
|
|
292
|
|
|
|
262
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
836
|
|
|
$
|
333
|
|
|
$
|
262
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
2008
|
|
|
Federal income tax at statutory federal rate
|
|
|
34.0
|
%
|
|
|
(34.0
|
)%
|
|
|
(34.0
|
)%
|
State taxes
|
|
|
1.9
|
|
|
|
0.7
|
|
|
|
0.1
|
|
Tax-deductible goodwill
|
|
|
3.9
|
|
|
|
3.8
|
|
|
|
0.6
|
|
Foreign losses not benefited
|
|
|
|
|
|
|
6.7
|
|
|
|
|
|
Stock-based compensation expense
|
|
|
8.3
|
|
|
|
24.5
|
|
|
|
5.0
|
|
Foreign dividends
|
|
|
4.2
|
|
|
|
|
|
|
|
|
|
Other
|
|
|
(0.5
|
)
|
|
|
1.9
|
|
|
|
0.1
|
|
Change in valuation allowance
|
|
|
(43.8
|
)
|
|
|
1.5
|
|
|
|
28.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.0
|
%
|
|
|
5.1
|
%
|
|
|
0.7
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
F-32
Deferred tax assets (liabilities) consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31,
|
|
|
|
2010
|
|
|
2009
|
|
|
Deferred income tax assets:
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards
|
|
$
|
20,055
|
|
|
$
|
19,919
|
|
Intangible assets
|
|
|
64
|
|
|
|
|
|
Reserves and accruals
|
|
|
|
|
|
|
2,259
|
|
Deferred revenue
|
|
|
261
|
|
|
|
788
|
|
Deferred rent
|
|
|
209
|
|
|
|
226
|
|
Stock options
|
|
|
5,699
|
|
|
|
3,852
|
|
Tax credits and other
|
|
|
506
|
|
|
|
73
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
26,794
|
|
|
$
|
27,117
|
|
|
|
|
|
|
|
|
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Property and equipment
|
|
$
|
(5,378
|
)
|
|
$
|
(2,947
|
)
|
Reserves and accruals
|
|
|
(745
|
)
|
|
|
|
|
Intangible assets
|
|
|
|
|
|
|
(333
|
)
|
Tax deductible goodwill
|
|
|
(1,141
|
)
|
|
|
(654
|
)
|
|
|
|
|
|
|
|
|
|
Total deferred tax liabilities
|
|
|
(7,264
|
)
|
|
|
(3,934
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax assets before valuation allowance
|
|
|
19,530
|
|
|
|
23,183
|
|
Valuation allowance
|
|
|
(20,652
|
)
|
|
|
(23,837
|
)
|
|
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
|
(1,122
|
)
|
|
|
(654
|
)
|
Current deferred tax asset
|
|
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Noncurrent deferred tax liability
|
|
$
|
(1,141
|
)
|
|
$
|
(654
|
)
|
|
|
|
|
|
|
|
|
|
Due to the uncertainty related to the ultimate use of the
Companys 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 Companys 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 Companys 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
F-33
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
Companys 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 Companys 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:
|
|
|
|
|
|
|
Operating Leases
|
|
|
2011
|
|
$
|
4,602
|
|
2012
|
|
|
3,671
|
|
2013
|
|
|
3,307
|
|
2014
|
|
|
1,799
|
|
2015
|
|
|
162
|
|
|
|
|
|
|
Total minimum lease payments
|
|
$
|
13,541
|
|
|
|
|
|
|
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
Companys 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 Companys 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
F-34
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 Companys 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 Companys 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 Companys risk in
paying out any claims under these indemnification provisions.
F-35
Exhibit Index
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Number
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Exhibit Title
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2
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.1*
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Stock Purchase Agreement, dated as of December 2, 2010, by
and among EnerNOC Inc., Global Energy Partners, Inc., The Global
Energy Partners, Inc., Employee Stock Ownership Trust and
certain individuals named herein.
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3
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.1
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Amended and Restated Certificate of Incorporation of EnerNOC,
Inc., filed as Exhibit 3.2 to the Registrants
Form S-1/A
filed May 3, 2007 (File
No. 333-140632),
is hereby incorporated by reference as Exhibit 3.1.
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3
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.2
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Amended and Restated Bylaws of EnerNOC, Inc., filed as
Exhibit 3.4 to the Registrants
Form S-1/A
filed May 3, 2007 (File
No. 333-140632),
is hereby incorporated by reference as Exhibit 3.2.
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4
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.1
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Form of Specimen Common Stock Certificate, filed as
Exhibit 4.1 to the Registrants
Form S-1/A
filed May 3, 2007 (File
No. 333-140632),
is hereby incorporated by reference as Exhibit 4.1.
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4
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.2
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Fifth Amended and Restated Investor Rights Agreement, filed as
Exhibit 4.1 to the Registrants
Form 10-Q
filed November 5, 2007 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 4.2.
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10
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.1*
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Loan and Security Agreement by and among EnerNOC, Inc., ENOC
Securities Corporation and Silicon Valley Bank, dated as of
August 5, 2008, as amended by the First Loan Modification
Agreement, dated as of May 29, 2009, Second Loan
Modification Agreement, dated as of April 23, 2010, Third
Loan Modification Agreement, dated as of July 30, 2010, the
Joinder and Amendment Agreement, dated as of December 27,
2010, and the Fourth Loan Modification Agreement, dated as of
February 4, 2011.
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10
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.2@
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Second Amended and Restated Employment Agreement, dated as of
March 1, 2010, by and between Timothy G. Healy and EnerNOC,
Inc. filed as Exhibit 10.3 to the Registrants Annual
Report on
Form 10-K
for the year ended December 31, 2009 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 10.2.
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10
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.3@
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Second Amended and Restated Employment Agreement, dated as of
March 1, 2010, by and between David B. Brewster and
EnerNOC, Inc. filed as Exhibit 10.4 to the
Registrants Annual Report on
Form 10-K
for the year ended December 31, 2009 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 10.3.
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10
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.4@
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Form of Severance Agreement by and between EnerNOC, Inc. and
each of Gregg Dixon and David Samuels, filed as
Exhibit 10.6 to the Registrants
Form S-1
filed February 12, 2007 (File
No. 333-140632),
is hereby incorporated by reference as Exhibit 10.4.
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10
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.5@
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Form of Amendment No. 1 to Form of Severance Agreement by
and between EnerNOC, Inc, and each of Gregg Dixon and David
Samuels, filed as Exhibit 10.3 to the Registrants
Form 10-Q
filed August 10, 2007 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 10.5.
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10
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.6
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Amended and Restated Office Lease, dated as of August 15,
2008, between Transwestern Federal, L.L.C. and EnerNOC, Inc.,
filed as Exhibit 10.1 to the Registrants Current
Report on
Form 8-K
filed August 20, 2008 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 10.6.
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10
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.7
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Sub-Sublease
Agreement by and between Prosodie Interactive California and
EnerNOC, Inc., dated May 30, 2008, filed as
Exhibit 10.1 to the Registrants
Form 10-Q
filed August 13, 2008 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 10.7.
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10
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.8
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Agreement of Lease, dated as of September 9, 2008, between
CRP/Capstone 14W Property Owner, L.L.C. and EnerNOC, Inc., filed
as Exhibit 10.1 to the Registrants Current Report on
Form 8-K
filed September 12, 2008 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 10.8.
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10
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.9@
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EnerNOC, Inc. Amended and Restated 2007 Employee, Director and
Consultant Stock Plan and HMRC
Sub-Plan for
UK Employees, and forms of agreement thereunder, filed as
Exhibit 10.1to the Registrants
Form 10-Q
filed November 9, 2010 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 10.9.
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10
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.10@
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EnerNOC, Inc. Amended and Restated Non-Employee Director
Compensation Policy, filed as Exhibit 10.1 to the
Registrants
Form 10-Q
filed May 7, 2010 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 10.10.
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10
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.11@*
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Summary of 2011 Executive Officer Bonus Plan.
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Number
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Exhibit Title
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10
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.12@
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Form of Indemnification Agreement between EnerNOC, Inc. and each
of the directors and executive officers thereof, filed as
Exhibit 10.21 to the Registrants Registration
Statement on
Form S-1,
as amended, filed May 3, 2007 (File
No. 333-140632),
is hereby incorporated by reference as Exhibit 10.12.
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10
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.13@
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Offer Letter, dated as of December 19, 2007, by and between
EnerNOC, Inc. and Darren P. Brady, filed as Exhibit 10.23
to the Registrants Annual Report on
Form 10-K
for the year ended December 31, 2007 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 10.13.
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10
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.14@
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Severance Agreement, dated as of January 22, 2008, by and
between EnerNOC, Inc. and Darren P. Brady filed as
Exhibit 10.1 to the Registrants Current Report on
Form 8-K/A
filed January 24, 2008 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 10.14.
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10
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.15@
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Offer Letter, dated as of July 27, 2009, between EnerNOC,
Inc. and Timothy Weller, filed as Exhibit 10.1 to the
Registrants Current Report on
Form 8-K
filed July 31, 2009 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 10.15.
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10
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.16@
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Severance Agreement, dated as of July 27, 2009, by and
between EnerNOC, Inc. and Timothy Weller, filed as
Exhibit 10.2 to the Registrants Current Report on
Form 8-K
filed July 31, 2009 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 10.16.
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10
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.17@
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Offer Letter, dated as of November 4, 2009, by and between
EnerNOC, Inc. and Kevin Bligh, filed as Exhibit 10.1 to the
Registrants Current Report on
Form 8-K
filed November 10, 2009 (File
No. 001-33471),
is hereby incorporated by reference as Exhibit 10.17.
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21
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.1*
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Subsidiaries of EnerNOC, Inc.
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23
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.1*
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Consent of Ernst & Young LLP, Independent Registered
Public Accounting Firm
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31
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.1*
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Certification of Chief Executive Officer of EnerNOC, Inc.
pursuant to
Rule 13a-14(a)
or
Rule 15d-14(a)
promulgated under the Securities Exchange Act of 1934, as
amended.
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31
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.2*
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Certification of Chief Financial Officer of EnerNOC, Inc.
pursuant to
Rule 13a-14(a)
or
Rule 15d-14(a)
promulgated under the Securities Exchange Act of 1934, as
amended.
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32
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.1*
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Certification of the Chief Executive Officer and Chief Financial
Officer of EnerNOC, Inc. pursuant to
Rule 13a-14(b)
promulgated under the Securities Exchange Act of 1934, as
amended, and 18 U.S.C. Section 1350, as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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@ |
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Management contract, compensatory plan or arrangement. |
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* |
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Filed herewith |