|
|
 | | | |
- close
- close
- close
- close
EnerNOC 10-Q 2011 Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549
FORM 10-Q
(Mark One)
For the quarterly period ended September 30, 2011
or
For the transition period from to
Commission File Number: 001-33471
EnerNOC, Inc.
(Exact Name of Registrant as Specified in Its Charter)
(617) 224-9900
(Registrant’s Telephone Number, Including Area Code) 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
þ No o
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 the definitions of “large
accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one):
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
There
were 26,792,090 shares of the registrant’s common stock, $0.001 par value per share,
outstanding as of November 3, 2011.
EnerNOC, Inc.
Index to Form 10-Q
2
Table of Contents
EnerNOC, Inc.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except par value and share data)
The accompanying notes are an integral part of these condensed consolidated financial statements.
3
Table of Contents
EnerNOC, Inc.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(in thousands, except share and per share data)
The accompanying notes are an integral part of these condensed consolidated financial statements.
4
Table of Contents
EnerNOC, Inc.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
The accompanying notes are an integral part of these condensed consolidated financial statements.
5
Table of Contents
EnerNOC, Inc.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except share and per share data)
1. Description of Business and Basis of Presentation
Description of Business
EnerNOC, Inc. (the Company) is a service company that was incorporated in Delaware on June 5,
2003. The Company operates in a single segment providing clean and intelligent energy management
applications and services for the smart grid, which include comprehensive demand response,
data-driven energy efficiency, energy price and risk management, and enterprise carbon management
applications and services. The Company’s energy management applications and services enable cost
effective energy management strategies for its commercial, institutional and industrial end-users
of energy (C&I customers) and its electric power grid operator and utility customers by reducing
real-time demand for electricity, increasing energy efficiency, improving energy supply
transparency, and mitigating emissions. The Company uses its Network Operations Center (NOC) and
comprehensive demand response application, DemandSMART, to remotely manage and reduce electricity
consumption across a growing network of C&I customer sites, making demand response capacity
available to electric power grid operators and utilities on demand while helping C&I customers
achieve energy savings, improved financial results and environmental benefits. To date, the Company
has received substantially all of its revenues from electric power grid operators and utilities,
who make recurring payments to the Company for managing demand response capacity that it shares
with its C&I customers in exchange for those C&I customers reducing their power consumption when
called upon.
The Company builds on its position as a leading demand response services provider by using its
NOC and energy management application platform to deliver a portfolio of additional energy
management applications and services to new and existing C&I, electric power grid operator and
utility customers. These additional energy management applications and services include its
EfficiencySMART, SupplySMART and CarbonSMART applications and services. EfficiencySMART is its
data-driven energy efficiency suite that includes commissioning and retro-commissioning authority
services, energy consulting and engineering services, a persistent commissioning application and an
enterprise energy management application for managing energy across a portfolio of sites.
SupplySMART is its energy price and risk management application that provides its C&I customers
located in restructured or deregulated markets throughout the United States with the ability to
more effectively manage the energy supplier selection process, including energy supply product
procurement and implementation, budget forecasting, and utility bill information management.
CarbonSMART is its enterprise carbon management application that supports and manages the
measurement, tracking, analysis, reporting and management of greenhouse gas emissions.
Reclassifications
The Company has reclassified certain costs in its unaudited condensed consolidated statements
of income for the three and nine months ended September 30, 2010 totaling $406 and $1,041,
respectively, previously included in selling and marketing expenses as general and administrative
expenses to more appropriately reflect the nature of these costs.
Basis of Consolidation
The unaudited condensed 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 January 3, 2011, the Company acquired all of the outstanding capital stock of Global Energy
Partners, Inc. (Global Energy) in a purchase business combination. Accordingly, the results of
Global Energy subsequent to that date are included in the Company’s unaudited condensed
consolidated statements of income.
On January 25, 2011, the Company acquired all of the outstanding capital stock of M2M
Communications Corporation (M2M) in a purchase business combination. Accordingly, the results of
M2M subsequent to that date are included in the Company’s unaudited condensed consolidated
statements of income.
6
Table of Contents
On July 1, 2011, the Company acquired all of the outstanding stock of Energy Response Holdings
Pty Ltd (Energy Response) in a purchase business combination. Accordingly, the results of Energy
Response subsequent to that date are included in the Company’s unaudited condensed consolidated
statements of income.
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.
There were no material recognizable subsequent events recorded or requiring disclosure in the
September 30, 2011 unaudited condensed consolidated financial statements.
Use of Estimates in Preparation of Financial Statements
The accompanying unaudited condensed consolidated financial statements have been prepared
pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). Certain
information and footnote disclosures normally included in financial statements prepared in
accordance with GAAP have been condensed or omitted pursuant to SEC rules and regulations. In the
opinion of the Company’s management, the unaudited condensed consolidated financial statements and
notes have been prepared on the same basis as the audited consolidated financial statements
contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2010,
and include all adjustments (consisting of normal, recurring adjustments) necessary for the fair
presentation of the Company’s financial position at September 30, 2011 and the statements of
income for the three and nine months ended September 30, 2011 and 2010 and statements of cash
flows from the nine months ended September 30, 2011 and 2010. Operating results for the three and
nine months ended September 30, 2011 are not necessarily indicative of the results to be expected
for any other interim period or the entire fiscal year ending December 31, 2011.
The preparation of these unaudited condensed 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, fair value of deferred acquisition consideration, fair value of accrued acquisition
contingent consideration, expected future cash flows including growth rates, discount rates,
terminal values and other assumptions and estimates used to evaluate the recoverability of
long-lived assets and goodwill, estimated fair values of intangible assets and goodwill,
amortization methods and periods, certain accrued expenses and other related charges, stock-based
compensation, contingent liabilities, tax reserves and recoverability of the Company’s net deferred
tax assets and related valuation allowance.
Although the Company regularly assesses these estimates, actual results could differ
materially. Changes in estimates are recorded in the period in which they become known. The Company
bases its estimates on historical experience and various other assumptions that it believes to be
reasonable under the circumstances. Actual results may differ from management’s estimates if these
results differ from historical experience or other assumptions prove not to be substantially
accurate, even if such assumptions are reasonable when made.
The Company is subject to a number of risks similar to those of other companies of similar and
different sizes both inside and outside of its industry, including, but not limited to, rapid
technological changes, competition from similar energy management applications and services
provided by larger companies, customer concentration, government regulations, market or program
rule changes, protection of proprietary rights and dependence on key individuals.
Revenue Recognition
The Company recognizes revenues in accordance with Accounting Standards Codification (ASC)
605, Revenue Recognition (ASC 605). In all of the Company’s arrangements, it does not recognize any
revenues until it can determine that 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:
7
Table of Contents
The Company enters into contracts and open market bidding programs with utilities and electric
power grid operators to provide demand response applications and services. Demand response revenues
consist of two elements: revenue earned based on the Company’s ability to deliver committed
capacity to its electric power grid operator and utility customers, which the Company refers to as
capacity revenue; and revenue earned based on additional payments made to the Company for the
amount of energy usage actually curtailed from the grid during a demand response event, which the
Company refers to as energy event revenue.
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 the Company to payments under the 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 the Company’s verified capacity is below the
previously verified amount, the electric power grid operator or utility customer will reduce future
payments based on the adjusted verified capacity amounts. Ongoing demand response revenue
recognized between demand response events or tests that are not subject to penalty or 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. Based on
the evaluation of the factors in ASC 605-45-45, including the fact that the Company is the primary
obligor and bears both the performance and credit risk related to its arrangements with electric
power grid operators and utility customers, the Company has determined that it is the principal in
these arrangements. Therefore, the Company records demand response revenues gross of the amounts
billed to the electric power grid operators and utility customers and records the amounts paid to
C&I customers as cost of revenues.
In one of the open market programs in which the Company participates, the program year
operates on a June to May basis and performance is measured based on the aggregate performance
during the months of June through September. As a result, fees received for the month of June
could potentially be subject to adjustment or refund based on performance during the months of July
through September. The Company concluded that it could reliably estimate the amount of fees
potentially subject to adjustment or refund and recorded a reserve for this amount in the month of
June. As of June 30, 2011, the Company recorded an estimated reserve of $9,260 related to
potential subsequent performance adjustments. The fees under this program were fixed as of
September 30, 2011 and based on final performance during the three months ended September 30, 2011,
the Company recorded a reduction in the estimated reserve totaling $3,690, which resulted in final
performance adjustments of $5,570. For the three months ended September 30, 2011 the impact of
this change in estimate on income before income tax and net income was $3,690 and $3,572,
respectively, and the impact of this change in estimate on diluted income per common share was
$0.13 per share. This change in estimate had no impact on the nine months ended September 30, 2011
nor will it impact any future periods. The Company’s performance estimates which provided the basis
for the estimated reserve as of June 30, 2011 were reasonably consistent with the actual
performance during events and test events during the three months ended September 30, 2011. The
primary driver of the change in estimate from June 30, 2011 to September 30, 2011 was due to the
differences based on the number and type of events by which performance is measured, which is not
within the Company’s control. The Company is in the process of re-evaluating its ability to
reliably estimate the amount of fees potentially subject to adjustment or refund for the year
ending December 31, 2012 (fiscal 2012) on a prospective basis based on its consideration of its
actual performance during the months of June 2011 through September 2011, as well as, additional
guidance issued by the customer regarding its interpretation of certain program rules that will
impact performance calculations on a prospective basis. As there are no revenues recognized
related to this open market program during the fourth quarter of the Company’s fiscal year, any
change in the Company’s evaluation of its ability to reliably estimate the amount of fees
potentially subject to adjustment or refund would have no impact on the results of operations for
the three months ending December 31, 2011.
8
Table of Contents
As a result of contractual amendments entered into during the three months ended March 31,
2011 and the three months ended September 30, 2011 to amend certain refund provisions included in
one of the Company’s contracts with a utility customer, the Company concluded that it could
reliably estimate the fees potentially subject to refund and, therefore, the fees under this
arrangement were fixed or determinable. As a result, during the three months ended March 31, 2011,
and the three months ended September 30, 2011 the Company recognized as revenues $3,025 and $2,294,
respectively, of fees that had been previously deferred. As of September 30, 2011, there were no
deferred revenues related to this contractual arrangement.
Certain of the forward capacity programs in which the Company participates may be deemed
derivative contracts under ASC 815, Derivatives and Hedging (ASC 815). 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 and, accordingly, the arrangement is not treated as a derivative
contract.
Energy event revenues are recognized when earned. Energy event revenue is deemed to be
substantive and represents the culmination of a separate earnings process and is recognized when
the energy event is initiated by the electric power grid operator or utility customer and the
Company has responded under the terms of the contract or open market program.
Under certain of the Company’s arrangements, in particular those arrangements entered into by
the Company’s wholly-owned subsidiary, M2M, the Company sells proprietary equipment to C&I
customers that is utilized to provide the ongoing services that the Company delivers. Currently,
this equipment has been determined to not have stand-alone value. As a result, the Company defers
the fees associated with the equipment and the Company begins recognizing those fees ratably over
the expected C&I customer relationship period (generally 3 years), once the C&I customer is
receiving the ongoing services from the Company. In addition, the Company capitalizes the
associated direct and incremental costs, which primarily represent the equipment and third-party
installation costs, and recognizes such costs over the expected C&I customer relationship period.
In September 2009, the Financial Accounting Standards Board (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 ASC Subtopic
605-25, which is the revenue recognition guidance for multiple-element arrangements. ASU 2009-13
provides for three significant changes to the existing multiple-element revenue recognition
guidance as follows:
As required, the Company adopted ASU 2009-13 at the beginning of its first quarter of the
fiscal year ending December 31, 2011 (fiscal 2011) on a prospective basis for transactions
originating or materially modified on or after January 1, 2011. ASU 2009-13 generally does not
change the units of accounting for the Company’s revenue transactions. The impact of adopting ASU
2009-13 was not material to the Company’s financial statements during the nine months ended
September 30, 2011, and if it was applied in the same manner to the fiscal year ending December 31,
2010 (fiscal 2010) would not have had a material impact to revenue for the nine months ended
September 30, 2010. The Company does not expect the adoption of ASU 2009-13 to have a significant
impact on the timing and pattern of revenue recognition in the future due to the Company’s limited
number of multiple element arrangements. The key impact that the Company expects the adoption of
ASU 2009-13 to have relates to certain EfficiencySMART service arrangements with C&I customers who
also provide curtailment of capacity as part of the Company’s demand response arrangements.
Historically, the Company recorded the fees recognized under these arrangements as a reduction of
cost of revenues as evidence of fair value did not exist for certain EfficiencySMARTservices due to
the limited history of selling these separately and lack of availability of TPE. As previously
stated, the impact of ASU 2009-13 has not been and is not expected to be material.
The Company typically determines the selling price of its services based on VSOE. Consistent
with its methodology under previous accounting guidance, the Company determines VSOE based on its
normal pricing and discounting practices for the specific service when sold on a stand-alone basis.
In determining VSOE, the Company’s policy is to require a substantial majority of selling
9
Table of Contents
prices for a product or service to be within a reasonably narrow range. The Company also
considers the class of customer, method of distribution, and the geographies into which its
products and services are sold into when determining VSOE. The Company typically has had VSOE for
its products and services.
In certain circumstances, the Company is not able to establish VSOE for all deliverables in a
multiple element arrangement. This may be due to the infrequent occurrence of stand-alone sales for
an element, a limited sales history for new services or pricing within a broader range than
permissible by the Company’s policy to establish VSOE. In those circumstances, the Company proceeds
to the alternative levels in the hierarchy of determining selling price. TPE of selling price is
established by evaluating largely similar and interchangeable competitor products or services in
stand-alone sales to similarly situated customers. The Company is typically not able to determine
TPE and has not used this measure since the Company has been unable to reliably verify standalone
prices of competitive solutions. ESP is established in those instances where neither VSOE nor TPE
are available, considering internal factors such as margin objectives, pricing practices and
controls, customer segment pricing strategies and the product life cycle. Consideration is also
given to market conditions such as competitor pricing information gathered from experience in
customer negotiations, market research and information, recent technological trends, competitive
landscape and geographies. Use of ESP is limited to a very small portion of the Company’s services,
principally certain EfficiencySMART services.
Foreign Currency Translation
The financial statements of the Company’s international subsidiaries are translated in
accordance with ASC 830, Foreign Currency Matters (formerly SFAS No. 52, Foreign Currency
Translation) (ASC 830), into the Company’s reporting currency, which is the United States dollar.
The functional currencies of the Company’s subsidiaries in Canada, the United Kingdom, Australia
and New Zealand are the Canadian dollar, the British pound, the Australian dollar and the New
Zealand dollar, 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 certain inter-company accounts receivable and payable that have been determined to not be
of a “long-term investment” nature, as defined by ASC 830, into the functional currency of the
respective entity, resulting in unrealized gains or losses recorded in the consolidated statement
of income. 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
income and included in accumulated other comprehensive loss within stockholders’ equity. Losses
arising from transactions denominated in foreign currencies and the remeasurement of certain
intercompany receivables and payables are included in other (expense) income, net in the unaudited condensed
consolidated statements of income and were $2,648 and $2,848 for the three and nine months
ended September 30, 2011, respectively. Gains arising from transactions denominated in foreign
currencies were $13 for the three months ended September 30, 2010. Losses arising from
transactions denominated in foreign currencies were $17 for the nine months ended September 30,
2010, respectively. The significant increase in losses arising from transactions denominated in
foreign currencies for the three and nine months ended September 30, 2011 as compared to the
comparable periods of 2010 is due to the significant increase of foreign denominated intercompany
receivables held by the Company from one of its Australian subsidiaries primarily as a result of
the funding provided to complete the acquisition of Energy Response (see Note 2) and the
strengthening of the United States dollar as compared to the Australian dollar during the three
months ended September 30, 2011. During the three and nine months ended September 30, 2011 and
2010, there were no material realized gains or losses incurred related to transactions denominated in
foreign currencies. As of September 30, 2011, the Company had an intercompany receivable from its
Australian subsidiary that is denominated in Australia dollars and not deemed to be of a “long-term
investment” nature totaling $31,965 ($32,640 Australian).
In addition, a portion of the funding provided by the Company to one of its Australian
subsidiaries to complete the acquisition of Energy Response (see Note 2) was deemed to be of a
“long-term investment nature” and therefore, the resulting translation adjustments are being
recorded as a component of stockholders’ equity within accumulated other comprehensive loss. As of
September 30, 2011, the intercompany funding that is denominated in Australia dollars and deemed
to be of a “long-term investment” nature totaled $21,671 ($20,364 Australian).
Comprehensive Income
Comprehensive income is defined as the change in equity of a business enterprise during a
period resulting from transactions and other events and circumstances from non-owner sources.
Comprehensive income is composed of net income and foreign currency translation adjustments. As of
September 30, 2011 and 2010, accumulated other comprehensive 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.
10
Table of Contents
Comprehensive income for the three and nine months ended September 30, 2011 and 2010 was as follows:
Software Development Costs
The Company applies the provisions of ASC 350-40, Internal-Use Software (ASC 350-40). 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 and third-party consultants 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 five years. The Company’s
judgment is required in determining the point at which various projects enter the stages at which
costs may be capitalized, in assessing the ongoing value and impairment of the capitalized costs,
and in determining the estimated useful lives over which the costs are amortized.
Software development costs of $805 and $1,045 for the three months ended September 30, 2011
and 2010, respectively, and $2,944 and $5,063 for the nine months ended September 30, 2011 and
2010, respectively, have been capitalized in accordance with ASC 350-40. The capitalized amount was
included as software in property and equipment at September 30, 2011 and December 31, 2010. The
Company capitalized $0 and $248 during the three months ended September 30, 2011 and 2010,
respectively, and $13 and $1,216 for the nine months ended September 30, 2011 and 2010,
respectively, related to a company-wide enterprise resource planning systems implementation
project, which was put into production in June 2011 and is being amortized over a five year useful
life. Amortization of capitalized internal use software costs was $1,160 and $749 for the three
months ended September 30, 2011 and 2010, respectively, and $3,028 and $2,123 for the nine months
ended September 30, 2011 and 2010, respectively. Accumulated amortization of capitalized internal
use software costs was $10,162 and $7,134 as of September 30, 2011 and December 31, 2010,
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 September 30, 2011, the Company identified an impairment
indicator related to certain demand response equipment as a result of the removal of such equipment
from service during the three months ended September 30, 2011. As a result of this impairment
indicator, the Company performed an impairment test during the three months ended September 30,
2011 and recognized an impairment charge of $168 during the three months ended September 30, 2011,
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 unaudited condensed
consolidated statements of income. The fair market value was determined utilizing Level 3
inputs, as defined by ASC 820, Fair Value Measurements and Disclosures (ASC 820), based on the
projected future cash flows discounted using the estimated market participant rate of return for
this type of asset.
As of September 30, 2011, there were no impairment indicators noted with respect to the
Company’s generation equipment that required an impairment test. As of September 30, 2011
approximately $1,726 of the Company’s generation equipment is utilized in open market programs. The
recoverability of the carrying value of this generation equipment 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.
11
Table of Contents
During the three months ended June 30, 2011, 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
June 30, 2011. 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 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 $57
compared to the carrying value of the asset group of $83, and as a result recorded an impairment
charge of $26 during the three months ended June 30, 2011, which is reflected in cost of revenues
in the accompanying unaudited condensed consolidated statements of income. 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 June 30, 2011, the Company identified an impairment indicator
related to certain demand response equipment as a result of the removal of such equipment from
service during the three months ended June 30, 2011. As a result of this impairment indicator, the
Company performed an impairment test during the three months ended June 30, 2011 and recognized an
impairment charge of $204 during the three months ended June 30, 2011, 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 unaudited condensed consolidated statements of
income. 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 March 31, 2011, the Company identified an impairment indicator
related to certain demand response equipment as a result of the removal of such equipment from
service during the three months ended March 31, 2011. As a result of this impairment indicator, the
Company performed an impairment test during the three months ended March 31, 2011 and recognized an
impairment charge of $110 during the three months ended March 31, 2011, 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 unaudited condensed consolidated statements of
income. 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.
Inventories
Inventories are valued at the lower of cost or market on a first in, first out basis.
Work-in-process and finished goods inventories consist of materials, labor and manufacturing
overhead. The valuation of inventory requires management to estimate excess and obsolete inventory.
The Company employs a variety of methodologies to determine the net realizable value of its
inventory. Provisions for excess and obsolete inventory are primarily based on management’s
estimates of forecasted net sales and service usage levels. A significant change in the timing or
level of demand for the Company’s products as compared to forecasted amounts may result in
recording additional provisions for excess and obsolete inventory in the future. The Company
records provisions for excess and obsolete inventory as cost of product sales. As of September 30,
2011, the Company had $323 of inventory, which primarily consisted of raw materials related to M2M.
Industry Segment Information
The Company is required to disclose the standards for reporting information about its
operating segments in annual financial statements and required selected information of these
segments being presented in interim financial reports issued to stockholders. Operating segments
are defined as components of an enterprise about which separate financial information is available
that is evaluated regularly by the chief operating decision maker, or decision making group, in
making decisions on how to allocate resources and assess performance. The Company’s chief decision
maker is considered to be the team comprised of the chief executive officer and the executive
management team. The Company views its operations and manages its business as one operating
segment.
The Company operates in several geographic areas, primarily the United States, Canada, United
Kingdom, Australia and New Zealand. Revenues derived from United States operations comprise the
majority of consolidated revenues. International subsidiaries comprised less than 10% of consolidated revenues
for the three and nine months ended September 30, 2011 and are not expected to exceed 10% of
consolidated revenues for fiscal 2011.
12
Table of Contents
As of September 30, 2011 and December 31, 2010, the long-lived assets related to the Company’s
international subsidiaries were not material to the accompanying unaudited condensed consolidated
financial statements taken as a whole.
2. Acquisitions
Energy Response Holdings Pty Ltd
In July 2011, the Company and one of its subsidiaries acquired all of the outstanding stock of
Energy Response, a privately-held company headquartered in Australia and specializing in demand
response and other energy management services in Australia and New Zealand, pursuant to a
definitive agreement dated July 1, 2011. The Company concluded that this acquisition represents a
business combination and therefore, has accounted for it as such. The Company believes that Energy
Response will enhance and broaden the Company’s service offerings in Australia and New Zealand.
The Company concluded that the acquisition of Energy Response represented a material business
combination under the provisions of ASC 805, Business Combinations (ASC 805), and therefore, pro
forma financial information has been provided herein. Subsequent to the acquisition date, the
Company’s results of operations include the results of operations of Energy Response.
The Company acquired Energy Response for an aggregate purchase price, exclusive of potential
contingent consideration, of $29,286, plus an additional $470 paid as working capital and other
adjustments, consisting of $27,265 in cash paid at closing and $2,491 representing the fair value
of the 156,697 shares of Company common stock issued as of the acquisition date. Of the
consideration paid at closing, $2,646 was paid as consideration to settle Energy Response’s
outstanding debt obligations. In addition to the amounts paid at closing, the Company may be
obligated to pay additional contingent purchase price consideration related to an earn-out payment
equal to $10,718 ($10,000 Australian). The earn-out payment, if any, will be based on the development of a demand
response reserve capacity market in the National Electricity Market in Australia by December 31,
2013 that meets certain market size and price per megawatt conditions. This milestone needs to be
achieved in order for the earn-out payment to occur and there will be no partial payment if the
milestone is not fully achieved. The Company determined that the initial fair value of the
earn-out payment as of the acquisition date was $309. This fair value was included as a component
of the purchase price resulting in an aggregate purchase price of $30,065. Any changes in fair
value will be recorded in the Company’s consolidated statements of income. The Company
recorded its estimate of the fair value of the contingent consideration based on the evaluation of
the likelihood of the achievement of the contractual conditions that would result in the payment of
the contingent consideration and weighted probability assumptions of these outcomes. This fair
value measurement was based on significant inputs not observable in the market and therefore,
represented a Level 3 measurement as defined in ASC 820. As of September 30, 2011, there were no
changes in the probability of the earn out payment. This liability has been discounted to reflect
the time value of money and therefore, as the milestone date approaches, the fair value of this
liability will increase. This increase in fair value was recorded in general and administrative
expenses in the Company’s accompanying unaudited condensed consolidated statements of income.
During the three and nine months ended September 30, 2011, the Company recorded a charge of $23.
At September 30, 2011, the liability was recorded at $303 after adjusting for changes in exchange
rates. The difference between the $29,286 aggregate purchase price and the $29,475 aggregate
purchase price set forth in the definitive agreement was due to the fair value of the stock issued
in connection with the acquisition, which was based on the Company’s stock price as of the closing
date of the acquisition of $15.90 per share, as reported on the NASDAQ Global Market (NASDAQ), as
compared to a per share value of $17.10 determined in accordance with the definitive agreement,
which was based on the average of the per share last sale price as reported on NASDAQ for the
Company’s common stock for the thirty day period ending two trading days prior to closing.
Transaction costs related to this business combination have been expensed as incurred, which
are included in general and administrative expenses in the Company’s unaudited condensed
consolidated statements of income. Transaction costs incurred related to this transaction were
approximately $500.
The components and preliminary allocation of the purchase
price consist of the following approximate amounts:
13
Table of Contents
Net tangible assets acquired in the acquisition of Energy Response primarily related
to the following:
Restricted cash acquired primarily relates to certain security deposits posted by Energy
Response to collateralize its performance obligations under certain contractual arrangements with
electric power grid operator customers. In accordance with the definitive agreement, the Company
is required to distribute to the former stockholders of Energy Response $2,051 of this restricted
cash upon the amount being released by the applicable electric power grid operator customers.
This amount has been classified as an amount due to the former stockholders in the reconciliation
of net tangible assets acquired above. This amount was released by the electric power grid
operator customers during the three months ended September 30, 2011 and the Company distributed
this amount to the former stockholders during the three months ended September 30, 2011. The
remaining restricted cash relates to amounts used to collateralize Energy Response’s obligations
under certain of its facility operating lease arrangements. The acquired forward energy contracts
represent derivative instruments. ASC Topic 815 requires all derivative instruments to be
recognized at their fair values as either assets or liabilities on the balance sheet. The Company
determined the fair value of these derivative instruments using the framework prescribed by ASC
820, by considering the estimated amount that would be received or paid to sell or transfer these
instruments at the reporting date and by taking into account current interest rates, current energy
rates, and the creditworthiness of the applicable counterparty. These acquired forward energy
contracts were short-term arrangements which either expired or were terminated prior to September
30, 2011.The Company has not entered into any additional forward energy contracts since the
acquisition date and therefore, the Company held no derivative instruments as of September 30,
2011. From the date of acquisition through the date of expiration or termination, the change in
fair value of these forward energy contracts was not material and was included in other expense
(income), net in the accompanying unaudited condensed consolidated statements of income.
Identifiable Intangible Assets
As part of the preliminary purchase price allocation, the Company determined that Energy
Response’s separately identifiable intangible assets were its customer relationships, non-compete
agreements, developed technology and trade name. Developed technology represented certain
proprietary software tools that Energy Response had developed, which are utilized to assist in the
management of certain contractual arrangements. As of the date of acquisition, the Company
determined that there was no in-process research and development as the ongoing research and
development efforts were nominal and related to routine, on-going maintenance efforts.
The Company used the income approach to value the customer relationships, non-compete
agreements, developed technology and trade name. This approach calculates fair value by discounting
the after-tax cash flows back to a present value. The baseline data for this analysis was the cash
flow estimates used to price the transaction. Cash flows were forecasted for each intangible asset
then discounted based on an appropriate discount rate. The discount rates applied, which ranged
between 12% and 17%, were benchmarked with reference to the implied rate of return from the
transaction model, as well as an estimate of a market-participant’s weighted average cost of
capital based on the capital asset pricing model.
14
Table of Contents
In estimating the useful life of the acquired assets, the Company considered ASC 350-30-35,
General Intangibles Other Than Goodwill (ASC 350-30-35), which lists the pertinent factors to be
considered when estimating the useful life of an intangible asset. These factors include a review
of the expected use by the combined company of the assets acquired, the expected useful life of
another asset (or group of assets) related to the acquired assets, legal, regulatory or other
contractual provisions that may limit the useful life of an acquired asset or may enable the
extension of the useful life of an acquired asset without substantial cost, the effects of
obsolescence, demand, competition and other economic factors, and the level of maintenance
expenditures required to obtain the expected future cash flows from the asset. The Company
amortizes these intangible assets over their estimated useful lives using a method that is based on
estimated future cash flows, as the Company believes this will approximate the pattern in which the
economic benefits of the assets will be utilized, or where the Company has concluded that the cash
flows were not reliably determinable, on a straight-line basis.
Subsequent to the acquisition, the Company discontinued the use of the trade name intangible
asset and recorded an impairment charge of $199. This amount is included in selling and marketing
expense in the accompanying unaudited condensed consolidated statements of income during the
three months ended September 30, 2011.
The factors contributing to the recognition of this amount of goodwill were based upon the
Company’s determination that several strategic and synergistic benefits are expected to be realized
from the combination. None of the goodwill is expected to be currently deductible for tax purposes.
As noted above, the Company’s consolidated results of operations for the three and nine months ended
September 30, 2011 include the results of operations for Energy Response from the date of
acquisition through September 30, 2011, which included net revenues of $2,596 and net loss of
$1,637.
The following unaudited pro forma financial information presents the consolidated results of
operations of the Company and Energy Response as if the acquisition had occurred at the beginning
of fiscal 2010 with pro forma adjustments to give effect to amortization of intangible assets, a
decrease in interest expense as all of Energy Response’s debt arrangement were settled in
connection with the acquisition, an increase in weighted average number of common shares
outstanding based on the shares issued in connection with the acquisition and certain other
adjustments:
The direct acquisition fees and expenses of approximately $500 that were a direct result of
the transaction are excluded from the unaudited pro forma information above for the nine months
ended September 30, 2011. The unaudited pro forma financial information for the nine months ended
September 30, 2010 was adjusted to include these charges. The unaudited pro forma results are not
necessarily indicative of the results that the Company would have attained had the acquisitions of
Energy Response occurred on January 1, 2010.
Global Energy Partners, Inc.
In January 2011, the Company acquired all of the outstanding stock of Global Energy, a
privately-held company located in California and specializing in the design and implementation of
utility energy efficiency and demand response programs. The Company believes that Global Energy’s
service offerings will enhance and broaden its portfolio of service offerings in the area of energy
efficiency and demand response.
The Company concluded that the acquisition of Global Energy did not represent a material
business combination and therefore, no pro forma financial information has been provided herein.
Subsequent to the acquisition date, the Company’s results of operations include the results of
operations of Global Energy. The Company accounted for the acquisition of Global Energy as a
purchase of a business under ASC 805.
15
Table of Contents
The total purchase price paid by the Company at closing was approximately $26,658, consisting
of $19,875 in cash and the remainder of which was paid by the issuance of 275,181 shares of the
Company’s common stock that had a fair value of approximately $6,783. The fair value of these
shares was measured as of the acquisition date using the closing price of the Company’s common
stock, as reported on NASDAQ on January 3, 2011. This acquisition had no contingent consideration
or earn-out payments.
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
unaudited condensed consolidated statements of income.
During the three months ended September 30, 2011, based on additional information gathered
related to the fair value of certain acquired assets and liabilities, the Company recorded
adjustments to the allocation of the purchase price, resulting in an increase of net tangible
assets acquired of $104 and a corresponding decrease to goodwill.
During the three months ended June 30, 2011, based on additional information gathered related
to the fair value of certain acquired assets and liabilities, the Company recorded adjustments to
the allocation of the purchase price, resulting in an increase of net tangible assets acquired of
$120 and a corresponding increase to goodwill.
The components and preliminary allocation of the purchase
price consist of the following approximate amounts:
Net tangible assets acquired in the acquisition of Global Energy primarily related
to the following:
Identifiable Intangible Assets
As part of the preliminary purchase price allocation, the Company determined that Global
Energy’s separately identifiable intangible assets were its customer relationships, non-compete
agreements, developed technology and trade name. Developed technology represented certain
proprietary software tools that Global Energy had developed, which are utilized on certain
consulting projects. As of the date of acquisition, the Company determined that there was no
in-process research and development as the ongoing research and development efforts were nominal
and related to routine, on-going maintenance efforts.
The Company used the income approach to value the customer relationships, non-compete
agreements, developed technology and trade name. This approach calculates fair value by discounting
the after-tax cash flows back to a present value. The baseline data for this analysis was the cash
flow estimates used to price the transaction. Cash flows were forecasted for each intangible asset
then discounted based on an appropriate discount rate. The discount rates applied, which ranged
between 10% and 16%, were benchmarked with reference to the implied rate of return from the
transaction model as well as an estimate of a market-participant’s weighted average cost of capital
based on the capital asset pricing model.
In estimating the useful life of the acquired assets, the Company considered ASC 350-30-35,
which lists the pertinent factors to be considered when estimating the useful life of an intangible
asset. These factors include a review of the expected use by the combined company of the assets
acquired, the expected useful life of another asset (or group of assets) related to the acquired
assets,
16
Table of Contents
legal, regulatory or other contractual provisions that may limit the useful life of an
acquired asset or may enable the extension of the useful life of an acquired asset without
substantial cost, the effects of obsolescence, demand, competition and other economic factors, and
the level of maintenance expenditures required to obtain the expected future cash flows from the
asset. The Company amortizes these intangible assets over their estimated useful lives using a
method that is based on estimated future cash flows, as the Company believes this will approximate
the pattern in which the economic benefits of the assets will be utilized, or where the Company has
concluded that the cash flows were not reliably determinable, on a straight-line basis. The
acquisition of Global Energy was deemed to be an asset purchase for income tax purposes.
Accordingly, no deferred taxes were established relating to the fair value of the acquired
intangible assets.
The factors contributing to the recognition of this amount of goodwill were based upon several
strategic and synergistic benefits that are expected to be realized from the combination.
Substantially all of the goodwill is expected to be deductible for tax purposes.
M2M Communications Corporation
On January 21, 2011, the Company entered into a definitive agreement to acquire M2M, a
privately-held company located in Idaho and specializing in wireless technology solutions for
energy management and demand response. The acquisition closed on January 25, 2011. By integrating
M2M’s wireless technology solutions with the Company’s energy management applications and services,
the Company believes that it will be able to enhance its automated demand response offering and
deliver more value to its rapidly growing C&I customer base.
The Company concluded that the acquisition of M2M did not represent a material business
combination and therefore, no pro forma financial information has been provided herein. Subsequent
to the acquisition date, the Company’s results of operations include the results of operations of
M2M. The Company accounted for the acquisition of M2M as a purchase of a business under ASC 805.
The total initial purchase price paid by the Company at closing was approximately $29,871,
consisting of $17,597 in cash, $3,925 representing the estimated fair value of $7,000 of deferred
purchase price consideration determined at closing, and the remainder of which was paid by the
issuance of 351,665 shares of the Company’s common stock that had a fair value of approximately
$8,349. The fair value of these shares was measured as of the acquisition date using the closing
price of the Company’s common stock, as reported on NASDAQ on January 25, 2011. 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 of
January 25, 2011. The deferred purchase price consideration is not subject to adjustment or
forfeiture. The Company recorded its estimate of the fair value of the deferred purchase price
consideration based on the evaluation of the likelihood of the achievement of the contractual
conditions that would result in the payment of the deferred purchase price consideration prior to
seven years from the acquisition date and weighted probability assumptions of these outcomes. This
fair value measurement was based on significant inputs not observable in the market and therefore,
represented a Level 3 measurement as defined in ASC 820. As of September 30, 2011, there were no
significant changes in the estimated timing of payment of the deferred purchase price
consideration. This liability has been discounted to reflect the time value of money and therefore,
as the milestone date approaches, the fair value of this liability will increase. This increase in
fair value was recorded as an expense in the Company’s accompanying unaudited condensed
consolidated statements of income with a portion of the charge being recorded to cost of
revenues related to the component of the deferred purchase price consideration related to the
achievement of certain gross profit metrics and the remaining portion of the charge being recorded
to general and administrative expenses. During the three and nine months ended September 30, 2011,
the Company recorded a charge of $109 and $293, respectively. Of the $109 recorded for the three
months ended September 30, 2011, $52 was recorded to cost of revenues and $57 was recorded to
general and administrative expenses. Of the $293 recorded for the nine months ended September 30,
2011, $139 was recorded to cost of revenues and $154 was recorded to general and administrative
expenses. At September 30, 2011, the liability was recorded at $4,218. This acquisition had no
contingent consideration or earn-out payments.
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
unaudited condensed consolidated statements of income.
The allocation of the purchase price is based upon preliminary estimates of the fair value of
assets acquired and liabilities assumed as of January 25, 2011. The Company is in the process of
gathering information to finalize its valuation of certain assets and liabilities. The purchase
price allocation is preliminary and will be finalized once the Company has all necessary
information to complete its estimate, but generally no later than one year from the date of
acquisition.
During the three months ended September 30, 2011, based on additional information gathered
related to the fair value of certain acquired assets and liabilities, the Company recorded
adjustments to the allocation of the purchase price, resulting in an increase of net tangible
assets acquired of $192 and a corresponding decrease to goodwill.
17
Table of Contents
During the three months ended June 30, 2011, as a result of gathering information to update
the Company’s valuation allocation, the Company asserted that the estimated merger consideration
paid at the closing exceeded the final merger consideration. The Company and the former
stockholders of M2M reached a settlement agreement to reduce the purchase price by $1,250, which
was recorded in prepaid expenses, deposits and other current assets in the Company’s unaudited
condensed consolidated balance sheets as of June 30, 2011 included in the Company’s Quarterly
Report on Form 10-Q for the period ended June 30, 2011. This reduction in purchase price reduced
the fair value of the customer relationships and non-compete agreements intangible assets acquired
by $100 and $10, respectively. The additional $1,140 reduction in purchase price was recorded as a
reduction of goodwill. The Company received 45,473 shares of common stock, which was based on the
fair value used to determine the stock consideration issued in connection with the acquisition of
$23.74 per share and represents a fair value of $1,125, and cash of $125 from escrow during the
three months ended September 30, 2011.
The components and preliminary allocation of the purchase
price consist of the following approximate amounts:
Net tangible assets acquired in the acquisition
of M2M primarily related to the following:
In connection with the acquisition of M2M, the Company acquired M2M’s outstanding borrowing
under M2M’s line of credit arrangement with a financial institution. At closing, the Company fully
repaid these borrowings and M2M’s line of credit arrangement was terminated.
Identifiable Intangible Assets
As part of the preliminary purchase price allocation, the Company determined that M2M’s
separately identifiable intangible assets were its customer relationships, non-compete agreements,
developed technology and trade name. Developed technology represented the products and related
software that M2M had developed for its wireless technology applications. As of the date of the
acquisition, the Company determined that there was no in-process research and development as the
ongoing research and development efforts related solely to routine, on-going efforts to refine,
enrich, or otherwise improve the qualities of the existing product, and the adaptation of existing
capability to a particular requirement or customer’s need as part of a contractual arrangement
(i.e. configuring equipment for specific customer requirements), which do not meet the criteria of
in-process research and development.
The Company used the income approach to value the customer relationships, non-compete
agreements, developed technology and trade name. This approach calculates fair value by discounting
the after-tax cash flows back to a present value. The baseline data for this analysis was the cash
flow estimates used to price the transaction. Cash flows were forecasted for each intangible asset
then discounted based on an appropriate discount rate. The discount rates applied, which ranged
between 10% and 18%, were benchmarked with reference to the implied rate of return from the
transaction model, as well as an estimate of a market-participant’s weighted average cost of
capital based on the capital asset pricing model.
18
Table of Contents
In estimating the useful life of the acquired assets, the Company considered ASC 350-30-35,
which lists the pertinent factors to be considered when estimating the useful life of an intangible
asset. These factors include a review of the expected use by the combined company of the assets
acquired, the expected useful life of another asset (or group of assets) related to the acquired
assets, legal, regulatory or other contractual provisions that may limit the useful life of an
acquired asset or may enable the extension of the useful life of an acquired asset without
substantial cost, the effects of obsolescence, demand, competition and other economic factors, and
the level of maintenance expenditures required to obtain the expected future cash flows from the
asset. The Company amortizes these intangible assets over their estimated useful lives using a
method that is based on estimated future cash flows, as the Company believes this will approximate
the pattern in which the economic benefits of the assets will be utilized, or where the Company has
concluded that the cash flows were not reliably determinable, on a straight-line basis. The
acquisition of M2M was deemed to be an asset purchase for income tax purposes. Accordingly, no
deferred taxes were established relating to the fair value of the acquired intangible assets.
The factors contributing to the recognition of this amount of goodwill were based upon the
Company’s determination that several strategic and synergistic benefits are expected to be realized
from the combination. Substantially all of the goodwill is expected to be deductible for tax
purposes.
Other Immaterial Acquisitions
In January 2011, the Company completed its acquisition of a privately-held company
specializing in demand response and other energy management services. The Company believes that
this acquisition will enhance and broaden the Company’s international service offerings.
The Company concluded that this acquisition did not represent a material business combination
and therefore, no pro forma financial information has been provided herein. Subsequent to the
acquisition date, the Company’s results of operations include the results of operations of the
acquired company. The Company accounted for this acquisition as a purchase of a business under ASC
805.
The total purchase price paid by the Company at closing was approximately $5,193, consisting
of $3,918 in cash at closing, $779 paid as consideration to settle the acquired company’s
outstanding debt obligations and $496 of cash consideration to be paid upon satisfaction of certain
general representations and warranties, which will be paid in one year or less and is included in
accrued expenses and other current liabilities in the accompanying unaudited condensed consolidated
balance sheets as of September 30, 2011. This acquisition had no contingent consideration or
earn-out payments. The Company did not issue any shares of its capital stock in connection with
this acquisition.
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
unaudited condensed consolidated statements of income.
The allocation of the purchase price is based upon preliminary estimates of the fair value of
assets acquired and liabilities assumed as of January 25, 2011. The Company is in the process of
gathering information to finalize its valuation of certain assets and liabilities. The purchase
price allocation is preliminary and will be finalized once the Company has all necessary
information to complete its estimate, but generally no later than one year from the date of
acquisition.
The components and preliminary allocation of the purchase price
consist of the following approximate amounts:
Net tangible liabilities assumed in this acquisition primarily related to the following:
19
Table of Contents
Identifiable Intangible Assets
As part of the preliminary purchase price allocation, the Company determined that the acquired
company’s separately identifiable intangible assets were its customer relationships, non-compete
agreements and trade name. The acquired company had no developed technology nor were there any
ongoing research and development efforts as of the date of acquisition.
The Company used the income approach to value the customer relationships, non-compete
agreements and trade name. This approach calculates fair value by discounting the after-tax cash
flows back to a present value. The baseline data for this analysis was the cash flow estimates used
to price the transaction. Cash flows were forecasted for each intangible asset then discounted
based on an appropriate discount rate. The discount rates applied, which ranged between 16% and
28%, were benchmarked with reference to the implied rate of return from the transaction model, as
well as an estimate of a market-participant’s weighted average cost of capital based on the capital
asset pricing model.
In estimating the useful life of the acquired assets, the Company considered ASC 350-30-35,
which lists the pertinent factors to be considered when estimating the useful life of an intangible
asset. These factors include a review of the expected use by the combined company of the assets
acquired, the expected useful life of another asset (or group of assets) related to the acquired
assets, legal, regulatory or other contractual provisions that may limit the useful life of an
acquired asset or may enable the extension of the useful life of an acquired asset without
substantial cost, the effects of obsolescence, demand, competition and other economic factors, and
the level of maintenance expenditures required to obtain the expected future cash flows from the
asset. The Company amortizes these intangible assets over their estimated useful lives using a
method that is based on estimated future cash flows, as the Company believes this will approximate
the pattern in which the economic benefits of the assets will be utilized, or where the Company
concluded that the cash flows were not reliably determinable, on a straight-line basis.
The factors contributing to the recognition of this amount of goodwill were based upon the
Company’s determination that several strategic and synergistic benefits were expected to be
realized from the combination. None of the goodwill is expected to be expected to be currently
deductible for tax purposes.
3. Impairment of Intangible Assets and Goodwill
Definite-Lived Intangible Assets
The Company amortizes its intangible assets that have finite lives using either the
straight-line method or, if reliably determinable, based on the pattern in which the economic
benefit of the asset is expected to be consumed utilizing expected undiscounted future cash flows.
Amortization is recorded over the estimated useful lives ranging from one to ten years. The Company
reviews its intangible assets subject to amortization to determine if any adverse conditions exist
or a change in circumstances has occurred that would indicate impairment or a change in the
remaining useful life. If the carrying value of an asset exceeds its undiscounted cash flows, the
Company will write-down the carrying value of the intangible asset to its fair value in the period
identified. In assessing recoverability, the Company must make assumptions regarding estimated
future cash flows and discount rates. If these estimates or related assumptions change in the
future, the Company may be required to record impairment charges. The Company generally calculates
fair value as the present value of estimated future cash flows to be generated by the asset using a
risk-adjusted discount rate. If the estimate of an intangible asset’s remaining useful life
changes, the Company will amortize the remaining carrying value of the intangible asset
prospectively over the revised remaining useful life. During the three months ended September 30,
2011, as a result of a discontinuation of certain tradenames acquired in connection with the
acquisition of Energy Response and another immaterial acquisition that occurred in January 2011,
the Company determined that these definite-lived intangible assets were impaired and recorded an
impairment charge of $241 during the three months ended September 30, 2011 to reduce the carrying
value of these assets to zero, which was included in selling and marketing expense in the
accompanying unaudited condensed consolidated statements of income.
20
Table of Contents
The following table provides the gross carrying amount and related accumulated amortization of intangible assets as of
September 30, 2011 and December 31, 2010:
The increase in intangibles assets from December 31, 2010 to September 30, 2011 was due to the
allocation of purchase price related to the acquisitions made by the Company during the nine months
ended September 30, 2011. Amortization expense related to intangible assets amounted to $2,008 and
$353 for the three months ended September 30, 2011 and 2010, respectively, and $4,533 and $1,109
for nine months ended September 30, 2011 and 2010, respectively. Amortization expense for developed
technology, which was $247 for the three months ended September 30, 2011 and $577 for the nine
months ended September 30, 2011, is included in cost of revenues in the accompanying unaudited
condensed consolidated statements of income. Amortization expense for all other intangible
assets is included as a component of operating expenses in the accompanying unaudited condensed
consolidated statements of income. The intangible asset lives range from one to ten years and
the weighted average remaining life was 4.99 years at September 30, 2011. Estimated amortization is
$2,139, $7,950, $7,867, $7,223, $4,911 and $7,035 for 2011, 2012, 2013, 2014, 2015 and thereafter,
respectively.
Indefinite-Lived Intangible Assets
In connection with the Company’s acquisition of SmallFoot LLC (Smallfoot) and ZOX, LLC (Zox),
the Company acquired certain in-process research and development projects with a fair value of $390
and $530, respectively. During the three months ended June 30, 2011, the Company concluded that
the Smallfoot in-process research and development project had reached technological feasibility.
Prior to re-classifying the asset as a definite-lived intangible asset, the Company performed an
impairment test utilizing 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. Therefore, the Company re-classified the fair value of $390 relating to the
Smallfoot in-process research and development projects to a definite-lived intangible asset at June
30, 2011 with a useful life of three years. The amount of amortization expense recorded in the
three and nine months ended September 30, 2011 was immaterial.
The Zox in-process research and development project has not reached technological feasibility
and remained an indefinite-lived intangible asset at September 30, 2011. There were no interim
impairment indicators that had been identified for Zox as of September 30, 2011.
Goodwill
The following table shows the change of the carrying amount of goodwill from
December 31, 2010 to September 30, 2011:
21
Table of Contents
4. Net Income Per Share
A reconciliation of basic and diluted share amounts for the three and nine months ended
September 30, 2011 and 2010 are as
follows (shares in thousands):
In reporting periods in which the Company reports net income, anti-dilutive shares
comprise those common stock equivalents that have either an exercise price above the average stock
price for the quarter or the common stock equivalent’s related average unrecognized stock
compensation expense is sufficient to “buy back” the entire amount of shares. In those reporting
periods in which the Company has a net loss, anti-dilutive shares comprise the impact of those
number of shares that would have been dilutive had the Company had net income plus the number of
common stock equivalents that would be anti-dilutive had the Company had net income.
The Company excludes the shares issued in connection with restricted stock awards from the
calculation of basic weighted average common shares outstanding until such time as those shares
vest. In addition, in connection with certain of the Company’s business combinations, the Company
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.
5. Disclosure of Fair Value of Financial Instruments
The Company’s financial instruments mainly consist of cash and cash equivalents, restricted
cash, accounts receivable, accounts payable and debt obligations. The carrying amounts of the
Company’s cash equivalents, restricted cash, accounts receivable and accounts payable approximate
their fair value due to the short-term nature of these instruments. At September 30, 2011, the
Company had no borrowings and outstanding letters of credit totalling $42,314 under the $75,000
senior secured revolving credit facility pursuant to the credit agreement entered into in April
2011 (2011 credit facility) with Silicon Valley Bank (SVB). At December 31, 2010, the Company had
no borrowings and outstanding letters of credit totalling $36,561 under the previous credit
facility pursuant to the loan and security agreement entered into with SVB in August 2008 (2008
credit facility). For additional information regarding the 2011 credit facility, see Note 7.
6. 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:
22
Table of Contents
The table below presents the balances of assets and liabilities measured at fair value on a
recurring basis at September 30, 2011:
With respect to assets measured at fair value on a non-recurring basis, which would be
impaired long-lived assets, refer to Note 1 and Note 3 for discussion of the determination of fair
value of these assets.
At September 30, 2011, the Company had restricted cash of approximately $93 collateralizing
certain other commitments. All certificates of deposit have contractual maturities of twelve months
or less. The Company’s investments in certificates of deposit have a fair value that approximates
cost.
7. Financing Arrangements
In April 2011, the Company and one of its subsidiaries entered into the 2011 credit facility.
Subject to continued covenant compliance, the 2011 credit facility provides for a two-year
revolving line of credit in the aggregate amount of $75,000, the full amount of which may be
available for issuances of letters of credit and up to $5,000 of which may be available for swing
line loans. The revolving line of credit is subject to increase from time to time up to an
aggregate amount of $100,000 with additional commitments from the lenders or new commitments from
financial institutions acceptable to SVB. The interest on revolving loans under the 2011 credit
facility will accrue, at the Company’s election, at either (i) the Eurodollar Rate with respect to
the relevant interest period plus 2.00% or (ii) the ABR (defined as the highest of (x) the “prime
rate” as quoted in the Wall Street Journal, (y) the Federal Funds Effective Rate plus 0.50% and (z)
the Eurodollar Rate for a one-month interest period plus 1.00%) plus 1.00%. In connection with the
issuance or renewal of letters of credit for the Company’s account, the Company is charged a letter
of credit fee of 2.125% pursuant to the 2011 credit facility. The Company expenses the interest and
letter of credit fees, as applicable, in the period incurred. The 2011 credit facility terminates
and all amounts outstanding are due and payable in full on April 15, 2013.
The 2011 credit facility contains customary terms and conditions for credit facilities of this
type, including restrictions on the ability of the Company and its subsidiaries to incur additional
indebtedness, create liens, enter into transactions with affiliates, transfer assets, pay dividends
or make distributions on, or repurchase, the Company’s common stock, consolidate or merge with
other entities, or suffer a change in control. In addition, the Company is required to meet certain
monthly and quarterly financial covenants customary with this type of credit facility. The
Company’s monthly financial covenants include a minimum specified ratio of current assets to
current liabilities. The Company’s quarterly financial covenants include achievement of minimum
earnings levels, which is based on earnings before depreciation and amortization expense, interest
expense, provisions for cash based income taxes, share-based compensation expense, rent expense and
certain other non-cash charges over a rolling twelve month period, and maintaining a minimum
specified fixed charge coverage ratio, which is based on the ratio of earnings calculation from the
minimum earnings
covenants discussed above less capital expenditures as compared to fixed charges, including
depreciation expense, rent expense, and income taxes paid.
The 2011 credit facility contains customary events of default, including for payment defaults,
breaches of representations, breaches of affirmative or negative covenants, cross defaults to other
material indebtedness, bankruptcy and failure to discharge
23
Table of Contents
certain judgments. If a default occurs
and is not cured within any applicable cure period or is not waived, the lenders may accelerate the
Company’s obligations under the 2011 credit facility. The 2011 credit facility replaced the 2008
credit facility which existed as of March 31, 2011. If the Company is determined to be in default
then any amounts outstanding under the 2011 credit facility would become immediately due and
payable and the Company would be required to collateralize with cash any outstanding letters of
credit up to 105% of the amounts outstanding.
As of September 30, 2011, the Company was in compliance with all of its covenants under the
2011 credit facility, including all financial covenants. At September 30, 2011, the Company had no
borrowings and outstanding letters of credit totaling $42,314 under the 2011 credit facility. As
of September 30, 2011, the Company had $32,686 available under the 2011 credit facility for future
borrowings or issuances of additional letters of credit.
In April 2011, the Company and one of its subsidiaries entered into a guarantee and collateral
agreement with SVB for the benefit of the lenders. The guarantee and collateral agreement provides
that the obligations under the 2011 credit facility are secured by all domestic assets of the
Company and several of its subsidiaries, excluding the Company’s foreign subsidiaries.
The Company incurred financing costs of $543 in connection with the 2011 credit facility,
which were deferred and are being amortized to interest expense over the life of the 2011 credit
facility, which matures on April 15, 2013.
In April 2011, the Company was required to provide financial assurance in connection with its
capacity bid in a certain open market bidding program. The Company provided this financial
assurance utilizing approximately $56,000 of its available cash on hand and a $39,000 letter of
credit issued under the 2011 credit facility. In May 2011, based on the capacity that the Company
cleared in this open market bidding program and the required post-auction financial assurance
requirements, the Company recovered all of the $56,000 of its available cash that it had provided
as financial assurance prior to the auction and was able to reduce the $39,000 letter of credit to
$13,500.
In June 2011, the Company and one of its subsidiaries entered into an amendment to the 2011
credit facility, which modified certain of the Company’s covenant requirements.
8. Commitments and Contingencies
The Company is contingently liable under outstanding letters of credit. Restricted cash
balances in the amount of $0 and $1,300, respectively, collateralize certain outstanding letters of
credit and cover financial assurance requirements in certain of the programs in which the Company
participated at September 30, 2011 and December 31, 2010. Restricted cash to secure certain other
commitments was $93 and $237 at September 30, 2011 and December 31, 2010, respectively.
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 $15,847 and $3,467, respectively, at
September 30, 2011 and December 31, 2010. These amounts primarily represent up-front payments
required by utility and electric power grid operator customers as a condition of participation in
certain demand response programs and to ensure that the Company will deliver its committed capacity
amounts in those programs. If the Company fails to meet its minimum committed capacity
requirements, a portion or all of the deposit may be forfeited. The Company assessed the
probability of default under these customer contracts and open market bidding programs and has
determined the likelihood of default and loss of deposits to be remote. In addition, under certain
utility and electric power grid operator customer contracts, if the Company does not achieve the
required performance guarantee requirements, the customer can terminate the arrangement and the
Company would potentially be subject to termination penalties. Under these arrangements, the
Company defers all fees received up to the amount of the potential termination penalty until the
Company has concluded that it can reliably determine that the potential termination penalty will
not be incurred or the termination penalty lapses. As of September 30, 2011, the Company had no
remaining deferred fees that were included in deferred revenues. As of September 30, 2011, the
maximum termination penalty that the Company was subject to under these arrangements, which the
Company has not deemed probable of incurring, is approximately $6,210.
In connection with the Company’s participation in an open market bidding program, the Company
entered into an arrangement with a third party during the second quarter of 2009 to bid capacity
into the program and provide the corresponding financial assurance required in connection with the
bid. The arrangement included an up-front payment by the Company equal to $2,000, of which $1,100
was expensed as interest expense during the second quarter of 2009 and $900 was deferred and will
be
recognized ratably as a charge to cost of revenues as revenue is recognized over the 2012/2013
delivery year. In addition, the Company will be required to pay the third party an additional
contingent fee, up to a maximum of $3,000, based on the revenue that the Company expects to earn in
2012 in connection with the bid. This additional fee will be recognized as earned.
24
Table of Contents
Indemnification Provisions
The Company includes indemnification provisions in certain of its contracts. These
indemnification provisions include provisions indemnifying the customer against losses, expenses,
and liabilities from damages that could be awarded against the customer in the event that the
Company’s services and related enterprise software platforms are found to infringe upon a patent or
copyright of a third party. The Company believes that its internal business practices and policies
and the ownership of information limits the Company’s risk in paying out any claims under these
indemnification provisions.
9. Stock-Based Compensation
Stock Options
The Company’s Amended and Restated 2003 Stock Option and Incentive Plan (2003 Plan) and the
Amended and Restated 2007 Employee, Director and Consultant Stock Plan (the 2007 Plan, and together
with the 2003 Plan, the Plans) provide for the grant of incentive stock options, nonqualified stock
options, restricted and unrestricted stock awards and other stock-based awards to eligible
employees, directors and consultants of the Company. Options granted under the Plans are
exercisable for a period determined by the Company, but in no event longer than ten years from the
date of the grant. Option awards are generally granted with an exercise price equal to the market
price of the Company’s common stock on the date of grant. Options, restricted stock awards and
restricted stock unit awards generally vest over four years, with certain exceptions. The 2003 Plan
expired upon the Company’s initial public offering (IPO) in May 2007. Any forfeitures under the
2003 Plan that occurred after the effective date of the IPO are available for future grant under
the 2007 Plan up to a maximum of 1,000,000 shares. The 2007 Plan provides for an annual increase to
the shares issuable under the 2007 Plan by an amount equal to the lesser of 520,000 shares or an
amount determined by the Company’s board of directors. This annual increase is effective on the
first day of each fiscal year through 2017. During the nine months ended September 30, 2011 and
2010, the Company issued 18,211 shares of its common stock and 24,681 shares of its common stock,
respectively, to certain executives to satisfy a portion of the Company’s compensation obligations
to those individuals. As of September 30, 2011, 2,065,965 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:
25
Table of Contents
Volatility measures the amount that a stock price has fluctuated or is expected to fluctuate
during a period. As there was no public market for the Company’s common stock prior to the
effective date of the IPO, the Company determined the volatility based on an analysis of reported
data for a peer group of companies that issued options with substantially similar terms. The
expected volatility of options granted through September 30, 2010 was determined using an average
of the historical volatility measures of this peer group of companies. During the three months
ended September 30, 2010, the Company determined that it had sufficient history to utilize
Company-specific volatility in accordance with ASC 718, Stock Compensation (ASC 718) and began
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 2011 credit facility preclude
the Company from paying dividends. During the three months ended September 30, 2011, the Company
updated its estimated exit rate pre-vesting and post-vesting applied to options, restricted stock
and restricted stock units based on an evaluation of demographics of its employee groups and
historical forfeitures for these groups in order to determine its option valuations as well as its
stock-based compensation expense. The changes in estimate of the volatility, exit rate pre-vesting
and exit rate post-vesting did not have a material impact on the Company’s stock-based compensation
expense recorded in the accompanying unaudited condensed consolidated statements of income for
the three and nine months ended September 30, 2011.
The Company accounts for transactions in which services are received from non-employees in
exchange for equity instruments based on the fair value of such services received or of the equity
instruments issued, whichever is more reliably measurable.
The components of stock-based compensation expense are disclosed below:
Stock-based compensation is recorded in the accompanying unaudited condensed consolidated
statements of income, as follows:
The Company recognized no material income tax benefit from stock-based compensation
arrangements during the three and nine months ended September 30, 2011 and 2010. In addition, no
material compensation cost was capitalized during the three and nine months ended September 30,
2011 and 2010.
The following is a summary of the Company’s stock option activity during the nine months ended
September 30, 2011:
26
Table of Contents
Additional Information About Stock Options
Of the stock options outstanding as of September 30, 2011, 1,640,505 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 September 30, 2011, the Company had
$5,398 of unrecognized stock-based compensation expense, which is expected to be recognized over a
weighted average period of 2.1 years. There were no unvested non-employee options as of September
30, 2011.
Restricted Stock and Restricted Stock Units
For non-vested restricted stock and restricted stock units outstanding as of September 30,
2011, the Company had $14,976 of unrecognized stock-based compensation expense, which is expected
to be recognized over a weighted average period of 2.4 years.
Restricted Stock
The following table summarizes the Company’s restricted stock activity during the nine months ended
September 30, 2011:
27
Table of Contents
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 4,350 shares of
restricted stock granted to certain non-executive employees, 250 shares granted to a non-employee,
and 16,000 shares of restricted stock granted to the Company’s board of directors during the nine
months ended September 30, 2011 that were immediately vested.
The fair value of restricted stock where vesting is solely based on service vesting condition
is expensed ratably over the vesting period. With respect to restricted stock where vesting
contains certain performance based vesting conditions, the fair value is expensed based on the
accelerated attribution method as prescribed by ASC 718 over the vesting period. During the nine
months ended September 30, 2011, the Company granted 260,000 shares of nonvested restricted stock
to certain executives that contain performance based vesting conditions, which the Company
determined were probable of being achieved. As of September 30, 2011, the Company determined that
the performance-based vesting conditions were still probable of being achieved. If the employee who
received the restricted stock leaves the Company prior to the vesting date for any reason, the
shares of restricted stock will be forfeited and returned to the Company.
Additional Information about Restricted Stock
Restricted Stock Units
The following table summarizes the Company’s restricted stock unit activity during the nine months
ended
September 30, 2011:
The total fair value of restricted stock units that vested during the nine months ended
September 30, 2011 was $1,537. The weighted average grant date fair value of restricted stock units
granted during the nine months ended September 30, 2010 was $28.99 per share. The total fair value
of restricted stock units that vested during the nine months ended September 30, 2010 was $1,440.
28
Table of Contents
10. Income Taxes
The Company accounts for income taxes in accordance with ASC 740, Income Taxes (ASC 740),
which is the asset and liability method for accounting and reporting income taxes. Under ASC 740,
deferred tax assets and liabilities are recognized based on temporary differences between the
financial reporting and income tax bases of assets and liabilities using statutory rates. In
addition, ASC 740 requires a valuation allowance against net deferred tax assets if, based upon the
available evidence, it is more likely than not that some or all of the deferred tax assets will not
be realized.
ASC 740 also provides criteria for the recognition, measurement, presentation and disclosures
of uncertain tax positions. A tax benefit from an uncertain tax position may be recognized if it is
“more likely than not” that the position is sustainable based solely on its technical merits. As of
September 30, 2011 and December 31, 2010, the Company had no material unrecognized tax benefits.
In accordance with ASC 740, each interim period is considered an integral part of the annual
period and tax expense is measured using an estimated annual effective tax rate. An enterprise is
required, at the end of each interim reporting period, to make its best estimate of the annual
effective tax rate for the full fiscal year and use that rate to provide for income taxes on a
current year-to-date basis. Generally, if an enterprise has an ordinary loss for the year to date
at the end of an interim period and anticipates ordinary income for the fiscal year, the enterprise
will record an interim period tax benefit based on applying the estimated annual effective tax rate
to the ordinary loss as long as the tax benefits are realized during the year or recognizable as a
deferred tax asset as of the end of the year. However, if an enterprise is unable to make a
reliable estimate of its annual effective tax rate than the actual effective tax rate for the
year-to-date may be the best estimate of the annual effective tax rate. The Company has determined
that it is currently unable to make a reliable estimate of its annual effective tax rate as of
September 30, 2011 due to unusual sensitivity to the rate as it relates to the current forecasted
fiscal 2011 U.S. ordinary income (loss). As a result, the Company recorded a tax provision for the
nine months ended September 30, 2011 based on its actual effective tax rate for nine months ended
September 30, 2011. The tax provision recorded for the three and nine months ended September 30,
2011 was $1,225 and $1,992, respectively, and represented the following:
The Company reviews all available evidence to evaluate the recovery of deferred tax assets,
including the recent history of accumulated losses in all tax jurisdictions over the last three
years, as well as its ability to generate income in future periods. As of September 30, 2011, due
to the uncertainty related to the ultimate use of the Company’s deferred income tax assets, the
Company provided a full valuation allowance on all of its U.S. deferred tax assets.
11. Concentrations of Credit Risk
The following table presents the Company’s significant customers. With respect to PJM
Interconnection (PJM) and ISO-New England, Inc. (ISO-NE), these customers are regional electric
power grid operator customers, 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.
29
Table of Contents
Accounts receivable from PJM was approximately $5,913 and $7,848 at September 30, 2011 and
December 31, 2010, respectively. Accounts receivable from ISO-NE was approximately $2,696 and
$3,351 at September 30, 2011 and December 31, 2010, respectively.
Pacific Gas and Electric Company and Southern California Edison Company (SCE) also comprised
10% or more of the accounts receivable balance at September 30, 2011 at 15% and 16%, respectively.
SCE was the only additional customer that comprised 10% or more of the accounts receivable balance
at December 31, 2010 at 15% of the accounts receivable balance. Unbilled revenue related to PJM was
$101,431 and $72,887 at September 30, 2011 and December 31, 2010, respectively. There was no
significant unbilled revenue for any other customers at September 30, 2011 and December 31, 2010.
12. Legal Proceedings
The Company is subject to legal proceedings, claims and litigation arising in the ordinary
course of business. The Company does not expect the ultimate costs to resolve these matters to have
a material adverse effect on its consolidated financial condition, results of operations or cash
flows.
13. Recent Accounting Pronouncements
Business Combinations
In December 2010, the FASB issued Accounting Standards Update No. 2010-29, Business
Combinations — Disclosure of Supplementary Pro Forma Information for Business Combinations (ASU
2010-29). ASU 2010-29 requires a public entity to disclose revenue and earnings of the combined
entity as though the business combination that occurred during the current year had occurred as of
the beginning of the prior year. It also requires a description of the nature and amount of
material, nonrecurring adjustments directly attributable to the business combination included in
the reported revenue and earnings. The new disclosure was effective for the Company’s first quarter
of fiscal 2011. The adoption of ASU 2010-29 requires additional disclosure in the event of a
material business combination but did not have a material impact on the Company’s financial
condition and results of operations during the three and
nine months ended September 30, 2011. As a result of the acquisition of Energy Response in
July 2011, the Company was required to meet certain disclosure requirements and provide pro-forma
financial information. Refer to Note 2 for further information on the acquisition of Energy
Response.
Intangibles — Goodwill and Other
In December 2010, the FASB issued ASU 2010-28, Intangibles- Goodwill and Other (ASU 2010-28).
ASU 2010-28 modifies Step 1 of the goodwill impairment test for reporting units with zero or
negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of
the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In
determining whether it is more likely than not that a goodwill impairment exists, an entity should
consider whether there are any adverse qualitative factors indicating that an impairment may exist.
ASU 2010-28 is effective for fiscal years that begin after December 15, 2010, which is fiscal 2011
for the Company. The adoption of ASU 2010-28 did not have a material impact on the Company’s
results from operations and financial condition.
30
Table of Contents
ASC 350 (ASC 350), Intangibles — Goodwill and Other (formerly the FASB) SFAS No. 142,
Goodwill and Other Intangible Assets), has a two-step impairment test that requires companies to
assess goodwill for impairment by quantitatively comparing the fair value of a reporting unit with
its carrying amount, including goodwill (Step 1). If the reporting unit’s fair value is less than
its carrying amount, Step 2 of the goodwill impairment test must be performed to measure the amount
of the goodwill impairment, if any.
In September 2011, the FASB issued ASU 2011-08, Intangibles—Goodwill and Other (Topic 350):
Testing Goodwill for Impairment, (ASU 2011-08) which gives companies the option to first perform a
qualitative assessment to determine whether it is more likely than not (a likelihood of more than
50%) that the fair value of a reporting unit is less than its carrying amount. If a company
concludes that this is the case, it must perform the two-step test. Otherwise, a company can forgo
the two-step test. ASU 2011-08 is effective for fiscal years that begin after December 15, 2011,
which is fiscal 2012 for the Company; however, early adoption is permitted. The Company is
currently evaluating ASU 2011-08, including whether the Company will early adopt. The Company does
not expect the adoption of ASU 2011-08 to have a material impact on its consolidated financial
condition or results of operations.
Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and
IFRS
In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement
and Disclosure Requirements in U.S. GAAP and IFRS (ASU 2011-04), which amends the FASB’s accounting
guidance related to fair value measurements in order to more closely align its disclosure
requirements with those in International Financial Reporting Standards. ASU 2011-04 clarifies the
application of existing fair value measurement and disclosure requirements and also changes certain
principles or requirements for measuring fair value or for disclosing information about fair value
measurements. ASU 2011-04 is effective for interim and annual periods beginning after December 15,
2011. The adoption of ASU 2011-04 is not expected to have a material effect on the Company’s
financial position or results of operations.
Presentation of Comprehensive Income
In June 2011, the FASB issued ASU 2011-05, Presentation of Comprehensive Income (ASU 2011-05),
which represents new accounting guidance related to the presentation of other comprehensive income
(OCI). ASU 2011-05 eliminates the option to present components of OCI as part of the statement of
changes in shareholders’ equity, which is the option that the Company currently uses to present
OCI. ASU 2011-05 allows for a one-statement or two-statement approach, outlined as follows:
ASU 2011-05also requires an entity to present on the face of the financial statements any
reclassification adjustments for items that are reclassified from OCI to net income. ASU 2011-05 is
effective for interim and annual periods beginning after December 15, 2011. The adoption of ASU
2011-05will not have an effect on the Company’s financial position or results of operations, but
will only impact how certain information related to OCI is presented in the Company’s consolidated
financial statements.
31
Table of Contents
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion should be read in conjunction with our unaudited condensed
consolidated financial statements and related notes thereto included elsewhere in this Quarterly
Report on Form 10-Q, as well as our audited financial statements and notes thereto and Management’s
Discussion and Analysis of Financial Condition and Results of Operations included in our Annual
Report on Form 10-K for the fiscal year ended December 31, 2010, as filed with the Securities and
Exchange Commission, or the SEC, on March 1, 2011. This Quarterly Report on Form 10-Q contains
forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as
amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended,
or the Exchange Act. Without limiting the foregoing, the words “may,” “will,” “should,” “could,”
“expect,” “plan,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,”
“continue,” “target” and variations of those terms or the negatives of those terms and similar
expressions are intended to identify forward-looking statements. All forward-looking statements
included in this Quarterly Report on Form 10-Q are based on current expectations, estimates,
forecasts and projections and the beliefs and assumptions of our management including, without
limitation, our expectations regarding our results of operations, operating expenses and the
sufficiency of our cash for future operations. We assume no obligation to revise or update any such
forward-looking statements. Our actual results could differ materially from those anticipated in
these forward-looking statements as a result of certain important factors, including those set
forth below under this Item 2 — “Management’s Discussion and Analysis of Financial Condition and
Results of Operations,” Part II, Item 1A — “Risk Factors” and elsewhere in this Quarterly Report
on Form 10-Q, as well as in our Annual Report on Form 10-K for the fiscal year ended December 31,
2010. You should carefully review those factors and also carefully review the risks outlined in
other documents that we file from time to time with the SEC.
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. As of
September 30, 2011, we managed approximately 7,000 megawatts, or MW, of demand response capacity
across a C&I customer base of approximately 4,750 accounts and 11,150 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 the 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.
32
Table of Contents
Since inception, our business has grown substantially. We began by providing demand response
services in one state in 2003 and expanded to providing our portfolio of energy management
applications and services in several regions throughout the United States, as well as
internationally in Australia, Canada, New Zealand and the United Kingdom, by September 30, 2011.
Significant Recent Developments
In
February 2011, PJM Interconnection, or PJM, a grid operator
customer, and Monitoring Analytics, LLC, the PJM market monitor, issued a joint
statement concerning settlements in PJM’s capacity market for participants using a certain baseline
methodology for the measurement and verification of demand response. We refer to this as the PJM
statement. The PJM statement, among other things, asserted that certain market practices in the PJM
capacity market were no longer appropriate or acceptable and unilaterally implied that compensation
should no longer be determined by actual measured reductions in a C&I customer’s electrical load,
unless the reductions are below that C&I customer’s peak
demand for electricity, or PLC, in the prior year.
In March 2011, we filed for and were granted expedited declaratory
relief with the Federal Energy Regulatory Commission, or FERC, which
allowed us to continue to manage our portfolio of demand
response capacity in PJM as we had in the past and receive settlement in accordance
with the then current PJM market rules approved by FERC. However, PJM
continued to take steps to modify
the market rules according to the PJM statement, including by filing proposed tariff changes with
FERC.
On
November 4, 2011, FERC issued an order that addressed the PJM
statement and clarified the rules related to the measurement and verification of demand response resources in the PJM
capacity market, which is a market from which we derive a substantial
portion of our revenues. We refer to this as the FERC order. The FERC order,
among other things, preserves PJM’s original market rules for the
full compliance period of the 2011-12 delivery year, while accepting
PJM’s proposed market rule changes going forward, subject to
certain conditions, including the requirement that PJM submit a compliance filing with FERC by January 3, 2012 that includes the
development of an interim mechanism to protect demand response suppliers’ reasonable reliance expectations
regarding capacity compliance measurement and verification for the 2012-13 delivery year through the 2014-15
delivery year and explains how PJM will treat the aggregation of
demand response resources under its proposal. In addition, the FERC order
encouraged further examination of the limitations of PLC and consideration of the
development of a more dynamic baseline methodology applicable to
demand response resources in the future.
Revenues and Expense Components
Revenues
We derive recurring revenues from the sale of our energy management applications and services.
We do not recognize any revenues until persuasive evidence of an arrangement exists, delivery has
occurred, the fee is fixed or determinable, and we deem collection to be reasonably assured.
Our revenues from our demand response services primarily consist of capacity and energy
payments, including ancillary services payments. We derive revenues from demand response capacity
that we make available in open market programs and pursuant to contracts that we enter into with
electric power grid operators and utilities. In certain markets, we enter into contracts with
electric power grid operators and utilities, generally ranging from three to 10 years in duration,
to deploy our demand response services. We refer to these contracts as utility contracts.
Where we operate in open market programs, our revenues from demand response capacity payments
may vary month-to-month based upon our enrolled capacity and the market payment rate. Where we have
a utility contract, we receive periodic capacity payments, which may vary monthly or seasonally,
based upon enrolled capacity and predetermined payment rates. Under both open market programs and
utility contracts, we receive capacity payments regardless of whether we are called upon to reduce
demand for electricity from the electric power grid, and we recognize revenue over the applicable
delivery period, even where payments are made over a different period. We generally demonstrate our
capacity either through a demand response event or a measurement and verification test. This
demonstrated capacity is typically used to calculate the continuing periodic capacity payments to
be made to us until the next demand response event or measurement and verification test establishes
a new demonstrated capacity amount. In most cases, we also receive an additional payment for the
amount of energy usage that we actually curtail from the grid during a demand response event. We
refer to this as an energy payment.
As program rules may differ for each open market program in which we participate and for each
utility contract, we assess whether or not we have met the specific service requirements under the
program rules and recognize or defer revenues as necessary. We recognize demand response capacity
revenues when we have provided verification to the electric power grid operator or utility of our
ability to deliver the committed capacity under the open market program or utility contract.
Committed capacity is verified through the results of an actual demand response event or a
measurement and verification test. Once the capacity amount has been verified, the revenues are
recognized and future revenues become fixed or determinable and are recognized monthly over the
performance period until the next demand response event or measurement and verification test. In
subsequent demand response events or measurement and verification tests, if our verified capacity
is below the previously verified amount, the electric power grid operator or utility customer will
reduce future payments based on the adjusted verified capacity amounts. Under certain utility
contracts and open market program participation rules, our performance and related fees are
measured and determined over a period of time. If we can reliably estimate our performance for the
applicable performance period, we will reserve the entire amount of estimated penalties that will
be incurred, if any, as a result of estimated underperformance prior to the commencement of revenue
recognition. If we are unable to reliably estimate the performance and any related penalties, we
defer the recognition of revenues until the fee is fixed or determinable. Any changes to our
original estimates of net revenues are recognized as a change in accounting estimate in the
earliest reporting period that such a change is determined.
We defer incremental direct costs incurred related to the acquisition or origination of a
utility contract or open market program in a transaction that results in the deferral or delay of
revenue recognition. As of September 30, 2011 and December 31, 2010, 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 three and nine months
ended September 30, 2011 and 2010, we did not defer any contract origination costs. 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. During the three months ended September 30, 2011 and 2010, we
capitalized $1.9 million and $1.3 million, respectively, of production and generation equipment
costs. During the nine months ended September 30, 2011 and 2010, we capitalized $8.5 million
33
Table of Contents
and $5.8 million, respectively, of production and generation equipment costs. We believe that
this accounting treatment appropriately matches expenses with the associated revenue.
As of September 30,
2011, we had approximately 7,000 MW under management in our demand
response network, meaning that we had entered into definitive contracts with our C&I customers
representing approximately 7,000 MW of demand response capacity. In determining our MW under
management in the seasonal demand response programs in which we participate, we typically count the
maximum demand response capacity for a C&I customer site over a trailing twelve-month period as the
MW under management for that C&I customer site. However, the trailing period could be longer in
certain programs under which significant rule changes have occurred or under which we do not have
enough obligation to enroll all of our MW in a given program period, but have enough obligation in
a future program period to enroll the MW again. 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-New England, Inc., or 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.
In the PJM open market programs in which we participate, the program year operates on a June
to May basis and performance is measured based on the aggregate performance during the months of
June through September. As a result, fees received for the month of June could potentially be
subject to adjustment or refund based on performance during the months of July through September.
We concluded that we could reliably estimate the amount of fees potentially subject to adjustment
or refund and recorded a reserve for this amount in the month of June. As of June 30, 2011, we
recorded an estimated reserve of $9.3 million related to potential subsequent performance
adjustments. The fees under this program were fixed as of September 30, 2011 and, based on final
performance during the three months ended September 30, 2011, we recorded a reduction in the
estimated reserve totaling $3.7 million, which resulted in final performance adjustments of $5.6
million. For the three months ended September 30, 2011, the impact of this change in estimate on
income before income tax and net income was $3.7 million and $3.6 million, respectively, and the
impact of this change in estimate on diluted income per common share was $0.13. This
change in estimate had no impact on the nine months ended September 30, 2011 nor will it impact any
future periods. Our performance estimates which provided the basis for the estimated reserve as of
June 30, 2011 were reasonably consistent with the actual performance during demand response events and test events
during the three months ended September 30, 2011. The primary driver of the change in estimate
from June 30, 2011 to September 30, 2011 was due to the differences based on the number and type of
demand response events by which performance was measured, which was not within our control. We are in the process
of reevaluating our ability to reliably estimate the amount of fees potentially subject to
adjustment or refund for the year ending December 31, 2012, or fiscal 2012, on a prospective basis
based on our consideration of our actual performance during the months of June 2011 through
September 2011, as well as additional guidance issued by PJM regarding its interpretation of
certain program rules that will impact performance calculations on a prospective basis. As there
are no revenues recognized related to the PJM open market programs during the fourth quarter of our
fiscal year, any change in our evaluation of our ability to reliably estimate the amount of fees
potentially subject to adjustment or refund would have no impact on results of operations for the
three months ending December 31, 2011.
Although we believe
that, based on the language contained in the FERC order, our revenues derived from the PJM
market for the fiscal year ending December 31, 2011, or fiscal 2011, will not be impacted
by the FERC order, our
ability to manage our portfolio of demand response capacity
in the PJM market for future delivery years may be
harmed by the FERC order, which could significantly reduce our future revenues for 2012 and beyond and which
may have
a material adverse effect on our results of operations and financial condition. Furthermore, the attention of
our management and other personnel has been, and may continue to be, diverted as we evaluate and respond to the
FERC order, which may continue to have a negative impact on our sales efforts in, and revenues and gross profits
derived from the PJM region, as well as our other operating regions.
34
Table of Contents
Revenues generated from open market sales to PJM accounted for 71% and 78%, respectively, of
our total revenues for the three months ended September 30, 2011 and 2010 and 58% and 65%,
respectively, of our total revenues for the nine months ended September 30, 2011 and 2010.
Revenues generated from open market sales to ISO-NE accounted for 11% and 16%, respectively,
of our total revenues for the nine months ended September 30, 2011 and 2010. Revenues generated
from open market sales to ISO-NE did not comprise more than 10% of our total revenues for the three
months ended September 30, 2011 or 2010.
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.
We also derive revenues from the sale, installation and ongoing
services of our wireless technology solutions, primarily related to
our acquisition of M2M Communications Corporation, or M2M, in January
2011.
Revenues derived from these offerings were $7.3 million
and $4.0 million, respectively, for the three months ended September 30, 2011 and 2010 and $19.6
million and $10.5 million, respectively, for the nine months ended September 30, 2011 and 2010.
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 acquired developed technology, 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 elsewhere in this Quarterly Report on Form 10-Q 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 costs, equipment depreciation, and the wages and associated benefits that we pay
to our project managers for the performance of their services.
Gross Profit and Gross Margin
Gross profit consists of our total revenues less our cost of revenues. Our gross profit has
been, and will be, affected by many factors, including (a) the demand for our energy management
applications and services, (b) the selling price of our energy management applications and
services, (c) our cost of revenues, (d) the way in which we manage, or are permitted to manage by
the relevant electric power grid operator or utility, our portfolio of demand response capacity,
(e) the introduction of new clean and intelligent energy management applications and services, (f)
our demand response event performance and (g) our ability to open and enter new markets and regions
and expand deeper into markets we already serve. Our outcomes in negotiating favorable contracts
with our C&I customers, as well as with our electric power grid operator and utility customers, the
effective management of our portfolio of demand response capacity and our demand response event
performance are the primary determinants of our gross profit and gross margin.
Operating Expenses
Operating expenses consist of selling and marketing, general and administrative, and research
and development expenses. Personnel-related costs are the most significant component of each of
these expense categories. We grew from 465 full-time employees at September 30, 2010 to 587
full-time employees at September 30, 2011. 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. We expect our overall operating expenses to increase in absolute dollar
terms for the foreseeable future and to increase as a percentage of total annual revenues in the
near term as we continue to invest in our business and employee base in order to capitalize on
emerging opportunities, expand the development of our energy management applications and services,
and grow our MW under management. In
35
Table of Contents
addition, amortization expense from intangible assets acquired in future acquisitions will
increase our operating expenses in future periods.
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 our selling and marketing expenses to continue to increase
in absolute dollar terms for the foreseeable future and to slightly increase as a percentage of
total annual revenues in the near term as we further increase the number of our sales
professionals.
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, including fees associated
with acquisitions, (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 and to slightly increase as a percentage of total annual revenues in the near
term as we further invest in our infrastructure and employee base to support our continued growth.
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 three and nine months ended September 30, 2011,
we capitalized software development costs of $0.8 million and $2.9 million, respectively, and the
amount is included as software in property and equipment at September 30, 2011. During the three
and nine months ended September 30, 2010, we capitalized software development costs of $1.0 million
and $5.1 million, respectively, and the amount is included as software in property and equipment at
September 30, 2010. Included in the amounts above, we capitalized $0 and $0.2 million
during the three months ended September 30, 2011 and 2010, respectively, and $13,000 and $1.2 million
during the nine months ended September 30, 2011 and 2010, respectively, related to a company-wide
enterprise resource planning systems implementation project, which was put into production in June
2011 and is being amortized over a five year useful life. We expect research and development
expenses to increase in absolute dollar terms for the foreseeable future and to slightly increase
as a percentage of total annual revenues in the near term as we develop new technologies and
further invest in our research and development organization.
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
income 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 and will be estimated on the date of grant using a lattice valuation
model. For the three months ended September 30, 2011 and 2010, we recorded expenses of
approximately $3.2 million and $3.7 million, respectively, in connection with share-based payment
awards to employees and non-employees. For the nine months ended September 30, 2011 and 2010, we
recorded expenses of approximately $10.5 million and $11.7 million, respectively, in connection
with share-based payment awards to employees and non-employees. With respect to option grants
through September 30, 2011, a future expense of non-vested options of approximately $5.4 million is
expected to be recognized over a weighted average period of 2.1 years. With respect to restricted
stock and restricted stock units issued through September 30, 2011, a future expense of unvested
restricted stock and restricted stock unit awards of approximately $15.0 million is expected to be
recognized over a weighted average period of 2.4 years.
36
Table of Contents
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, and municipal bonds.
Interest Expense
Interest expense consists of interest on our capital lease obligations, fees associated with
the credit facility that we entered into with Silicon Valley Bank, or SVB, in August 2008, which we
refer to as the 2008 credit facility, fees associated with the $75.0 million senior secured
revolving credit facility that we entered into with SVB and a certain other lender in April 2011,
which we refer to as the 2011 credit facility, and fees associated with issuing letters of credit
and other financial assurances.
Consolidated Results of Operations
Three and Nine Months Ended September 30, 2011 Compared to the Three and Nine Months Ended
September 30, 2010
Revenues
The following table summarizes our revenues for the three and nine months ended September 30,
2011 and 2010 (dollars in thousands):
For the three months ended September 30, 2011, our DemandSMART revenues increased by $3.0
million, or 2%, as compared to the three months ended September 30, 2010. For the nine months ended
September 30, 2011, our DemandSMART revenues decreased by $6.7 million, or 3%, as compared to the
nine months ended September 30, 2010. The increase (decrease) in our DemandSMART revenues was
primarily attributable to changes in the following existing operating areas (dollars in thousands):
37
Table of Contents
The increase in DemandSMART revenues during the three months ended September 30, 2011
as compared to the same period in 2010 was
partially due to our ability to recognize revenues that had previously been deferred in connection
with our utility contract with Ontario Power Authority, or the OPA contract. As a result of an
amendment to the OPA contract that modified certain refund provisions
and that we entered into during the
three months ended September 30, 2011, we concluded that fees under the OPA contract were no longer
subject to refund and were fixed or determinable. As a result, during the three months ended
September 30, 2011, we recognized as revenues $2.3 million of fees under the OPA contract that had
been previously deferred. Prior to the three months ended March 31, 2011, we had not
recognized any revenues related to the OPA contract. The increase in DemandSMART revenues was also
partially attributable to an increase in MW enrolled in our New England and California demand
response programs and stronger demand response event performance in those programs. The increase in
DemandSMART revenues was also partially attributable to our participation in a demand response
program in Australia, which resulted from our acquisitions of DMT Energy Pty Ltd, or DMT, during
the first quarter of 2011and Energy Response Holdings Pty Ltd, or Energy Response, during the third quarter
of 2011. The increase in DemandSMART revenues related to other demand response programs, including
Tennessee Valley Authority, were primarily driven by an increase in MW enrolled in these programs.
The increase in DemandSMART revenues was also partially attributable to a $3.7 million change in
the estimate related to the reserve for potential performance adjustments in PJM that had been
recorded during the three months ended September 30, 2011. The increase in DemandSMART revenues
during the three months ended September 30, 2011 was partially offset by less favorable pricing in
our PJM, New England and New York programs, as well as a decrease in MW enrolled in our ERCOT
program as compared to the same period in 2010. DemandSMART revenues were also negatively affected
by fewer demand response events being called during the three months ended September 30, 2011,
which resulted in decreased energy payments, as compared to the same period in 2010.
The decrease in our DemandSMART revenues during the nine months ended September 30, 2011 as
compared to the same period in 2010 was primarily attributable to less favorable pricing in the PJM
and New York markets, as well as a decrease in MW enrolled in our ISO-NE program as compared to
the same period in 2010 as a result of the commencement of an ISO-NE program in which we currently
participate, 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. The decrease in DemandSMART
revenues was also partially attributable to fewer demand response events being called by PJM during the
three months ended September 30, 2011, which resulted in decreased energy payments, as compared to
the same period in 2010. The decrease in DemandSMART revenues was partially offset by an increase
in revenues recognized as a result of amendments to the OPA contract during the nine months ended
September 30, 2011 that resulted in the recognition of $5.3 million of revenues during the period
that had been previously deferred. The decrease in DemandSMART revenues was also partially offset
by an increase in our MW under management in certain of the demand response programs in which we participate,
stronger demand response event performance in our California demand response programs, our
participation in demand response programs in Australia and our ability to recognize revenues based
on the finalization of performance in a certain California demand response program. There were no
revenues related to Australia in 2010.
For the three and nine months ended September 30, 2011, our EfficiencySMART, SupplySMART and
CarbonSMART applications and services and other revenues increased by $3.3 million and $9.1 million,
respectively, as compared to the same periods in 2010, primarily due to our acquisitions of Global
Energy Partners, Inc., or Global Energy, and M2M, both of which occurred in January 2011. In addition, we completed a certain EfficiencySMART
project during the three months ended September 30, 2011, which resulted in the recognition of $0.6
million of revenues that had been previously deferred.
We currently expect our total revenues to increase slightly for the year ending December 31,
2011 as compared to 2010, as we further increase our MW under management in all of our expanded
operating regions, enroll new C&I customers in our demand response programs, expand the sales of
our EfficiencySMART, SupplySMART and CarbonSMART applications and
services and other services and products to our new and existing
C&I customers, and pursue more favorable pricing opportunities with our C&I customers. Although our
MW under management have increased in the PJM market in 2011 as compared to 2010, until PJM prices
improve in 2013, 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.
38
Table of Contents
In addition, the discontinuance of PJM’s Interruptible Load for
Reliability program, or 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 will also negatively impact our revenues in 2012.
Although we believe that, based on the language contained in the FERC order, our revenues derived from the PJM
market for fiscal 2011 will not be impacted by the FERC order, our ability to manage our portfolio of demand
response capacity in the PJM market for future delivery years may be harmed by the FERC order, which could
significantly reduce our future revenues for 2012 and beyond and which may have a material adverse effect on our
results of operations and financial condition. Furthermore, the attention of our management and other personnel has
been, and may continue to be, diverted as we evaluate and respond to the FERC order, which may continue to have a
negative impact on our sales efforts in, and revenues derived from the PJM region, as well as our other operating
regions.
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 three and nine months ended September 30, 2011 and
2010 (dollars in thousands):
The increase in gross profit during the three and nine months ended September 30, 2011 as
compared to the same periods in 2010 was primarily due to our ability to recognize revenues that
had previously been deferred in connection with the OPA contract, pursuant to which we recognized
the cost of such revenues in previous periods, and to a change in estimate of $3.7 million related
to the estimated reserve for potential performance adjustments in PJM that had been recorded during the
three months ended June 30, 2011. The increase in gross profit was also partially attributable to stronger demand response event
performance in certain of the demand response programs in which we
participate, including ISO-NE, which in some cases
resulted in increased energy payments for the three and nine months ended September 30, 2011 as
compared to the same periods in 2010, as well as our ability to recognize revenues based on the
finalization of performance in a certain California demand response program for which the
corresponding cost of revenues were recorded in 2010. The acquisitions of Global Energy, M2M,
Energy Response and DMT that we completed in 2011 also contributed to the increase in gross profit
for the three and nine months ended September 30, 2011. The increase was partially
offset by less favorable pricing in PJM and ISO-NE, as well as fewer demand response events being
called by PJM during the three and nine months ended September 30, 2011, which resulted in
decreased energy payments, as compared to the same periods in 2010.
The increase in gross margin during the three months ended September 30, 2011 as compared to the
same period in 2010 was primarily due to the recognition of revenues in connection with the OPA
contract, pursuant to which we recognized the cost of revenues in previous periods, and a change in
estimate of $3.7 million related to the estimated reserve for potential performance adjustments in PJM
that had been recorded during the three months ended June 30, 2011. The increase was partially
offset by less favorable pricing in PJM and ISO-NE, which was not entirely offset by lower payments
to our C&I customers. Our gross margin for the nine months ended September 30, 2011 was
consistent with the comparable period in 2010.
We currently expect that our gross margin for the year ending December 31, 2011 will be
slightly higher than our gross margin for the year ended December 31, 2010, and that our gross
margin for the three months ended 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 industry. In addition, until 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
39
Table of Contents
2012. Although we believe that, based on the language contained in the FERC order, our gross profit derived from the
PJM market for fiscal 2011 will not be impacted by the FERC order, our ability to manage our portfolio of demand
response capacity in the PJM market for future delivery years may be harmed by the FERC order, which could
significantly reduce our future gross profits for 2012 and beyond and which may have a material adverse effect on
our results of operations and financial condition. Furthermore, the attention of our management and other personnel
has been, and may continue to be, diverted as we evaluate and respond to the FERC order, which may continue to
have a negative impact on our sales efforts in, and gross profits derived from the PJM region, as well as our other
operating regions.
Operating Expenses
The following table summarizes our operating expenses for the three and nine months ended
September 30, 2011 and 2010 (dollars in thousands):
In certain forward capacity markets in which we participate, such as PJM, we may
enable our C&I customers, meaning we may install our equipment at a C&I customer site to allow for
the curtailment of MW from the electric power grid, up to twelve months in advance of enrolling the
C&I customer in a particular demand response 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.
The increase in payroll and related costs within our operating expenses during the three and nine
months ended September 30, 2011 as compared to the same periods in 2010 was primarily driven by an
increase in headcount, which was substantially due to the
acquisitions that we completed in 2011.
Selling and Marketing Expenses
40
Table of Contents
The increase in selling and marketing expenses for the three and nine months ended September
30, 2011 as compared to the same periods in 2010 was primarily due to an increase in payroll and
related costs associated with an increase in the number of selling and marketing full-time
employees from 176 at September 30, 2010 to 242 at September 30, 2011. The increase was offset by
a decrease in salary rates per full-time employee, as well as the timing associated with our hiring
new full-time employees during 2011 as compared to 2010. The increase was also offset by decreases
in sales commissions payable to employees in our sales organization of $1.3 million and $0.5 million
for the three and nine months ended September 30, 2011, respectively, as compared to the same
periods in 2010.
The decrease in stock-based compensation for the three months ended September 30, 2011
as compared to the same period in 2010 was primarily due to significant stock-based awards granted in
2007 that became fully vested prior to the three months ended September 30, 2011. The decrease
was also partially attributable to the reversal of stock-based compensation expense due to
forfeitures of a greater number of stock-based awards in connection with an increase in our
attrition rate. Stock-based compensation for the nine months ended September 30, 2011 was relatively flat as compared to the same period in 2010.
The increase in other selling and marketing expenses for the three and nine months ended
September 30, 2011 as compared to the same periods in 2010 was primarily attributable to an increase
in amortization expense of $1.5 million and $3.0 million, respectively, due to the customer
relationship and trade name intangible assets acquired in connection with our acquisitions of Global
Energy, M2M, Energy Response and DMT. During the three and nine months ended September 30, 2011,
we recorded an impairment charge of $0.2 million and $0.2 million, respectively, related to the
discontinued use of the trade name intangible assets acquired in connection with our acquisitions
of Energy Response and DMT in 2011, which also contributed to the increase in selling and marketing
expenses for the three and nine months ended September 30, 2011 as compared to the same periods in
2010. The increase in other selling and marketing expenses for the three months ended September 30,
2011 as compared to the same period in
2010 was also partially attributable to allocating company-wide costs to selling and marketing expenses based
on headcount, which resulted in an increase in facility costs of $0.1 million due to the expansion
of our office space as a result of recent acquisitions. The increase in other selling and
marketing expenses for the nine months ended September 30, 2011 as compared to the same period in
2010 was also partially attributable to an increase in professional services fees of $0.2 million. The
increase in other selling and marketing expenses for the three and nine months ended September 30,
2011 was offset by a decrease in marketing costs of $0.2 million and $0.4 million, respectively,
due to our rebranding efforts that took place in 2010.
General and Administrative Expenses
The increase in general and administrative expenses for the three and nine months ended
September 30, 2011 as compared to the same periods in 2010 was primarily due to an increase in payroll
and related costs due to an increase in salary rates and certain severance costs. The increase in
payroll and related costs for the three and nine months ended September 30, 2011 as compared to the
same periods in 2010 was also partially attributable to an increase in full-time employees from 232
at September 30, 2010 to 273 at September 30, 2011.
41
Table of Contents
The decrease in stock-based compensation for the three and nine months ended September 30,
2011 as compared to the same periods in 2010 was primarily due to prior period stock-based awards that were fully vested as
of June 30, 2011 and the reversal of stock-based compensation expense due to forfeitures of
a greater number of stock-based awards in connection with an increase in our attrition rate. The decrease in
stock-based compensation expense for the nine months ended September 30, 2011 as compared to the same
period in 2010 was also partially attributable to fully-vested stock awards granted to our board of directors
during the nine months ended September 30, 2011 with a lesser grant-date fair value than the same
amount of fully-vested stock awards granted during the same period in 2010.
The increase in other general and administrative expenses for the three months ended September
30, 2011 as compared to the same period in 2010 was primarily attributable to an increase in
professional services fees of $0.5 million incurred in connection with the integration of the Global Energy, M2M, Energy
Response and DMT acquisitions. The increase was also partially attributable to technology and
communication costs of $0.4 million due to increased software licensing fees and computer supplies,
as well as new hire orientation training costs of $0.1 million, all of which resulted from
increased headcount. Additionally, for the three months ended
September 30, 2011, we allocated company-wide costs to general and administrative
expenses based on headcount, which resulted in an increase in facility costs of $0.2 due to the
expansion of our office space as a result of recent acquisitions.
The increase in other general and administrative expenses for the nine months ended September
30, 2011 as compared to the same period in 2010 was primarily attributable to an increase in
professional services fees of $1.6 million incurred in
connection with the integration of the acquisitions that we completed in 2011. The
increase was also partially attributable to miscellaneous expenses, including finance charges and
other taxes, of $0.5 million due to the growth of our business, as well as technology and
communication costs of $0.7 million. We also allocated company-wide costs to general and
administrative expenses for the nine months ended September 30, 2011 based on headcount, which resulted in an increase in facility costs of $0.5
million due to the expansion of our office space as a result of our recent acquisitions. The
increase was also attributable to employee-related non-compensation expenses, including payroll
services and other expenses of $0.4 million.
Research and Development Expenses
The increase in research and development expenses for the three and nine months ended
September 30, 2011 as compared to the same periods in 2010 was primarily driven by the costs
associated with an increase in the number of research and development full-time employees from 57
at September 30, 2010 to 72 at September 30, 2011, as well as an increase in salary rates per
full-time employee. The increase was offset by an increase in capitalized internal payroll and
related costs of $0.2 million and $0.6 million,
respectively, for the three and nine months ended September 30, 2011.
The increase in stock-based compensation for the three and nine months ended September 30,
2011 as compared to the same periods in 2010 was primarily due to costs related to equity awards
granted to new employees during 2011, including a senior level employee.
The decrease in other research and development expenses for the three months ended September
30, 2011 as compared to the same period in 2010 was primarily related to $0.2 million in higher
consulting-related professional fees incurred during the three months ended September 30, 2010. We
also allocated company-wide costs to research and development expenses for the three months ended September 30, 2011 based on
42
Table of Contents
headcount, which resulted in a $0.1 million increase of facility costs related to increased
rent expense due to the expansion of our office space as a result of acquisitions.
The increase in other research and development expenses for the nine months ended
September 30, 2011 as compared to the same period in 2010 was primarily attributable to a $0.5 million
increase in technology and communications expenses related to software licensing fees. We also
allocated company-wide costs to research and development expenses for the nine months ended September 30, 2011 based on headcount, which
resulted in an increase in facility costs of $0.1 million due to the expansion of our office space
as a result of recent acquisitions. The increase was also partially attributable to $0.1 million of
professional services fees related to our intellectual property and miscellaneous equipment expenses of $0.1
million as a result of the expansion of our hardware product offerings.
Other (Expense) Income, Net
Other expense, net for the three and nine months ended September 30, 2011 was primarily
comprised of foreign currency losses related to certain intercompany receivables denominated in
foreign currencies. Other income, net for the three and nine months ended September 30, 2010 was
primarily comprised of a nominal amount of interest income and a nominal amount of foreign currency
gains related to certain intercompany receivables denominated in foreign currencies. The
significant increase in losses arising from transactions denominated in foreign currencies for the
three and nine months ended September 30, 2011 as compared to the same periods in 2010 was due to
the significant increase of foreign denominated intercompany receivables held by us from one of our
Australian subsidiaries primarily as a result of the funding provided to complete the acquisition
of Energy Response and the strengthening of the United States dollar as compared to the Australian
dollar during the three months ended September 30, 2011. As of September 30, 2011, we had an
intercompany receivable from our Australian subsidiary that is denominated in Australian dollars and
not deemed to be of a “long-term investment” nature totaling $32.0 million ($32.6 million Australian). The
significant increase in losses arising from transactions denominated in foreign currencies is a
non-cash expense, and we did not implement any currency hedging transactions during the three months ended
September 30, 2011.
Interest Expense
Interest expense for the three and nine months ended September 30, 2011 includes interest on
our outstanding capital leases and letters of credit origination fees. The increase in interest
expense for the three and nine months ended September 30, 2011 as compared to the same periods in 2010
was due to the amortization of capitalized debt issuance costs associated with the 2011 credit
facility, which were significantly higher than the amortization of debt issuance costs associated
with the 2008 credit facility.
Income Taxes
The tax provision recorded for the three and nine months ended September 30, 2011 was $1.2
million and $2.0 million, respectively, and represented the following:
In accordance with ASC 740, Income Taxes, or ASC 740, each interim period is considered an
integral part of the annual period and tax expense is measured using an estimated annual effective
tax rate. An enterprise is required, at the end of each interim reporting period, to make its best
estimate of the annual effective tax rate for the full fiscal year and use that rate to provide for
income taxes on a current year-to-date basis. Generally, if an enterprise has an ordinary loss for
the year to date at the end of an interim period and anticipates ordinary income for the fiscal
year, the enterprise will record an interim period tax benefit based on applying the estimated
annual effective tax rate to the ordinary loss as long as the tax benefits are realized during the
year or recognizable as a deferred tax asset as of the end of the year. However, if an enterprise
is unable to make a reliable estimate of its annual effective tax rate, then actual effective tax
rate for the year-to-date may be the best estimate of the annual effective tax rate. We have
determined that we are currently unable to make a reliable estimate of our annual effective tax
rate as of September 30, 2011 due to unusual
43
Table of Contents
sensitivity to the rate as it relates to the current forecasted U.S. ordinary income (loss)
for fiscal 2011. As a result, we recorded a tax
provision for the three and nine months ended September 30, 2011 based on our actual effective tax
rate for the nine months ended September 30, 2011.
We reviewed all available evidence to evaluate the recovery of 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 September 30, 2011, due to the
uncertainty related to the ultimate use of our deferred income tax assets, we have provided a full
valuation allowance on all of our U.S. deferred tax assets.
For the three and nine months ended September 30, 2010, we recorded a provision for income
taxes of $3.8 million and $2.9 million, respectively.
Liquidity and Capital Resources
Overview
Since inception, we have generated significant cumulative losses. As of September 30, 2011, we
had an accumulated deficit of $53.1 million. As of September 30, 2011, our principal sources of
liquidity were cash and cash equivalents totaling $77.4 million, a decrease of $76.0 million from
the December 31, 2010 balance of $153.4 million. As of September 30, 2011, we were contingently
liable for $42.3 million in connection with outstanding letters of credit under the 2011 credit facility. As of September 30, 2011 and December 31, 2010, we had restricted cash
balances of $0.1 and $1.5 million, respectively, which relate to amounts that collateralize unused
outstanding letters of credit and cover financial assurance requirements in certain of the programs
in which we participate and certain other commitments. At September 30, 2011 and December 31,
2010, our excess cash was primarily invested in money market funds.
We believe our existing cash and cash equivalents at September 30, 2011, amounts available
under the 2011 credit facility and our anticipated net cash flows from operating activities will be
sufficient to meet our anticipated cash needs, including investing activities and the provision of
financial assurances in connection with our capacity bids in certain open market bidding programs,
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,
amounts available under the 2011 credit facility and our anticipated net 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 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.
Cash Flows
The following table summarizes
our cash flows for the nine months ended September 30, 2011 and
2010 (dollars in thousands):
44
Table of Contents
Cash Flows Provided by Operating Activities
Cash provided by operating activities primarily consists of net income adjusted for certain
non-cash items including depreciation and amortization, stock-based compensation expenses, asset
impairment charges, unrealized foreign currency translation gains and losses, and the effect of
changes in working capital and other activities.
Cash provided by operating activities for the nine months ended September 30, 2011 was
approximately $16.8
million and consisted of net income of $14.6 million and $32.1 million of non-cash items,
primarily consisting of depreciation and amortization, deferred taxes, stock-based compensation
charges, impairment charges of property and equipment, and unrealized foreign exchange losses,
offset by $30.0 million of net cash used in working capital and other
activities.
Cash provided by working capital and other activities consisted of an increase in accrued
capacity payments of $23.3 million relating primarily to the PJM demand response market, an
increase of $3.4 million in deferred revenue, an increase of $1.6 million in accrued payroll and
related expenses, and a decrease of $0.1 million in inventory. These amounts were offset by cash
used in working capital and other activities consisting of an increase of $30.1 million in unbilled
revenues relating to the PJM demand response market, an increase of $18.7 million in accounts
receivable due to the timing of cash receipts under the demand response programs in which we participate, a
decrease of $5.4 million in accounts payable and accrued expenses and other current liabilities due
to the timing of payments, an increase in other assets of $2.9 million, an increase in prepaid
expenses and other current assets of $1.1 million, and a decrease in other noncurrent liabilities
of 0.2 million.
Cash provided by operating activities for the nine months ended September 30, 2010 was $28.7
million and consisted of net income of $30.7 million and $26.2 million of non-cash items, primarily
consisting of depreciation and amortization, deferred taxes, stock-based compensation charges and
impairment of property and equipment. These amounts were offset by $28.2 million of net cash used
in working capital and other activities. Cash used in working capital and other activities
consisted of an increase of $73.8 million in unbilled revenues relating to the PJM demand response
market and an increase of $16.6 million in accounts receivable due to the timing of cash receipts
under the demand response programs in which we participate. These amounts were partially offset by
cash provided by working capital and other activities, which reflected an increase of $2.8 million
in accrued payroll and related expenses, an increase in other non-current liabilities of $1.9
million, an increase of $7.6 million in accounts payable and accrued expenses due to the
timing of payments, an increase in accrued capacity payments of $48.7 million, the majority
of which was related to the PJM demand response market, an increase of $0.2 in deferred revenue and
a decrease in prepaid expenses and other assets of $1.0 million.
Cash Flows Used in Investing Activities
Cash used in investing activities was $94.1 million for the nine months ended September 30,
2011. During the nine months ended September 30, 2011, we acquired Global Energy for a purchase
price of $26.7 million, of which $19.9 million was paid in cash, M2M for a purchase price of $28.6 million, of which $17.5 million was paid in cash, DMT for a purchase price of $5.2 million, of which $3.9 million was paid in cash, and
Energy Response for a purchase price of $30.1 million, of which $27.3
million was paid in cash. The net cash acquired from these acquisitions was $1.1 million.
Additionally, our cash investments included the cash portion of the acquisition contingent
consideration for Cogent Energy, Inc., or Cogent, of $1.5 million. Our other principal cash
investments during the nine months ended September 30, 2011 related to capitalized internal use
software costs used to build out and expand our energy management applications and services and
purchases of property and equipment. During the nine months ended September 30, 2011, we also
incurred $15.2 million in capital expenditures primarily related to the purchase of office
equipment and demand response equipment and other miscellaneous expenditures. In addition, during
the nine months ended September 30, 2011, our deposits increased by $9.4 million primarily due to
financial assurance requirements related to demand response programs in Australia.
Cash used in investing activities was $10.5 million for the nine months ended September 30,
2010. Our principal cash investments during the nine months ended September 30, 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
nine months ended September 30, 2010, we acquired SmallFoot LLC and ZOX, LLC 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 South River
Consulting, LLC of $0.9 million. We had a decrease in restricted cash and deposits of $6.7 million
primarily as a result of demand response event performance in July 2010 under a certain open market
program in which we participate, resulting in our restricted cash becoming unrestricted in July
2010. During the nine months ended September 30, 2010, we also incurred $15.3 million in capital
expenditures primarily related to the purchase of office equipment and demand response equipment
and other miscellaneous expenditures.
45
Table of Contents
Cash Flows Provided by Financing Activities
Cash provided by financing activities was $1.9 million and $3.5 million for the nine months
ended September 30, 2011 and 2010, respectively, and consisted primarily of proceeds that we
received from exercises of options to purchase shares of our common stock during the nine months
ended September 30, 2011 and 2010.
Credit Facility Borrowings
In April 2011, we and one of our subsidiaries entered into the 2011 credit facility. Subject
to continued covenant compliance, the 2011 credit facility provides for a two-year revolving line of
credit in the aggregate amount of $75.0 million, the full amount of which may be available for
issuances of letters of credit and up to $5.0 million of which may be available for swing line
loans. The revolving line of credit is subject to increase from time to time up to an aggregate
amount of $100.0 million with additional commitments from the lenders or new commitments from
financial institutions acceptable to SVB. The interest on revolving loans under the 2011 credit
facility will accrue, at our election, at either (i) the Eurodollar Rate with respect to the
relevant interest period plus 2.00% or (ii) the ABR (defined as the highest of (x) the “prime rate”
as quoted in the Wall Street Journal, (y) the Federal Funds Effective Rate plus 0.50% and (z) the
Eurodollar Rate for a one-month interest period plus 1.00%) plus 1.00%. In connection with the
issuance or renewal of letters of credit for our account, we are charged a letter of credit fee of
2.125% pursuant to the 2011 credit facility. We expense the interest and letter of credit fees, as
applicable, in the period incurred. The 2011 credit facility terminates and all amounts outstanding
thereunder are due and payable in full on April 15, 2013. As of September 30, 2011, we were in
compliance with all of our covenants under the 2011 credit facility, including all financial
covenants. At September 30, 2011, we had no borrowings and letters of credit totaling $42.3
million outstanding under the 2011 credit facility. As of September 30, 2011, we had $32.7 million
available under the 2011 credit facility for future borrowings or issuance of additional letters of
credit.
The 2011 credit facility contains customary terms and conditions for credit facilities of this
type, including restrictions on our ability and the ability of our subsidiaries to incur additional
indebtedness, create liens, enter into transactions with affiliates, transfer assets, pay dividends
or make distributions on, or repurchase our common stock, consolidate or merge with other entities,
or suffer a change in control. In addition, we are required to meet certain monthly and quarterly
financial covenants customary with this type of credit facility. Our monthly financial covenants
include a minimum specified ratio of current assets to current liabilities. Our quarterly
financial covenants include achievement of minimum earnings levels, which is based on earnings
before depreciation and amortization expense, interest expense, provisions for cash-based income
taxes, share-based compensation expense, rent expense and certain other non-cash charges over a
rolling twelve month period and maintaining a minimum specified charge coverage ratio, which is
based on the ratio of earnings calculation from the minimum earnings covenants less
capital expenditures compared to fixed charges, including depreciation expense, rent expense, and
income taxes paid.
The 2011 credit facility contains customary events of default, including for payment defaults,
breaches of representations, breaches of affirmative or negative covenants, cross defaults to other
material indebtedness, bankruptcy and failure to discharge certain judgments. If a default occurs
and is not cured within any applicable cure period or is not waived, the lenders may accelerate our
obligations under the 2011 credit facility. The 2011 credit facility replaces the 2008 credit
facility, which was in place as of March 31, 2011. If we are determined to be in default under the 2011 credit facility, then any
amounts outstanding would become immediately due and payable and we
would be required to collateralize with cash any outstanding letters of credit up to 105% of the
amounts outstanding.
On April 15, 2011, we and one of our subsidiaries entered into a guarantee and collateral
agreement with SVB for the benefit of the lenders under the 2011 credit facility. The guarantee and
collateral agreement provides that the obligations under the 2011 credit facility are secured by
all of our domestic assets and the domestic assets of several of our subsidiaries, excluding our foreign subsidiaries.
We incurred financing costs of $0.5 million in connection with the 2011 credit facility, which
were deferred and are being amortized as interest expense over the life of the 2011 credit
facility, which matures on April 15, 2013.
In April 2011, we were required to provide financial assurance in connection with our capacity
bid in a certain open market bidding program. We provided this financial assurance utilizing
approximately $56.0 million of our available cash and a $39.0 million letter of credit
issued under the 2011 credit facility. In May 2011, based on the capacity that we cleared in this
open market bidding program and the required post-auction financial assurance requirements, we
recovered all $56.0 million of our available cash that we had provided as financial assurance
and were able to reduce the $39.0 million letter of credit to $13.5 million.
46
Table of Contents
In June 2011, we and one of our subsidiaries entered into an amendment to the 2011 credit
facility, which modified certain of our covenant requirements.
Contingent Earn-Out Payments
In connection with our acquisition of Energy Response, we may be obligated to pay additional
contingent purchase price consideration related to an earn-out
payment of $10.7 million, or $10.0
million Australian. The earn-out payment, if any, will be based on
the development of a demand
response reserve capacity market in the National Electric Market in Australia by December 31, 2013
that meets certain market size and price per megawatt conditions. This milestone needs to be
achieved in order for the earn-out payment to occur, and there will be no partial payment if the
milestone is not fully achieved. We determined that the initial fair
value of the earn-out payment as of
the acquisition date was $0.3 million. Any changes in fair value will be recorded in our
consolidated statements of income. We recorded our estimate of the fair value of the
contingent consideration based on the evaluation of the likelihood of the achievement of the
contractual conditions that would result in the payment of the contingent consideration and
weighted probability assumptions of these outcomes. This fair value measurement was based on
significant inputs not observable in the market and, therefore, represented a Level 3 measurement as
defined in ASC 820, Fair Value Measurements and Disclosures. As of September 30, 2011, there were
no changes in the probability of payment of the earn-out payment.
Since the liability associated with the earn-out payment has been
discounted, as the time period to payment shortens, the liability
will increase. The change in
fair value resulting from this liability was recorded in general and administrative expenses in the accompanying unaudited
condensed consolidated statements of income. During the three and nine months ended September
30, 2011, we recorded a charge of $23,000 in general and
administrative expenses in the accompanying unaudited condensed
consolidated statements of income. At September 30, 2011, the
liability associated with the earn-out payment was recorded at
$0.3 million after adjusting for changes in exchange rates.
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 we paid the earn-out payment in January 2011.
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 totaled
$15.2 million and $15.3 million during the nine months ended September 30, 2011 and 2010,
respectively. As we continue to grow, we expect our capital expenditures for 2011 to increase as
compared to 2010.
Contractual Obligations
As of September 30, 2011, the contractual obligations disclosure contained in our Annual
Report on Form 10-K for the fiscal year ended December 31,
2010, or our 2010 Form 10-K, which we filed with the SEC on
March 1, 2011, has not materially changed.
Off-Balance Sheet Arrangements
As of September 30, 2011, 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 September 30, 2011, we had outstanding
letters of credit totaling $42.3 million. For information on these commitments and contingent
obligations, see “Liquidity and Capital Resources — Credit Facility Borrowings” above and Note 8
to our unaudited condensed consolidated financial statements contained herein.
Critical Accounting Policies and Use of Estimates
The discussion and analysis of our financial condition and results of operations are based
upon our interim unaudited condensed 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
47
Table of Contents
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.
The critical accounting estimates used in the preparation of our financial statements that we
believe affect our more significant judgments and estimates used in the preparation of our interim
condensed consolidated financial statements presented in this Quarterly Report on Form 10-Q are
described in “Management’s Discussion and Analysis of Financial Condition and Results of
Operations” and in the notes to the consolidated financial
statements included in our 2010 Form 10-K. Except as disclosed herein, there have been no material changes to our critical accounting policies
or estimates during the three and nine months ended September 30, 2011.
Revenue Recognition
We
recognize revenues in accordance with ASC 605, Revenue
Recognition, or ASC 605. In all of our
arrangements, we do not recognize any revenues until we can determine that 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:
We enter into utility contracts and open market
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
electric power 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. Based on the evaluation of the factors in
ASC 605-45-45, including the fact that we are the primary obligor and bear both the performance and
credit risk related to our arrangements with electric power grid operators or utilities, we have
determined that we are the principal in our arrangements with electric power grid operators or
utilities. Therefore, we record demand response revenues gross of the amounts billed to the
electric power grid operators or utilities and record the amounts paid to C&I customers as cost of
revenues.
48
Table of Contents
In one of the open market programs in which we participate, the program year operates on a
June to May basis and performance is measured based on the aggregate performance during the months
of June through September. As a result, fees received for the month of June could potentially be
subject to adjustment or refund based on performance during the months of July through September.
We concluded that we could reliably estimate the amount of fees potentially subject to adjustment
or refund and recorded a reserve for this amount in the month of June. As of June 30, 2011, we
recorded an estimated reserve of $9.3 million related to potential subsequent performance
adjustments. The fees under this program were fixed as of September 30, 2011 and, based on final
performance during the three months ended September 30, 2011, we recorded a reduction in the
estimated reserve totaling $3.7 million, which resulted in final performance adjustments of $5.6
million. For the three months ended September 30, 2011, the impact of this change in estimate on
income before income tax and net income was $3.7 million and $3.6 million, respectively, and the
impact of this change in estimate on diluted income per common share was $0.13. This
change in estimate had no impact on the nine months ended September 30, 2011 nor will it impact any
future periods. Our performance estimates which provided the basis for the estimated reserve as of
June 30, 2011 were reasonably consistent with the actual performance during demand response events and test events
during the three months ended September 30, 2011. The primary driver of the change in estimate
from June 30, 2011 to September 30, 2011 was due to the differences based on the number and type of
demand response events by which performance was measured, which was not within our control. We are in the process
of reevaluating our ability to reliably estimate the amount of fees potentially subject to
adjustment or refund for fiscal 2012 on a prospective basis
based on our consideration of our actual performance during the months of June 2011 through
September 2011, as well as additional guidance issued by the customer regarding its interpretation
of certain program rules that will impact performance calculations on a prospective basis. As
there are no revenues recognized related to this open market program during the fourth quarter of
our fiscal year, any change in the our evaluation of our ability to reliably estimate the amount of
fees potentially subject to adjustment or refund would have no impact on results of operations for
the three months ending December 31, 2011.
As a result of contractual amendments entered into during the three months ended March 31,
2011 and the three months ended September 30, 2011 to amend certain refund provisions included in
one of our contracts with a utility customer, we concluded that we could reliably estimate the fees
potentially subject to refund and, therefore, the fees under this arrangement were fixed or
determinable. As a result, during the three months ended March 31, 2011 and the three months ended
September 30, 2011, we recognized as revenues $3.0 million and $2.3 million, respectively, of fees
that had been previously deferred. As of September 30, 2011, there were no deferred revenues
related to this contractual arrangement.
Certain of the forward capacity programs in which we participate may be deemed derivative
contracts under ASC 815, Derivatives and Hedging, or ASC 815. We believe that we meet
the scope exception with respect to these forward capacity programs 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.
Energy event revenues are recognized when earned. Energy event revenue is deemed to be
substantive and represents the culmination of a separate earnings process and is recognized when
the energy event is initiated by the electric power grid operator or utility customer and we have
responded under the terms of the utility contract or open market program.
Under certain of our arrangements, in particular those arrangements entered into by our wholly-owned
subsidiary, M2M, we sell equipment to the C&I customer that is utilized to provide the
ongoing services that we deliver. Currently, this equipment has been determined to not have
stand-alone value. As a result, we defer the fees associated with the equipment and we
begin recognizing those fees ratably over the expected C&I customer relationship period,
which is generally 3 years, once the C&I customer is receiving the ongoing services from us. In
addition, we capitalize the associated direct and incremental costs, which primarily
represent the equipment and third-party installation costs, and recognize such costs over the
expected C&I customer relationship period.
In September 2009, the Financial Accounting Standards Board, or 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, which is the revenue recognition guidance for multiple-element arrangements. ASU 2009-13
provides for three significant changes to the existing multiple element revenue recognition
guidance as follows:
49
Table of Contents
As
required, we adopted ASU 2009-13 at the beginning of the first quarter of fiscal 2011 on a
prospective basis for transactions originating or materially modified on or after January 1, 2011.
ASU 2009-13 generally does not change the units of accounting for our revenue transactions. The
impact on adopting ASU 2009-13 was not material to our financial statements during the nine months
ended September 30, 2011, and if they were applied in the same
manner to the fiscal year ended December 31, 2010 would not have
had a material impact on revenue for the nine months ended September 30, 2010. We do not expect the
adoption of ASU 2009-13 to have a significant impact on the timing and pattern of revenue
recognition in the future due to the limited number of multiple element arrangements. The key
impact that we expect the adoption of ASU 2009-13 to have relates to certain EfficiencySMART
service arrangements with C&I customers who also provide curtailment of capacity as part of our
demand response arrangements. Historically, we had recorded the fees recognized under these
arrangements as a reduction of cost of revenues because evidence of fair value did not exist for
persistent commissioning services due to the limited history of selling separately and no available
TPE. As previously stated, the impact of ASU 2009-13 has not had and
is not expected to have a
material impact on our financial condition and results of operations.
We
typically determine the selling price of our services based on VSOE. Consistent with our
methodology under previous accounting guidance, we determine VSOE based on our normal pricing and
discounting practices for the specific service when sold on a stand-alone basis. In determining
VSOE, our policy is to require a substantial majority of selling prices for a product or service to
be within a reasonably narrow range. We also consider the class of customer, method of
distribution, and the geographies into which our products and services are sold into when
determining VSOE. We typically have had VSOE for our products and services.
In certain circumstances, we are not able to establish VSOE for all deliverables in a multiple
element arrangement. This may be due to the infrequent occurrence of stand-alone sales for an
element, a limited sales history for new services or pricing within a broader range than
permissible by our policy to establish VSOE. In those circumstances, we proceed to the alternative
levels in the hierarchy of determining selling price. TPE of selling price is established by
evaluating largely similar and interchangeable competitor products or services in stand-alone sales
to similarly situated customers. We are typically not able to determine TPE and we have not used
this measure since we are unable to reliably verify stand-alone prices of competitive solutions.
ESP is established in those instances where neither VSOE nor TPE are available, considering
internal factors such as margin objectives, pricing practices and controls, customer segment
pricing strategies and the product life cycle. Consideration is also given to market conditions
such as competitor pricing strategies information gathered from experience in customer
negotiations, market research and information, recent technological trends, competitive landscape
and geographies. Use of ESP is limited to a very small portion of our services, principally certain
EfficiencySMART services.
Recent Accounting Pronouncements
Business Combinations
In December 2010, the FASB issued Accounting Standards Update No. 2010-29, Business
Combinations — Disclosure of Supplementary Pro Forma Information
for Business Combinations, or ASU
2010-29. ASU 2010-29 requires a public entity to disclose revenue and earnings of the combined
entity as though the business combination that occurred during the current year had occurred as of
the beginning of the prior year. It also requires a description of the nature and amount of
material, nonrecurring adjustments directly attributable to the business combination included in
the reported revenue and earnings. The new disclosure was effective
for the first quarter of fiscal
2011. The adoption of ASU 2010-29 requires additional disclosure in the event of a material
business combination but did not have a material impact on our financial condition and results of
operations during the three and nine months ended September 30, 2011. As a result of the
acquisition of Energy Response in July 2011, we were required to meet certain disclosure
requirements and provide pro-forma financial information.
Intangibles — Goodwill and Other
In
December 2010, the FASB issued ASU 2010-28, Intangibles-
Goodwill and Other, or ASU 2010-28.
ASU 2010-28 modifies Step 1 of the goodwill impairment test for reporting units with zero or
negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of
the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In
determining whether it is more likely than not that a goodwill impairment exists, an entity should
consider whether there are any adverse qualitative factors indicating that an impairment may exist.
ASU 2010-28 is effective for fiscal years that begin after
50
Table of Contents
December 15, 2010, which is
fiscal 2011 for us. The adoption of ASU 2010-28 did not have a
material impact on our financial condition
or results of operations.
ASC 350, Intangibles —
Goodwill and Other, or ASU 350 (formerly the FASB Statement of
Financial Accounting Standards No. 142, Goodwill and Other
Intangible Assets), has a two-step
impairment test that requires companies to assess goodwill for impairment by quantitatively
comparing the fair value of a reporting unit with its carrying amount, including goodwill (Step 1).
If the reporting unit’s fair value is less than its carrying amount, Step 2 of the goodwill
impairment test must be performed to measure the amount of the goodwill impairment, if any.
In September 2011, the FASB issued ASU 2011-08, Intangibles—Goodwill and Other (Topic 350):
Testing Goodwill for Impairment, or ASU 2011-08, which gives companies the option to first perform a qualitative
assessment to determine whether it is more likely than not that the
fair value of a reporting unit is less than its carrying amount. If a company concludes that this
is the case, it must perform the two-step test. Otherwise, a company can forgo the two-step test.
ASU 2011-08 is effective for fiscal years that begin after December 15, 2011, which is fiscal 2012
for us; however, early adoption is permitted. We are currently evaluating the impact of ASU 2011-08, including
whether we will early adopt. We do not expect the adoption of ASU 2011-08 to have a material
impact on our financial condition or results of operations.
Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and
IFRS
In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement
and Disclosure Requirements in U.S. GAAP and IFRS, or ASU 2011-04, which amends FASB’s accounting guidance related to
fair value measurements in order to more closely align its disclosure requirements with those in
International Financial Reporting Standards. ASU 2011-04 clarifies the application of existing
fair value measurement and disclosure requirements and also changes certain principles or
requirements for measuring fair value or for disclosing information about fair value measurements.
ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The
adoption of ASU 2011-04 is not expected to have a material effect on
our financial condition or
results of operations.
Presentation of Comprehensive Income
In June 2011,
the FASB issued ASU 2011-05, Presentation of Comprehensive Income,
or ASU 2011-05, which
represents new accounting guidance related to the presentation of other comprehensive income (OCI).
ASU 2011-05 eliminates the option to present components of OCI as part of the statement of
changes in shareholders’ equity, which is the option that we currently use to present OCI. ASU 2011-05
allows for a one-statement or two-statement approach, outlined as follows:
ASU 2011-05 also requires an entity to present on the face of the financial statements any
reclassification adjustments for items that are reclassified from OCI to net income. ASU 2011-05
is effective for interim and annual periods beginning after December 15, 2011. The adoption of ASU 2011-05
will not have an effect on our financial condition or results of operations, but will only
impact how certain information related to OCI is presented in our consolidated financial
statements.
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, non-GAAP net
income 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 is GAAP net income; the GAAP
measure most comparable to non-GAAP net income per share is GAAP net income per share; the GAAP
measure most comparable to adjusted EBITDA is GAAP net income; 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.
51
Table of Contents
Use and Economic Substance of Non-GAAP Financial Measures Used by EnerNOC
Management uses these non-GAAP measures when evaluating our operating performance and for
internal planning and forecasting purposes. Management believes that such measures help indicate
underlying trends in our business, are important in comparing current results with prior period
results, and are useful to investors and financial analysts in assessing our operating performance.
For example, management considers non-GAAP net income (loss) to be an important indicator of the
overall performance because it eliminates the effects of events that are either not part of our
core operations or are non-cash compensation expenses. In addition, management considers adjusted
EBITDA to be an important indicator of our operational strength and performance of our business and
a good measure of our historical operating trend. Moreover, management considers free cash flow to
be an indicator of our operating trend and performance of our business.
The following is an explanation of the non-GAAP measures that we utilize, including the
adjustments that management excluded as part of the non-GAAP measures for the three and nine months
ended September 30, 2011 and 2010, respectively, as well as reasons for excluding these individual
items:
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.
Non-GAAP Net Income and Non-GAAP Net Income per Share
Net income for the three months ended September 30, 2011 was $46.9 million, or $1.83 per basic
share and $1.77 per diluted share, compared to net income of $43.9 million, or $1.76 per basic
share and $1.67 per diluted share, for the three months ended September 30, 2010. Net income for
the nine months ended September 30, 2011 was $14.6 million, or $0.57 per basic and $0.55 per
diluted share, compared to net income of $30.7 million, or $1.25 per basic share and $1.18 per
diluted share, for the nine months ended September 30, 2010. Excluding stock-based compensation
charges and amortization of expenses related to acquisition-related assets, net of related tax
effects, non-GAAP net income for the three months ended September 30, 2011 was $52.1, or $2.03 per
basic share and $1.96 per diluted share, compared to a non-GAAP net income of $47.6 million, or
$1.91 per basic share and $1.81 per diluted share, for the three months ended September 30, 2010.
Excluding stock-based compensation charges and amortization of expenses related to
acquisition-related assets, net of related tax effects, non-GAAP net income for the nine months
ended September 30, 2011 was $29.7, or $1.16 per basic share and $1.12 per diluted share, compared to a
non-GAAP net income of $42.4 million, or $1.72 per basic share and $1.63 per diluted share, for the
nine months ended September 30, 2010. The reconciliation of non-GAAP net income to GAAP net income
is set forth below:
52
Table of Contents
53
Table of Contents
Adjusted EBITDA
Adjusted EBITDA was $60.7 million and $55.9 million for the three months ended September 30,
2011 and 2010, respectively. Adjusted EBITDA was $46.9 million and $57.7 million for the nine
months ended September 30, 2011 and 2010, respectively.
The reconciliation of adjusted EBITDA to net income is set forth below:
54
Table of Contents
Free Cash Flow
Cash flows provided by operating activities was $8.7 million and $16.8 million for the
three and nine months ended September 30, 2011, respectively. Cash flows provided by operating
activities was $17.7 million and $28.7 million for the three and nine months ended September 30,
2010, respectively. Although our net income for the three months
ended September 30, 2011 was greater than our net
income for the comparable period of 2010, our cash flows provided by operating activities for the three months ended
September 30, 2011 were lower than the comparable period of 2010. The key factors that resulted in lower cash flows
provided by operating activities for the three months ended September
30, 2011 as compared to the same period in 2010
were as follows: approximately $6.0 million of our consolidated revenues and consolidated net income for the three months ended
September 30, 2011 resulted from a change in an estimated reserve and recognition of deferred revenues which had been
paid in a prior period; certain payments received in advance of performance of services during the three months ended
September 30, 2010 that did not occur during the comparable period of
2011; and the timing of cash receipts related
accounts receivable. We expect to continue to collect our accounts receivables in the normal course and have not
identified any material collectability issues with respect to accounts receivable as of September 30, 2011. We
incurred positive free cash flows of $5.7 million and $14.4 million for the
three months ended September 30, 2011 and 2010, respectively. We incurred positive free cash flows
of $1.6 million and $13.4 million for the nine months ended September 30, 2011 and 2010,
respectively. The reconciliation of free cash flow to cash flow from operating activities is set
forth below:
Except as disclosed herein, there have been no material changes to the interest rate risk
information and foreign exchange risk information disclosed in the “Quantitative and Qualitative
Disclosures About Market Risk” subsection of the section entitled “Management’s Discussion and
Analysis of Financial Condition and Results of Operations” in
our 2010 Form 10-K during the
three and nine months ended September 30, 2011.
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.
A substantial majority of our foreign expense and sales activities are transacted in
local currencies, including Australian dollars, British pounds, Canadian dollars and New Zealand
dollars. In addition, our foreign sales are denominated in local currencies. Fluctuations in the
foreign currency rates could affect our sales, cost of revenues and profit margins and could result
in exchange losses. In addition, currency devaluations can result in a loss if we maintain deposits
in a foreign currency. During the three and nine months ended September 30, 2011, less than 10% of
our sales were generated outside the United States.
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 for the year ending December 31, 2011. 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.
During the three and nine months ended September 30, 2011, we incurred foreign exchange losses
of $2.6 million and $2.8 million, respectively. Gains arising from transactions denominated in
foreign currencies were $13,000 for the three months ended September 30, 2010. Losses arising from
transactions denominated in foreign currencies were $17,000 for the nine months ended September 30,
2010. The significant increase in losses arising from transactions denominated in
foreign currencies for the three and nine months ended September 30, 2011 as compared to the same
periods of 2010 was due to the significant increase of foreign denominated intercompany receivables
held by us from one of our Australian subsidiaries primarily as a result of the funding provided to
complete the acquisition of Energy Response and the strengthening of
the U.S. dollar as
compared to the Australian dollar during the three months ended September 30, 2011. During the
three and nine months ended September 30, 2011 and 2010, there were no material realized losses
incurred related to transactions denominated in foreign currencies. As of September 30, 2011, we
had an intercompany receivable from our Australian subsidiary that is
denominated in Australian
dollars and not deemed to be of a “long-term investment” nature totaling $32.0 million, or $32.6
million Australian.
55
Table of Contents
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 other than the
impact on the unrealized gain (loss) on the intercompany receivable held by us from our Australian
subsidiary that is denominated in Australian dollars, for which a hypothetical 10% increase or
decrease in the foreign currency would result in an incremental $3.3 million gain or loss.
We currently do not have a program in place that is designed to mitigate our exposure to
changes in foreign currency exchange rates. We are evaluating certain potential programs, including
the use of derivative financial instruments to reduce our exposure to a reduction in U.S. dollar
value and the volatility of future cash flows caused by changes in currency exchange rates. The
utilization of forward foreign currency contracts would reduce, but would not eliminate, the impact
of currency exchange rate movements.
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 Quarterly Report on Form 10-Q, have
concluded that, based on such evaluation, our disclosure controls and procedures were effective to
ensure that information required to be disclosed by us in the reports that we file or submit under
the Exchange Act is recorded, processed, summarized and reported, within the time periods specified
in the SEC’s rules and forms, and is accumulated and communicated to our management, including our
principal executive and principal financial officers, or persons performing similar functions, as
appropriate to allow timely decisions regarding required disclosure.
Internal Control over Financial Reporting.
As a result of our recent acquisitions, we have begun to integrate certain business
processes and systems. Accordingly, certain changes have been made and will continue to be made to
our internal controls over financial reporting until such time as these integrations are complete.
There have been no other changes in our internal control over financial reporting that occurred
during the period covered by this report that have materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.
PART II — OTHER INFORMATION
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.
We operate in a rapidly changing environment that involves a number of risks that could
materially affect our business, financial condition or future results, some of which are beyond our
control. In addition to the other information set forth in this Quarterly Report on Form 10-Q, the
risks and uncertainties that we believe are most important for you to consider are discussed in
Part I — Item 1A under the heading “Risk Factors” in our 2010 Form 10-K.
During the three months ended September 30, 2011, there were no material changes to the risk
factors that were disclosed in Part I — Item 1A under the heading “Risk Factors” in our 2010 Form
10-K, other than as set forth below:
The
following risk factors replace and supersede the corresponding risk
factors set forth in our 2010 Form 10-K:
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. During the nine months ended September 30, 2011, revenues
generated from open market sales to PJM accounted for 58% of our total revenues. The modification
or termination of our sales relationship with PJM, or the modification or termination of any of
PJM’s open market programs in which we participate, could significantly reduce our future revenues
and profit margins and have a material adverse effect on our results of operations and financial
condition. For example, beginning in June 2012, PJM will discontinue 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 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. In March 2011, we filed for and were granted expedited declaratory relief with FERC, which
allowed us to continue to manage our portfolio of demand response capacity in PJM as we
had in the past and receive settlement in accordance with the then current PJM market rules
approved by FERC. However, PJM continued to take steps to modify the market rules according to the
PJM statement, including by filing proposed tariff changes with FERC. The FERC order was
subsequently issued on November 4, 2011. Although we believe that, based on the language contained
in the FERC order, our revenues and gross profits derived from the PJM market for fiscal 2011 will
not be impacted by the FERC order, our ability to manage our portfolio of demand response capacity
in the PJM market for future delivery years may be harmed by the FERC
order, which could
significantly reduce our future revenues and profit margins and which may have a material adverse
effect on our results of operations and financial condition. Furthermore, the attention of our
management and other personnel has been, and may continue to be, diverted as we evaluate and
respond to the FERC order, which may continue to have a negative impact on our sales efforts in,
and revenues and gross profits derived from the PJM region, as well as our other operating regions.
In addition, 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. During the nine months
ended September 30, 2011, revenues generated from open market sales to ISO-NE accounted for 11% of
our total revenues. The modification or termination of our sales relationship with ISO-NE, or the
modification or termination of any of ISO-NE’s open market programs in which we participate, could
significantly reduce our future revenues and profit margins and have a material adverse effect on
our results of operations and financial condition.
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 FERC order,
or to the extent PJM is otherwise successful at further 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.
The
following risk factor is added to the risk factors included in our 2010 Form 10-K:
An adverse change in the projected cash flows from our acquired businesses or the business climate
in which they operate, including the continuation of the current financial and economic turmoil,
could require us to incur an impairment charge, which would have an adverse impact on our operating
results.
We periodically review the carrying value of the goodwill and other long-lived assets
reflected in our financial statements to determine if any adverse conditions exist or a change in
circumstances has occurred that would indicate impairment of the value of
56
Table of Contents
these assets. Conditions that would indicate impairment and necessitate a revaluation of these
assets include, but are not limited to, a significant adverse change in the business climate or the
legal or regulatory environment within which we operate. If the carrying value of an asset is
determined to be impaired we will write-down the carrying value of the intangible asset to its fair
value in the period identified. We generally calculate fair value as the present value of estimated
future cash flows to be generated by the asset using a risk-adjusted discount rate. As of September
30, 2011, we had approximately $112.7 million of goodwill and definite-lived and indefinite-lived
intangible assets. We have experienced a decline in the price of our publicly-traded common stock
and related market capitalization such that our market capitalization has declined slightly below
the book value of our net assets. We evaluated this decline in our market capitalization and have
concluded that it was not an indicator of an impairment that existed as of September 30, 2011. We
will continue to monitor our market capitalization compared to the book value of our net assets. It
is possible that the continuation of the current global financial and economic turmoil could
negatively affect our anticipated cash flows, or the discount rate that is applied to valuing those
cash flows, which could impact our annual impairment test of goodwill that occurs in the fourth
quarter of our fiscal year. Any impairment test could result in a material impairment charge that
would have an adverse impact on our operating results.
(a) Unregistered Sales of Equity Securities
We offered, issued and/or sold the following unregistered securities during the three months
ended September 30, 2011: on July 1, 2011, in connection with our acquisition of Energy Response,
we issued 156,697 shares of our common stock.
The issuance of the securities described above was deemed to be exempt from registration under
the Securities Act in reliance on Section 4(2) of the Securities Act, including Regulation D and
Rule 506 promulgated thereunder, as transactions by an issuer not involving any public offering.
The recipients of these securities in such transaction represented their intention to acquire the
securities for investment only and not with a view to or for sale in connection with any
distribution thereof. Such recipients received written disclosures that the securities have not
been registered under the Securities Act and that any resale must be made pursuant to a
registration or an available exemption from such registration. All of these securities are deemed
restricted securities for the purposes of the Securities Act. The sales of these securities were
made without general solicitation or advertising.
(c) Issuer Purchases of Equity Securities
The following table provides information about our purchases of our common stock during the
three months ended September 30, 2011.
57
Table of Contents
58
Table of Contents
SIGNATURES
Pursuant to the requirements 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.
59
Table of Contents
Exhibit Index
60 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| |||||||
