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ENERNOC INC - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations.
(Edgar Glimpses Via Acquire Media NewsEdge) 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, 2011, as filed with the
Securities and Exchange Commission, or the SEC, on March 15, 2012 and as amended
on April 17, 2012, or our 2011 Form 10-K. 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 2011
Form 10-K. 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 energy management applications, services and
products for the smart grid, which include comprehensive demand response,
data-driven energy efficiency, energy price and risk management and enterprise
carbon management applications, services and products. Our energy management
applications, services and products 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 carbon
emissions.
We believe that we are the largest demand response service provider to C&I
customers. As of September 30, 2012, we managed approximately 8,500 megawatts,
or MW, of demand response capacity across a C&I customer base of approximately
5,800 accounts and approximately 13,500 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. We share these recurring payments with our C&I customers in
exchange for those C&I customers reducing their power consumption when called
upon.
In providing our demand response services, we match obligation, in the form of
MW that we agree to deliver to our utility and grid operator customers, with
supply, in the form of MW that we are able to curtail from the electric power
grid through our arrangements with C&I customers. We increase our ability to
curtail demand from the electric power grid by deploying a sales team to
contract with our C&I customers and by installing our equipment at these
customers' sites to connect them to our network. When we are called upon by our
utility or grid operator customers to deliver MW, we use our DemandSMART
application to dispatch this network to meet the demands of these utility and
grid operator customers. We occasionally reallocate and re-align our capacity
supply and obligation through open market bidding programs, supplemental demand
response programs, auctions or other similar capacity arrangements and bilateral
contracts to account for changes in supply and demand forecasts, as well as
changes in programs and market rules in order to achieve more favorable pricing
opportunities. We refer to the above activities as managing our portfolio of
demand response capacity.
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We build on our position as a leading demand response services provider by using
our NOC and energy management application platform to deliver a portfolio of
additional energy management applications, services and products to new and
existing C&I, electric power grid operator and utility customers. These
additional energy management applications, services and products include our
EfficiencySMART, SupplySMART, and CarbonSMART applications and services, and
certain wireless energy management products. 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. Our wireless
energy management products are designed to ensure that our C&I customers can
connect their equipment remotely and access meter data securely, and include
both cellular modems and an agricultural specific wireless technology solution
acquired as part of our acquisition of M2M Communications Corporation, or M2M,
in January 2011.
Since inception, our business has grown substantially. We began by providing
demand response services in one state in 2003 and have expanded to providing our
portfolio of energy management applications, services and products in several
regions throughout the United States, as well as internationally in Australia,
Canada, New Zealand and the United Kingdom.
Revenues and Expense Components
Revenues
We derive recurring revenues from the sale of our energy management
applications, services and products. 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 ten 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
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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,
2012 and December 31, 2011, there were no deferred incremental direct contract
acquisition costs. In addition, we defer incremental direct costs incurred
related to customer contracts where the associated revenues have been deferred
as long as the deferred incremental direct costs are deemed realizable. During
the three months ended September 30, 2012 and 2011, we deferred $0.7 million and
$1.1 million, respectively, of incremental direct costs. During the nine months
ended September 30, 2012 and 2011, we deferred $11.5 million and $5.2 million,
respectively, of incremental direct costs. The increase in the deferral of
incremental direct costs during the nine months ended September 30, 2012
compared to the same period in 2011 was primarily related to the deferral of the
costs associated with the payment obligations to our C&I customers in connection
with our participation in the PJM Interconnection, or PJM, open market demand
response program due to the change in our revenue recognition methodology in the
fiscal year ending December 31, 2012, or fiscal 2012. In addition, the increase
in the deferral of incremental costs during the nine months ended September 30,
2012 as compared to the same period in 2011 was also due to our participation in
the Western Australia demand response program, an open market program that we
did not participate in until the third quarter of the fiscal year ending
December 31, 2011, or fiscal 2011, pursuant to which the associated fees have
been deferred because they are not fixed or determinable until the end of the
applicable program period on September 30th of each year. During the nine months
ended September 30, 2012 and 2011, we expensed $8.9 million and $0.9 million,
respectively, of deferred incremental direct costs to cost of revenues. As of
September 30, 2012 there have been no material realizability issues related to
deferred incremental direct costs. During the three months ended September 30,
2012 and 2011, we capitalized $0.9 million and $1.9 million, respectively, of
production and generation equipment costs. During the nine months ended
September 30, 2012 and 2011, we capitalized $6.1 million and $8.5 million,
respectively, of production and generation equipment costs. We believe that the
above accounting treatments appropriately match expenses with the associated
revenue.
As of September 30, 2012, we had approximately 8,500 MW under management in our
demand response network, meaning that we had entered into definitive contracts
with our C&I customers representing approximately 8,500 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 determinable
amount of curtailable load 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 those MW again. We generally begin earning revenues
from our MW under management within approximately one to three months 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 actually
earn revenues from that MW. Certain other markets in which we currently
participate, such as the Western Australia market and ISO New England, Inc., or
ISO-NE, market, or may 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 program 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.
Based on recent changes to certain PJM program rules, we have concluded that we
no longer have the ability to reliably estimate the amount of fees potentially
subject to adjustment or refund until the performance period ends on
September 30th of each year. Therefore, commencing in fiscal 2012, all demand
response capacity revenues related to our participation in the PJM open market
program are being recognized at the end of the performance period, or during the
three months ended September 30th of each year. As a result of the fact that the
period during which we are required to perform (June through September) is
shorter than the period over which we receive payments under the program (June
through May), a portion of the revenues that have been earned will be recorded
and accrued as unbilled revenue. Revenues related to the current PJM open market
program year were recognized during the three months ended September 30, 2012,
and therefore we had $76.0 million in unbilled revenues from PJM at
September 30, 2012.
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In February 2012, the Federal Energy Regulatory Commission, or FERC, issued an
order substantially accepting a proposal by PJM regarding certain market rule
changes with respect to capacity compliance measurement and verification of
demand response resources in the PJM capacity market, which we refer to as the
PJM proposal. The FERC order resulted in the immediate implementation of the PJM
proposal. As a result, our future PJM revenues and profit margins may be reduced
and our future results of operations and financial condition may be negatively
impacted. These impacts may be offset by the effective management of our
portfolio of demand response capacity, including our future growth in MW under
management, the adjustment of our zonal capacity obligations through our
participation in PJM incremental auctions and bilateral contracts in the PJM
market.
Our revenues have historically been higher in the second and third fiscal
quarters of our fiscal year due to seasonality related to the demand response
market. As a result of the change in our ability to estimate performance in the
PJM open market program, all PJM revenues related to the current PJM program
year, which commenced on June 1, 2012, were recognized during the third quarter
of fiscal 2012 and represented 61% of our total revenues for the three months
ended September 30, 2012 as compared to 71% of our total revenues for the three
months ended September 30, 2011. No other individual electric power grid
operator or utility customer accounted for more than 10% of our total revenues
for either the three or nine months ended September 30, 2012.
Revenues generated from open market sales to ISO-NE accounted for 7% and 11% of
our total revenues for the three months ended September 30, 2011. Other than PJM
and ISO-NE, no individual electric power grid operators or utility customers
accounted for more than 10% of our total revenues for either the three or nine
months ended September 30, 2011.
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, and certain other wireless energy management
products. Revenues derived from these applications and services were $8.3
million and $7.3 million for the three months ended September 30, 2012 and 2011,
respectively, and $22.1 million and $19.6 million for the nine months ended
September 30, 2012 and 2011, respectively.
Cost of Revenues
Cost of revenues for our demand response services primarily consist 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 energy 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 during interim periods. Cost of revenues for our
EfficiencySMART, SupplySMART and CarbonSMART applications and services and
certain other wireless energy management products include our amortization of
capitalized internal-use software costs related to those applications, services
and products, 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, services and products, (b) the selling
price of our energy management applications, services and products, (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 energy management applications,
services and products, (f) our demand response event performance and (g) our
ability to open and enter new markets and regions and expand deeper into markets
we already serve. The effective management of our portfolio of demand response
capacity, including our outcomes in negotiating favorable contracts with
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our C&I customers, as well as with our electric power grid operator and utility
customers, our participation in capacity auctions and bilateral contracts, and
our demand response event performance, is the primary determinant 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
587 full-time employees at September 30, 2011 to 660 full-time employees at
September 30, 2012 primarily as a result of our overall growth and expansions
into new markets during this period. We expect to continue to hire employees to
support our growth for the foreseeable future. In addition, we incur significant
up-front costs associated with the expansion of the number of MW under our
management, which we expect to continue for the foreseeable future. We expect
our overall operating expenses to increase in absolute dollar terms for the
foreseeable future as we grow our MW under management, further increase our
headcount and expand the development of our energy management applications,
services and products. In addition, amortization expense from intangible assets
acquired in possible future acquisitions could potentially 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 an increase in selling and marketing
expenses in absolute dollar terms for the foreseeable future as we further
increase the number of sales professionals and, to a lesser extent, increase our
marketing activities.
General and Administrative
General and administrative expenses consist primarily of (a) salaries and
related personnel costs, including costs associated with share-based payment
awards and bonuses, related to our executive, finance, human resource,
information technology and operations organizations, (b) facilities expenses,
(c) accounting and legal professional fees, (d) depreciation and amortization
and (e) other related overhead. We expect general and administrative expenses to
continue to increase in absolute dollar terms for the foreseeable future as we
invest in infrastructure to support our continued growth.
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, services and products, and
enhancement of existing energy management applications, services and products,
(d) quality assurance and testing and (e) other related overhead. During the
three and nine months ended September 30, 2012, we capitalized software
development costs of $1.2 million and $3.5 million, respectively, and the amount
is included as software in property and equipment at September 30, 2012. 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. We
expect research and development expenses to increase in absolute dollar terms
for the foreseeable future as we develop new technologies and enhance our
existing technologies.
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 statements of income based on their fair
values as of the date of grant. During the nine months ended September 30, 2012,
in lieu of a portion of cash bonuses related to our 2012 and 2013 bonus plans,
we granted 1,023,010 shares of nonvested restricted stock to certain executives
and non-executive employees that contain performance-based vesting conditions.
These awards will vest in equal installments in 2013 and 2014 if the performance
conditions are achieved. If the employee who received the restricted stock
leaves the company for any reason prior to the vesting date, the shares of
restricted stock will be forfeited and returned to us. We did not make any
additional grants with performance-based vesting conditions during the three
months ended September 30, 2012. In addition, in December 2011, we granted
283,334 shares of nonvested restricted stock to certain non-executive
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employees that contained performance-based vesting conditions in lieu of a
portion of cash bonuses related to our 2012 and 2013 bonus plan. The performance
conditions associated with the December 2011 grants were modified during the
three months ended March 31, 2012. As a result of these grants of nonvested
restricted stock, we anticipate that, on a per employee basis, stock-based
compensation expense will increase with a corresponding decrease in cash
compensation expense.
For the three months ended September 30, 2012 and 2011, we recorded expenses of
approximately $3.3 million and $3.2 million, respectively, in connection with
share-based payment awards to employees and non-employees. For the nine months
ended September 30, 2012 and 2011, we recorded expenses of approximately $10.0
million and $10.5 million, respectively, in connection with share-based payment
awards to employees and non-employees. With respect to option grants through
September 30, 2012, a future expense of non-vested options of approximately $2.2
million is expected to be recognized over a weighted average period of 1.5
years. For non-vested restricted stock and restricted stock units subject to
service-based vesting conditions outstanding as of September 30, 2012, we had
$9.1 million of unrecognized stock-based compensation expense, which is expected
to be recognized over a weighted average period of 2.5 years. For non-vested
restricted stock subject to performance-based vesting conditions outstanding and
that were probable of vesting as of September 30, 2012, we had $5.3 million of
unrecognized stock-based compensation expense, which is expected to be
recognized over a weighted average period of 1.4 years. For non-vested
restricted stock subject to outstanding performance-based vesting conditions
that were not probable of vesting as of September 30, 2012, we had $1.1 million
of unrecognized stock-based compensation expense. If and when any additional
portion of our outstanding equity awards is deemed probable to vest, we will
reflect the effect of the change in estimate in the period of change by
recording a cumulative catch-up adjustment to retroactively apply the new
estimate.
Although the number of share-based awards has increased significantly during the
nine months ended September 30, 2012 as compared to the same period in 2011 due
to stock-based compensation being issued in lieu of cash compensation, the
overall amount of our stock-based compensation expense has decreased as a result
of the lower fair value of these awards compared to awards granted in prior
periods due to our lower stock price compared to the same period in 2011.
Accordingly, the weighted average grant date fair value of share-based payments
issued during the nine months ended September 30, 2012 was $7.85 per share as
compared to $18.25 per share for the same period in 2011.
Other Income and Expense, Net
Other income and expense consist primarily of gains or losses on transactions
designated in currencies other than our or our subsidiaries' functional
currency, interest income earned on cash balances, and other non-operating
income and expense. We historically have invested our cash in money market
funds, treasury funds, commercial paper, and municipal bonds.
Interest Expense
Interest expense primarily consists of fees associated with our $50.0 million
senior secured revolving credit facility pursuant to an amended and restated
credit agreement with Silicon Valley Bank, or SVB, which we refer to as the 2012
credit facility. Interest expense also consists of fees associated with issuing
letters of credit and other financial assurances.
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