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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 June 30, 2012, we managed over 8,300 megawatts, or MW, of
demand response capacity across a C&I customer base of approximately 5,600
accounts and approximately 13,000 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.
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 occasionally reallocate our
obligation through open market bidding programs, supplemental demand response
programs, auctions or other similar capacity arrangements, open program
registrations and bilateral contracts to account for changes in supply and
demand forecasts in order to achieve more favorable pricing opportunities. We
increase our ability to curtail demand from the electric power grid by deploying
a sales team to contract with our C&I customers and by installing our equipment
at these customers' sites to connect them to our network. When we are called
upon by our 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 refer to the above activities as
managing our portfolio of demand response capacity.
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
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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.
Significant Recent Developments
On June 28, 2012, we notified our landlord that we intend to terminate the
current lease for our principal executive offices at 75-101 Federal Street,
Boston, Massachusetts, which we refer to as the Current Lease, effective as of
July 1, 2013 pursuant to a termination option contained in the Current Lease. In
connection with this termination, we are obligated to pay a termination fee of
approximately $1.1 million, payable in two equal installments. We paid the
initial installment on June 28, 2012 and the remaining installment will be paid
to the landlord on or before July 1, 2013.
On July 5, 2012, we entered into a new lease for our principal executive offices
at One Marina Park Drive, Floors 4-6, Boston, Massachusetts, which we refer to
as the New Lease. Pursuant to the New Lease, we have agreed to lease
approximately 82,000 square feet of office space and expect to move into the
premises on or about May 1, 2013. The term of the New Lease began on July 5,
2012 and will continue until July 31, 2020, however the obligation to pay rent
will not commence until August 1, 2013. The average monthly rent over the
initial term of the New Lease is $0.3 million, exclusive of operating expenses.
Pursuant to the New Lease, we have a right of first offer, subject to the rights
of existing tenants in the building, whereby we may lease certain additional
space in the building during the term of the New Lease and the right to extend
the New Lease for one period of five years upon the expiration of the initial
term. Under the terms of the New Lease, we are required to provide a security
deposit in the form of an unconditional and irrevocable letter of credit of
approximately $1.8 million, subject to reduction commencing August 1, 2015, and
will be required to pay our pro rata share of any building operating expenses
and real estate taxes over and above a base year, as well as certain utility
costs. Additionally, we also have certain rights to sublease the New Lease.
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.
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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 June 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 June 30, 2012 and 2011, we deferred $8.0 million and $2.1
million, respectively, of incremental direct costs. During the six months ended
June 30, 2012 and 2011, we deferred $10.7 million and $4.1 million,
respectively, of incremental direct costs. The increase in the deferral of
incremental direct costs during the six months ended June 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 in the fiscal year
ending December 31, 2012, or fiscal 2012. In addition, the increase in the
deferral of incremental costs during the six months ended June 30, 2012 as
compared to the same period in 2011 was also due to our participation in the
Western Australia demand response program, a program which we did not
participate in during the six months ended June 30, 2011 where the associated
fees have been deferred because they are not fixed or determinable until the end
of the applicable program periods on September 30th. During the three months
ended June 30, 2012 and 2011, we capitalized $2.7 million and $4.7 million,
respectively, of production and generation equipment costs. During the six
months ended June 30, 2012 and 2011, we capitalized $5.2 million and $6.6
million, respectively, of production and generation equipment costs. We believe
that this accounting treatment appropriately matches expenses with the
associated revenue.
As of June 30, 2012, we had over 8,300 MW under management in our demand
response network, meaning that we had entered into definitive contracts with our
C&I customers representing over 8,300 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 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 actually 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 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
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September. Based on the 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 the applicable 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. No revenues related to
the current PJM open market program year were recognized during the three months
ended June 30, 2012, and therefore we had no unbilled revenues from PJM at
June 30, 2012. In accordance with our policy to capitalize direct and
incremental costs associated with deferred revenues to the extent that such
costs are realizable, we deferred the associated cost of our payments to C&I
customers for the month of June totaling $3.7 million and will expense such
deferred costs when the associated deferred revenues are recognized. We have
evaluated the direct and incremental costs for recoverability prior to
capitalization and determined that the capitalized costs are realizable.
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 the 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 PJM's proposed market
rule changes regarding capacity compliance measurement and verification. As a
result, our future PJM revenues and profit margins will be significantly reduced
and our future results of operations and financial condition will be negatively
impacted. These impacts may be offset by our future growth in MW under
management in the PJM market and effective management of our portfolio of demand
response capacity.
Our revenues have historically been higher in our 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, our revenues for the second quarter of fiscal 2012 are
significantly lower than our revenues for the second quarter of the fiscal year
ended December 31, 2011, or fiscal 2011, as all PJM revenues related to the
current PJM program year which commenced on June 1, 2012 will be recognized
during the third quarter of fiscal 2012. We recognized no revenue for the three
or six months ended June 30, 2012 from open market sales to PJM, as compared to
52% and 35%, respectively, of our total revenues for the three and six months
ended June 30, 2011.
Revenues generated from open market sales to ISO-NE accounted for 20% and 14%,
respectively, of our total revenues for the three months ended June 30, 2012 and
2011 and 22% and 22%, respectively, of our total revenues for the six months
ended June 30, 2012 and 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 six months ended June 30, 2012.
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 $7.1
million and $6.3 million, respectively, for the three months ended June 30, 2012
and 2011, and $13.8 million and $12.3 million, respectively, for the six months
ended June 30, 2012 and 2011.
Cost of Revenues
Cost of revenues for our demand response services primarily consists 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.
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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. 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
554 full-time employees at June 30, 2011 to 625 full-time employees at June 30,
2012 due to our acquisition of Energy Response Holdings Pty Ltd, or Energy
Response, in July 2011 and the overall growth of the company 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 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 six months ended June 30, 2012, we capitalized software development
costs of $1.6 million and $2.3 million, respectively, and the amount is included
as software in property and equipment at June 30, 2012. During the three and six
months ended June 30, 2011, we capitalized software development costs of $2.3
million and $3.1 million, respectively, and the amount is included as software
in property and equipment at June 30, 2011. We expect research and development
expenses to increase in absolute dollar terms for the foreseeable future as we
develop new technologies.
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Stock-Based Compensation
We account for stock-based compensation in accordance with Accounting Standards
Codification, or ASC, 718, Stock Compensation. As such, all share-based payments
to employees, including grants of stock options, restricted stock and restricted
stock units, are recognized in the statement of operations based on their fair
values as of the date of grant. During the six months ended June 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 prior to the vesting date for any reason, the shares of
restricted stock will be forfeited and returned to us. In addition, in December
2011, we granted 283,334 shares of nonvested restricted stock to certain
non-executive 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 grant 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 June 30, 2012 and 2011, we recorded expenses of
approximately $3.3 million and $3.8 million, respectively, in connection with
share-based payment awards to employees and non-employees. For the six months
ended June 30, 2012 and 2011, we recorded expenses of approximately $6.7 million
and $7.3 million, respectively, in connection with share-based payment awards to
employees and non-employees. With respect to option grants through June 30,
2012, a future expense of non-vested options of approximately $2.6 million is
expected to be recognized over a weighted average period of 1.7 years. For
non-vested restricted stock and restricted stock units subject to service-based
vesting conditions outstanding as of June 30, 2012, we had $8.9 million of
unrecognized stock-based compensation expense, which is expected to be
recognized over a weighted average period of 2.3 years. For non-vested
restricted stock subject to performance-based vesting conditions outstanding and
that were probable of vesting as of June 30, 2012, we had $6.8 million of
unrecognized stock-based compensation expense, which is expected to be
recognized over a weighted average period of 1.5 years. For non-vested
restricted stock subject to outstanding performance-based vesting conditions
that were not probable of vesting as of June 30, 2012, we had $1.5 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.
Other Income and Expense, Net
Other income and expense consist primarily of gain or loss 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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