EnerNOC, Inc.
ENERNOC INC (Form: 10-Q, Received: 05/08/2015 06:15:01)
Table of Contents

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
 
FORM 10-Q
 
 
(Mark One)
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2015
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                      
Commission File Number: 001-33471
 
EnerNOC, Inc.
(Exact Name of Registrant as Specified in Its Charter)
 
Delaware
87-0698303
(State or Other Jurisdiction of
Incorporation or Organization)
(IRS Employer
Identification No.)
One Marina Park Drive
Suite 400
Boston, Massachusetts
02210
(Address of Principal Executive Offices)
(Zip Code)
(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   ý     No   ¨
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   ý     No   ¨
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):
Large accelerated filer
¨
Accelerated filer
ý
Non-accelerated filer
¨  (Do not check if a smaller reporting company)
Smaller reporting company
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes   ¨     No   ý
There were 30,382,845 shares of the registrant’s common stock, $0.001 par value per share, outstanding as of May 4, 2015 .
 


Table of Contents

EnerNOC, Inc.
Index to Form 10-Q
 
 
 
Page
 
Item 1.
 
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
Item 1.
Item 1A
Item 2.
Item 6.
 


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EnerNOC, Inc.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except par value and share data)
 
March 31,
2015
 
December 31, 2014
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
152,428

 
$
254,351

Restricted cash
344

 
813

Trade accounts receivable, net of allowance for doubtful accounts of $848 and $679 at March 31, 2015 and December 31, 2014, respectively
43,010

 
40,875

Unbilled revenue
40,040

 
97,512

Capitalized incremental direct customer contract costs
7,800

 
7,633

Deferred tax assets
6,896

 
6,524

Prepaid expenses and other current assets
13,183

 
12,613

Assets held for sale
2,774

 

Total current assets
266,475

 
420,321

Property and equipment, net of accumulated depreciation of $99,739 and $94,976 at March 31, 2015 and December 31, 2014, respectively
49,753

 
50,458

Goodwill
149,554

 
114,939

Intangible assets, net
65,647

 
31,111

Capitalized incremental direct customer contract costs, net of current portion
912

 
982

Deferred tax assets
731

 
680

Deposits and other assets
7,503

 
6,211

Total assets
$
540,575

 
$
624,702

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
3,863

 
$
9,250

Accrued capacity payments
58,726

 
92,332

Accrued payroll and related expenses
17,757

 
18,446

Accrued expenses and other current liabilities
26,318

 
28,724

Deferred revenue
17,791

 
13,738

Liabilities held for sale
883

 

Total current liabilities
125,338

 
162,490

Accrued acquisition consideration
1,059

 
1,198

Convertible senior notes
139,900

 
138,908

Deferred tax liability
16,570

 
16,449

Deferred revenue
6,750

 
5,816

Other liabilities
7,910

 
7,721

Commitments and contingencies (Note 8)

 

Stockholders’ equity
 
 
 
Undesignated preferred stock, $0.001 par value; 5,000,000 shares authorized; no shares issued

 

Common stock, $0.001 par value; 50,000,000 shares authorized, 30,456,363 and 29,833,578 shares issued and outstanding at March 31, 2015 and December 31, 2014, respectively
30

 
30

Additional paid-in capital
369,630

 
365,855

Accumulated other comprehensive loss
(7,294
)
 
(4,752
)
Accumulated deficit
(119,561
)
 
(69,260
)
Total EnerNOC, Inc. stockholders’ equity
242,805

 
291,873

Noncontrolling interest
243

 
247

Total stockholders’ equity
243,048

 
292,120

Total liabilities and stockholders’ equity
$
540,575

 
$
624,702

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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EnerNOC, Inc.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share data)
 
Three Months Ended
 
March 31,
 
2015
 
2014
Revenues:
 
 
 
Grid operator
$
23,713

 
$
35,770

Utility
10,781

 
10,309

Enterprise
16,057

 
6,429

Total revenues
50,551

 
52,508

Cost of revenues
31,956

 
36,139

Gross profit
18,595

 
16,369

Operating expenses:
 
 
 
Selling and marketing
28,496

 
18,499

General and administrative
28,289

 
23,677

Research and development
7,451

 
5,175

Total operating expenses
64,236

 
47,351

Loss from operations
(45,641
)
 
(30,982
)
Other (expense) income, net
(4,657
)
 
574

Interest expense
(2,292
)
 
(450
)
Loss before income tax
(52,590
)
 
(30,858
)
Benefit from income tax
2,285

 
425

Net loss
(50,305
)
 
(30,433
)
Net loss attributable to noncontrolling interest
(4
)
 
(20
)
Net loss attributable to EnerNOC, Inc.
$
(50,301
)
 
$
(30,413
)
Net loss per common share
 
 
 
Basic and diluted
$
(1.80
)
 
$
(1.09
)
Weighted average number of common shares used in computing net loss per common share
 
 
 
Basic and diluted
28,007,756

 
27,923,861

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


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EnerNOC, Inc.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(in thousands)
 
Three Months Ended
 
March 31,
 
2015
 
2014
Net loss
$
(50,305
)
 
$
(30,433
)
Foreign currency translation adjustments
(2,543
)
 
547

Comprehensive loss
(52,848
)
 
(29,886
)
Comprehensive loss attributable to noncontrolling interest
(5
)
 
(21
)
Comprehensive loss attributable to EnerNOC, Inc.
$
(52,843
)
 
$
(29,865
)
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


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EnerNOC, Inc.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
 
Three Months Ended
 
March 31,
 
2015
 
2014
Cash flows from operating activities
 
 
 
Net loss
$
(50,305
)
 
$
(30,433
)
Adjustments to reconcile net loss to net cash used in operating activities:
 
 
 
Depreciation
5,916

 
5,482

Amortization of acquired intangible assets
3,918

 
1,883

Fair value adjustment of contingent purchase price
270

 
6

Stock-based compensation expense
3,931

 
4,227

Impairment of equipment and definite lived intangible assets
138

 
258

Unrealized foreign exchange transaction loss (gain)
5,053

 
(404
)
Deferred income taxes
(2,331
)
 
208

Non-cash interest expense
1,248

 
116

Other, net
(17
)
 
(174
)
Changes in operating assets and liabilities, net of effects of acquisitions:
 
 
 
Trade accounts receivable
6,283

 
(10,332
)
Unbilled revenue
57,443

 
39,198

Prepaid expenses and other current assets
(2,263
)
 
(3,126
)
Capitalized incremental direct customer contract costs
(116
)
 
(6,254
)
Other assets
(1,231
)
 
328

Other noncurrent liabilities
215

 
(345
)
Deferred revenue
5,026

 
9,341

Accrued capacity payments
(32,952
)
 
(18,338
)
Accrued payroll and related expenses
(3,231
)
 
(3,426
)
Accounts payable, accrued expenses and other current liabilities
(15,447
)
 
219

Net cash used in operating activities
(18,452
)
 
(11,566
)
Cash flows from investing activities
 
 
 
Purchases of property and equipment
(5,206
)
 
(6,113
)
Payments made for acquisitions, net of cash acquired
(77,559
)
 
(24,085
)
Payments made for investments

 
(1,000
)
Change in restricted cash and deposits
2,199

 
651

Payments made for acquisition of customer contract

 
(403
)
Net cash used in investing activities
(80,566
)
 
(30,950
)
Cash flows from financing activities
 
 
 
Proceeds from exercises of stock options
1,016

 
525

Payments made for employee restricted stock minimum tax withholdings
(2,027
)
 
(3,644
)
Net cash used in financing activities
(1,011
)
 
(3,119
)
Effects of exchange rate changes on cash and cash equivalents
(1,894
)
 
144

Net change in cash and cash equivalents
(101,923
)
 
(45,491
)
Cash and cash equivalents at beginning of period
254,351

 
149,189

Cash and cash equivalents at end of period
$
152,428

 
$
103,698

Supplemental disclosure of cash flow information

 

Cash paid for interest
$
983

 
$
334

Cash paid for income taxes
$
701

 
$
893

Non-cash financing and investing activities
 
 
 
Issuance of common stock in connection with acquisitions
$
103

 
$

Issuance of common stock in satisfaction of bonuses
$
865

 
$
145

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

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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 the leading provider of energy intelligence software (EIS) and related solutions. The Company’s enterprise customers use the Company's software to transform how they manage and control energy spend for their organizations, while utilities leverage the Company's software to better engage their customers and meet their demand-side management goals and objectives.
The Company’s EIS and related solutions provide its enterprise customers with a Software-as-a-Service (SaaS), solution to manage:
energy supplier selection, procurement and implementation;
energy budget forecasting;
utility bills and payment;
facility optimization, including the measurement, tracking, analysis and reporting on greenhouse gas emissions;
project tracking;
demand response, both in open and vertically-integrated markets; and
peak demand and the related cost impact.
The Company’s EIS and related solutions provide its enterprise customers the visibility they need to prioritize resources against the activities that will deliver the highest return on investment. The Company offers its EIS and related solutions to its enterprise customers at four subscription levels: basic, standard, professional, and industrial. The Company delivers its SaaS solutions on all of the major Internet browsers and on leading mobile device operating systems. In addition to its EIS packages, the Company sells two categories of premium professional services, which it refers to as Software Enhancement Services and Energy & Procurement Services. The Company’s Software Enhancement Services help its enterprise customers set their energy management strategy and enhance the effectiveness of EIS deployment. The Company’s Energy and Procurement Services consist of audits, retro-commissioning, and supply procurement consulting. The Company’s target enterprise customers for its EIS and related solutions are organizations that spend approximately $100 /year or more per site on energy, and the Company sells to these customers primarily through its direct salesforce.
The Company’s EIS for utilities is a SaaS solution that provides utilities with customer engagement, energy efficiency and demand response applications, while improving operational effectiveness. The Company delivers shared value for both the utility and its customers by combining its deep expertise with enterprise customers with energy data analytics, machine learning, and predictive algorithms to deliver segmentation and targeting capabilities that enable utilities to serve their most complex market segments, including commercial, institutional and industrial end-users of energy, and small and medium-sized enterprises. The Company’s EIS and related solutions provide its utility customers with a cost-effective and holistic solution that improves customer satisfaction ratings, delivers savings and consumption reductions to help achieve energy efficiency mandates, manages system peaks and grid constraints, and increases demand for utility-provided products and services.
The Company’s EIS and related solutions for utilities customers and electric power grid operators also include the demand response solutions and applications, EnerNOC Demand Manager™ and EnerNOC Demand Resource™. EnerNOC Demand Manager is a SaaS application that provides utilities with the underlying technology to manage their demand response programs and secure reliable demand-side resources. The Company’s EnerNOC Demand Manager product consists of long-term contracts with a utility customer for a SaaS solution that allows utilities to manage demand response capacity in utility-sponsored demand response programs. This product provides its utility customers with real-time load monitoring, dispatching applications, customizable reports, measurement and verification, and other professional services. The Company’s EnerNOC Demand Resource is a turnkey demand response resource where it matches obligation, in the form of megawatts (MW) that it agrees to deliver to the Company’s utility customers and electric power grid operators, with supply, in the form of MW that it is able to curtail from the electric power grid through its arrangements with its enterprise customers. When the Company is called upon by its utility customers and electric power grid operators to deliver its contracted capacity, the Company uses its Network Operations Center (NOC) to remotely manage and reduce electricity consumption across its growing network of enterprise customer sites, making demand response capacity available to its utility customers and electric power grid operators on demand while helping its enterprise customers achieve energy savings, improve financial results and realize environmental benefits. The Company receives recurring payments from its utility customers and electric power grid operators for providing its EnerNOC Demand Resource and the Company shares these recurring payments with its enterprise customers in exchange for those enterprise customers reducing their power consumption when called upon by the Company to do so. The Company

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occasionally reallocates and realigns its capacity supply and obligation through open market bidding programs, supplemental demand response programs, auctions or other similar capacity arrangements and third-party 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. The Company refers to the above activities as managing its portfolio of demand response capacity.
Since inception, the Company’s business has grown substantially. The Company began by providing its demand response solutions in one state in the United States in 2003 and has expanded to providing its EIS and related solutions throughout the United States, as well as internationally in Australia, Brazil, Canada, China, Germany, India, Ireland, Japan, New Zealand, South Korea, Switzerland and the United Kingdom.

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. The Company owns 60% of EnerNOC Japan K.K, for which it consolidates the operations in accordance with ASC 810, Consolidation (ASC 810). The remaining 40% represents non-controlling interest in the accompanying unaudited condensed consolidated balance sheets and statements of operations.
Subsequent Events Consideration
The Company considers events or transactions that occur after the balance sheet date but prior to the issuance of the financial statements to provide additional evidence relative to certain estimates or to identify matters that require additional disclosure. Subsequent events have been evaluated as required.

On April 22, 2014, the Company entered into an agreement with a third party enterprise customer to sell its remaining contractual demand response capacity resource, or Resource, related to an open market demand response program, which allowed the buyer to enroll directly with the applicable grid operator. Under the terms of the agreement, the Company agreed to sell the Resource with such sale and transfer being effective as of the date that the Resource has been paid for in full. In April 2015, the Company received payment in full from the Resource and completed the sale of the Resource. The resulting gain on the sale of the Resource will be recorded in the second quarter of 2015.

Use of Estimates in Preparation of Financial Statements
The 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 thereto 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, 2014 , and include all adjustments (consisting of normal, recurring adjustments) necessary for the fair presentation of the Company’s financial position at March 31, 2015 and statements of operations, statements of comprehensive loss and statements of cash flows for the three months ended March 31, 2015 and 2014 . Operating results for the three months ended March 31, 2015 are not necessarily indicative of the results to be expected for any other interim period or the entire fiscal year ending December 31, 2015 (fiscal 2015 ).
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 accrued acquisition 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. The Company bases its estimates on historical experience and various other assumptions that it believes to be reasonable under the circumstances. Changes in estimates are recorded in the period in which they become known. 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.


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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, services and products 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 derives recurring revenues from the sale of its EIS and related solutions. The Company’s customers include grid operators, utilities and enterprises. The Company does not recognize any revenues until persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and collection is deemed to be reasonably assured. In making these judgments, the Company evaluates the following criteria:

Evidence of an arrangement. The Company considers a definitive agreement signed by the customer and the Company or an arrangement enforceable under the rules of an open market bidding program to be representative of persuasive evidence of an arrangement.

Delivery has occurred. The Company considers delivery to have occurred when service has been delivered to the customer and no significant post-delivery obligations exist. In instances where customer acceptance is required, delivery is deemed to have occurred when customer acceptance has been achieved.

Fees are fixed or determinable. The Company considers the fees to be fixed or determinable unless the fees are subject to refund or adjustment or are not payable within normal payment terms. If the fee is subject to refund or adjustment and the Company cannot reliably estimate this amount, the Company recognizes revenues when the right to a refund or adjustment lapses. If the Company offers payment terms significantly in excess of its normal terms, it recognizes revenues as the amounts become due and payable or upon the receipt of cash.

Collection is reasonably assured. The Company conducts a credit review at the inception of an arrangement to determine the creditworthiness of the customer. Collection is reasonably assured if, based upon evaluation, the Company expects that the customer will be able to pay amounts under the arrangement as payments become due. If the Company determines that collection is not reasonably assured, revenues are deferred and recognized upon the receipt of cash.
The Company maintains a reserve for customer adjustments and allowances as a reduction in revenues. In determining the Company’s revenue reserve estimate, the Company relies on historical data and known performance adjustments. These factors, and unanticipated changes in the economic and industry environment, could cause the Company’s reserve estimates to differ from actual results. The Company records a provision for estimated customer adjustments and allowances in the same period as the related revenues are recorded. These estimates are based on the specific facts and circumstances of a particular program, analysis of credit memo data, historical customer adjustments, and other known factors. If the data the Company uses to calculate these estimates does not properly reflect reserve requirements, then a change in the allowances would be made in the period in which such a determination is made and revenues in that period could be affected. The Company’s revenue reserves were $475 as of March 31, 2015 and December 31, 2014 , respectively.
Revenues from grid operators and revenues from utilities principally represent demand response revenues. During the three months ended March 31, 2015 and 2014, revenues from grid operators and utilities were comprised of $32,584 and $44,100 , respectively, of demand response revenues.
The Company’s enterprise revenues from the sales of its EIS and related solutions to its enterprise customers generally represent ongoing software or service arrangements under which the revenues are recognized ratably over the same period commencing upon delivery of the EIS and related solutions to the enterprise customer. Under certain of its arrangements, a portion of the fees received may be subject to adjustment or refund based on the validation of the energy savings delivered after the implementation is complete. As a result, The Company defers the portion of the fees that are subject to adjustment or refund until such time as the right of adjustment or refund lapses, which is generally upon completion and validation of the implementation. In addition, under certain other of the Company’s arrangements, the Company sells proprietary equipment to enterprise 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 revenues associated with the equipment and begins recognizing such revenue ratably over the expected enterprise customer relationship period (generally three years), once the enterprise 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 enterprise customer relationship period.

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The Company’s EIS and related solutions for utility customers and electric power grid operators also include the following demand response applications, EnerNOC Demand Manager and EnerNOC Demand Resource.
EnerNOC Demand Resource Solution
The Company’s grid operator revenues and utility revenues primarily reflect the sale of its EnerNOC Demand Resource solution. The revenues primarily consist of capacity and energy payments, including ancillary services payments, as well as payments derived from the effective management of its portfolio, including the Company’s participation in capacity auctions and third-party contracts and ongoing fixed fees for the overall management of utility-sponsored demand response programs. The Company derives revenues from its EnerNOC Demand Resource solution by making demand response capacity available in open market programs and pursuant to contracts that are entered into with electric power grid operators and utilities. In certain markets, the Company enters into contracts with electric power utilities, generally ranging from three to ten years in duration, to deploy its EnerNOC Demand Resource solution. The Company refers to these contracts as utility contracts.
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.
Demand response capacity revenues related to the Company’s participation in the PJM open market program for its Limited demand response product (referred to as the PJM summer-only open market program in prior filings) are being recognized at the end of the four month delivery period of June through September, or during the three month period ended September 30th of each year. Because the period during which the Company is required to perform (June through September) is shorter than the period over which payments are received under the program (June through May), a portion of the revenues that have been earned are recorded and accrued as unbilled revenue. Substantially all revenues related to the PJM open market program are recognized during the three months ended September 30th. As a result of the billing period not coinciding with the revenue recognition period, the Company had $38,950 and $96,404 in unbilled revenues from PJM at March 31, 2015 and December 31, 2014, respectively.
Two new demand response programs were introduced in the PJM market beginning in the 2014/2015 delivery year (June 1, 2014-May 31, 2015): the Extended and Annual demand response programs. Under the PJM Extended program, the delivery period is from June through October and then May in the subsequent calendar year. The revenues and any associated penalties, if any, for underperformance related to participation in the PJM Extended demand response program are separate and distinct from the Company’s participation in other offerings within the PJM open market program. Under the PJM Extended demand response program, penalties incurred as a result of underperformance for a demand response event dispatched during the months of June through September and for a demand response test event are the same as the PJM Limited demand response program service offering that the Company has historically participated in. However, penalties incurred as a result of underperformance for an event dispatched during the month of October or the month of May are 1/52 multiplied by the number of the shortfall amount (committed capacity less actual delivered capacity) times the applicable capacity rate. Consistent with the PJM Limited demand response program, the fees paid under this program could potentially be subject to adjustment or refund based on performance during the applicable performance period. Due to the lack of historical performance experience with the PJM Extended program, the Company is unable to reliably estimate the amount of fees potentially subject to adjustment or refund as of the end of September. Therefore, until the Company is able to reliably estimate the amount of fees potentially subject to adjustment or refund, revenue from the PJM Extended program will be deferred and recognized at the end of the delivery period (i.e., May). For the PJM Extended demand response delivery period that commenced on June 1, 2014 and ends on May 31, 2015, the potential fees that could be earned are not material, however, for subsequent years beyond the delivery period ending on May 31, 2015, the potential fees from participation in the PJM Extended demand response program could be material. Under the PJM Annual program, the delivery period is from June through May. Consistent with the Limited and Extended programs, revenues from the Annual program will be recognized at the end of the service delivery period. The Company has no MW capacity obligations in the Annual program for the 2014/2015 delivery year.
Demand response capacity revenues related to the Company’s participation in an open market program in Western Australia are potentially subject to refund and, therefore, are deferred until a portion of such capacity revenues are reliably estimable which currently occurs upon an emergency event dispatch or until the end of the program period on September 30th. Historically all capacity revenues have been recognized during the three month period ended September 30th as there have previously been no emergency event dispatches. During the three month period ended June 30, 2014, there was an emergency

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event dispatch in this open market program and as a result, a portion of the capacity revenues were fixed and no longer subject to adjustment. As of September 30, 2014, the Company determined that the amount of fees potentially subject to adjustment or refund was reliably estimable beginning with the new program year in Western Australia commencing on October 1, 2014. Therefore, future revenues will be recognized ratably over the delivery period from October 1 to September 30.
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. During the three months ended March 31, 2015 and 2014 , the Company recognized $284 and $20,570 , respectively, of energy event revenues.
The Company has evaluated the forward capacity programs in which it participates and has determined that its contractual obligations in these programs do not currently meet the definition of derivative contracts under ASC 815, Derivatives and Hedging (ASC 815).
The Company has evaluated the factors within ASC 605, Revenue Recognition (ASC 605), regarding gross versus net revenue reporting for its demand response revenues and its payments to enterprise customers. Based on the evaluation of the factors within ASC 605, the Company has determined that all of the applicable indicators of gross revenue reporting were met. The applicable indicators of gross revenue reporting included, but were not limited to, the following:
The Company is the primary obligor in its arrangements with electric power grid operators and utility customers because the Company provides its demand response services directly to electric power grid operators and utilities under long-term contracts or pursuant to open market programs and contracts separately with enterprise customers to deliver such services. The Company manages all interactions with the electric power grid operators and utilities, while enterprise customers do not interact with the electric power grid operators and utilities. In addition, the Company assumes the entire performance risk under its arrangements with electric power grid operators and utility customers, including the posting of financial assurance to assure timely delivery of committed capacity with no corresponding financial assurance received from its enterprise customers. In the event of a shortfall in delivered committed capacity, the Company is responsible for all penalties assessed by the electric power grid operators and utilities without regard for any recourse the Company may have with its enterprise customers.
The Company has latitude in establishing pricing, as the pricing under its arrangements with electric power grid operators and utilities is negotiated through a contract proposal and contracting process or determined through a capacity auction. The Company then separately negotiates payments to enterprise customers and has complete discretion in the contracting process with enterprise customers.
The Company has complete discretion in determining which suppliers (enterprise customers) will provide the demand response services, provided that the enterprise customer is located in the same region as the applicable electric power grid operator or utility.
 
The Company is involved in both the determination of service specifications and performs part of the services, including the installation of metering and other equipment for the monitoring, data gathering and measurement of performance, as well as, in certain circumstances, the remote control of enterprise customer loads.

As a result, the Company has concluded that it earns revenue (as a principal) from the delivery of demand response services to electric power grid operators and utility customers and records the amounts billed to the electric power grid operators and utility customers as gross demand response revenues and the amounts paid to enterprise customers as cost of revenues.
EnerNOC Demand Manager Solution
With respect to EnerNOC Demand Manager, the Company generally receives an ongoing fee for overall management of the utility demand response program based on enrolled capacity or enrolled enterprise customers, which is not subject to adjustment based on performance during a demand response dispatch. The Company recognizes utility revenues from these fees ratably over the applicable service delivery period commencing upon when the enterprise customers have been enrolled and the contracted services have been delivered. In addition, under this offering, the Company may receive additional fees for program start-up, as well as, for enterprise customer installations. The Company has determined that these fees do not have stand-alone value due to the fact that such services do not have value without the ongoing services related to the overall management of the utility demand response program and therefore, these fees are recognized over the estimated customer relationship period, which is generally the greater of three years or the contract period, commencing upon the enrollment of the enterprise customers and delivery of the contracted services.

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The Company follows the provisions of ASC Update No. 2009-13, Multiple-Deliverable Revenue Arrangements . The Company typically determines the selling price of its services based on vendor specific objective evidence (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 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 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. Third Party Evidence (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 stand-alone prices of competitive solutions. Management’s best estimate of selling price (ESP) is established in those instances where neither VSOE nor TPE are available, by 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 other EIS software and related solutions.
Stock-Based Compensation
The Company grants share-based awards to employees, non-employees, members of the board and advisory board members. The Company accounts for grants of stock-based compensation in accordance with ASC 718,  Stock Compensation  (ASC 718). The Company accounts for share-based awards granted to non-employees in accordance with ASC 505-50,  Equity Based Payments to Non-Employees , which results in the Company continuing to re-measure the fair value of the non-employee share-based awards until such time as the awards vest. All share-based awards granted, including grants of stock options, restricted stock and restricted stock units, are recognized in the statement of operations based on their fair value as of the date of grant. As of March 31, 2015, the Company had two  stock-based compensation plans, which is more fully described in Note 9.
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. The fair value of restricted stock upon which vesting is solely service-based 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. With the exception of certain executives whose employment agreements provide for continued vesting in certain circumstances upon departure, 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.
The fair value of each option has been and will be estimated on the date of grant using a lattice valuation model. The lattice model takes into account variables such as expected volatility, dividend yield rate, and risk free interest rate. However, in addition, the lattice model considers the probability that the option will be exercised prior to the end of its contractual life and the probability of termination or retirement of the option holder in computing the value of the option.
A summary of significant assumptions used to estimate the fair value of stock options granted to employees were as follows:
 
Three Months Ended March 31,
 
2015
 
2014
Risk-free interest rate
2.50
%
 
2.67
%
Vesting term, in years
2.30

 
2.22

Expected annual volatility
70
%
 
72
%
Expected dividend yield

 

Exit rate pre-vesting
7.7
%
 
7.8
%
Exit rate post-vesting
14.06
%
 
14.06
%

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The risk-free interest rate is the rate available as of the option date on zero-coupon U.S. Treasury securities with a term equal to the expected life of the option. Volatility measures the amount that a stock price has fluctuated or is expected to fluctuate during a period. The Company calculates volatility using a component of implied volatility and historical volatility to determine the value of share-based payments. 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 2014 credit facility preclude the Company from paying dividends. The Company periodically evaluates its employee demographics and historical forfeiture experience to determine if its estimated pre-vesting and post-vesting exit rates need to be revised. During the three months ended March 31, 2015 , the Company did not change its estimated pre-vesting and post-vesting exit rates.
Stock-based compensation expense recorded in the unaudited condensed consolidated statements of operations was as follows:
 
Three Months Ended
March 31,
 
2015
 
2014
Selling and marketing expenses
$
1,643

 
$
1,193

General and administrative expenses
2,430

 
2,696

Research and development expenses
336

 
338

Total stock-based compensation expense (1)
$
4,409

 
$
4,227

(1) The three months ended March 31, 2015 includes $478 of stock-based compensation expense related to the acquisition of World Energy that was settled with the equivalent cash payments.
Stock-based compensation expense related to share-based awards granted to non-employees was not material for the three months ended March 31, 2015 and 2014 . The Company did not recognize income tax benefits from stock-based compensation arrangements during the three months ended March 31, 2015 and 2014 . No material stock-based compensation expense was capitalized during the three months ended March 31, 2015 and 2014 .
The Company’s chief executive officer is required to receive his performance-based bonus, if achieved, in shares of the Company's common stock. The Company recorded this amount as stock-based compensation expense ratably over the applicable performance and service period in accordance with ASC 718. During the three months ended March 31, 2015, the Company recorded $113 of stock-based compensation expense related to this performance based bonus.
Foreign Currency Translation
The financial statements of the Company’s international subsidiaries are translated in accordance with ASC 830,  Foreign Currency Matters  (ASC 830), into the Company’s reporting currency, which is the United States dollar. The functional currencies of the Company’s subsidiaries in Australia, Brazil, Canada, Germany, Ireland, India, Japan, New Zealand, South Korea and the United Kingdom are the local currencies.
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 which have not been deemed a “long-term investment,” as defined by ASC 830, into the functional currency of the respective entity, resulting in unrealized gains or losses recorded in the unaudited condensed consolidated statements of operations. Revenues and expenses are translated using average exchange rates during the respective periods.
Foreign currency translation adjustments are recorded as a component of stockholders’ equity within accumulated other comprehensive loss. (Losses) gains arising from transactions denominated in foreign currencies and the remeasurement of certain intercompany receivables and payables are included in other (expense) income, net on the unaudited condensed consolidated statements of operations and were ($4,977) and ( $(387) for the three months ended March 31, 2015 and 2014 , respectively.
Comprehensive Loss
Comprehensive loss is defined as the change in equity of a business enterprise during a period resulting from transactions and other events and circumstances from non-owner sources. The Company’s comprehensive loss is composed of net loss and foreign currency translation adjustments. As of March 31, 2015 and December 31, 2014 , accumulated other comprehensive loss was comprised solely of cumulative foreign currency translation adjustments. The Company presents its components of other comprehensive loss, net of related tax effects.

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Table of Contents

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 applicable third-party costs who devote time to the development of internal-use computer software and amortizes these costs on a straight-line basis over the estimated useful life of the software, which is generally three years. The Company’s judgment is required in determining the point at which various projects enter the stages at which costs may be capitalized, in assessing the ongoing value and impairment of the capitalized costs, and in determining the estimated useful lives over which the costs are amortized. Internal use software development costs of $1,803 and $1,398 for the three months ended March 31, 2015 and 2014 , respectively, have been capitalized in accordance with ASC 350-40. Amortization of capitalized software development costs was $1,665 and $1,530 for the three months ended March 31, 2015 and 2014 , respectively. Accumulated amortization of capitalized software development costs was $29,268 and $27,603 as of March 31, 2015 and December 31, 2014 , respectively.
The costs for the development of new software and substantial enhancements to existing software that is intended to be sold or marketed (external use software) are expensed as incurred until technological feasibility has been established, at which time any additional costs would be capitalized. The Company has determined that technological feasibility of external use software is established at the time a working model of software is completed. Because the Company believes its current process for developing external use software will be essentially completed concurrently with the establishment of technological feasibility, no such costs have been capitalized to date.
Impairment of Long Lived Assets
The Company reviews long-lived assets, including property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of assets may not be recoverable over its remaining estimated useful life. If these assets are considered to be impaired, the 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. Impairment is recognized in earnings and equals the amount by which the carrying value of the assets exceeds their fair value determined by either a quoted market price, if any, or a value determined by utilizing a discounted cash flow (DCF) 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 March 31, 2015 and 2014 , the Company identified certain impairment indicators related to certain demand response equipment as a result of the removal of such equipment from operational sites during each of these respective years. As such, the equipment had no remaining useful life and no fair value. The remaining net carrying value was written off, resulting in the recognition of impairment charges of $138 and $95 , for the three months ended March 31, 2015 and 2014, respectively, which is included in cost of revenues in the unaudited condensed consolidated statements of operations. The Company did not recognize impairment charges related to definite lived intangible assets for the three months ended March 31, 2015. For the three months ended March 31, 2014, the Company recognized $163 related to impairment of definitive lived intangible assets.
Industry Segment Information
The Company views its operations and manages its business as one operating segment. 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 operating decision maker is considered to be its Chief Executive Officer.
The Company operates in the major geographic areas noted in the chart below. The “All other” designation includes revenues from other international locations, primarily consisting of Germany, Ireland, New Zealand, South Korea and the United Kingdom. Revenues are based upon customer location and internationally totaled $20,569 and $9,180 for the three months ended March 31, 2015 and 2014 , respectively. Australia was the only individual foreign country that accounted for more than 10% of the Company’s total revenues for the three months ended March 31, 2015 or 2014 .

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Table of Contents

Revenues by geography as a percentage of total revenues are as follows:
 
Three Months Ended March 31,
 
2015
 
2014
United States
59
%
 
83
%
Australia
15

 
2

Canada
10

 
11

All other
16

 
4

Total
100
%
 
100
%

As of March 31, 2015 and December 31, 2014, the long-lived tangible assets related to the Company’s international subsidiaries were less than 10% of the Company’s long-lived tangible assets and were deemed not material.
2. Acquisition
World Energy Solutions, Inc.
On January 5, 2015, the Company completed the acquisition of World Energy Solutions, Inc., or World Energy, an energy management software and services firm located in Worcester, Massachusetts that helps enterprises to simplify the energy procurement process through a suite of SaaS tools. The Company believes that the acquisition and integration of World Energy’s software into its EIS platform will help deliver more value to its enterprise customers through enhanced technology-enabled capabilities to manage the energy procurement process.
The Company concluded that this acquisition represented a business combination under the provisions of ASC 805, Business Combinations (ASC 805), but has concluded that it did not represent a material business combination, and therefore, no pro forma financial information is required to be presented. Subsequent to the acquisition date, the Company’s results of operations include the results of operations of World Energy.
The Company acquired World Energy for a purchase price of $5.50 per share and the assumption of debt for an aggregate purchase price of $79,913 , or $77,211 net of $2,702 in acquired cash. The Company paid cash of $68,538 for shares outstanding and $9,468 to repay debt. In addition, the Company was obligated and required to exchange and replace the outstanding share based awards of World Energy on the acquisition date. The Company cash settled the outstanding restricted stock awards and vested stock options and issued replacement awards for the unvested World Energy stock options for total consideration of $3,027 . Of this amount, $1,849 was determined to be purchase price consideration and $1,178 was determined to be post combination stock-based compensation expense ( $443 was recognized immediately as expense upon the close of the transaction as there was no remaining service period, with the remaining expense to be recognized over a period of 2.3 years ). In addition, the Company paid $58 for outstanding warrants.
Transaction costs of $367 related to World Energy were expensed as incurred and are included in general and administrative expenses in the Company’s unaudited condensed consolidated statements of operations.
The Company has allocated the purchase price to the net tangible assets and intangible assets based upon their fair values at January 5, 2015. The difference between the aggregate purchase price and the fair value of assets acquired and liabilities assumed was allocated to goodwill, none of which is deductible for tax purposes. The Company's acquired identifiable intangible assets include $29,160 of customer relationships and $12,240 of developed technology. 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 amortizes these acquired 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. As of March 31, 2015, the acquired intangible assets will be amortized over a weighted average amortization period as follows: customer relationships (backlog) of 1.8 years ; customer relationships (contract renewals) of 7.1 years and developed technology of 5.2 years .
The following table summarizes the purchase consideration paid for World Energy:
Purchase consideration:


     Cash paid for stock, stock awards and warrants
$
70,445

     Repayment of debt
9,468

        Fair value of consideration transferred
$
79,913



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Table of Contents

The preliminary fair values of assets acquired and liabilities assumed as of the acquisition date are set forth in the table below. These preliminary fair values were determined through established and generally accepted valuation techniques and are subject to change during the measurement period as valuations are finalized. As a result, the acquisition accounting is not complete and additional information that existed at the acquisition date may become known to the Company during the remainder of the measurement period. As of the filing date of this Quarterly Report on Form 10-Q, the Company is still in the process of valuing the assets acquired and liabilities assumed of World Energy’s business, including accounts receivable, deferred taxes, intangible assets and accrued expenses and other liabilities.
     Cash
$
2,702

     Accounts receivable
9,337

     Prepaid expenses and other current assets
1,596

     Property and equipment
449

     Identified intangible assets
41,400

     Goodwill
39,469

     Accounts payable, accrued expenses and other liabilities
(12,547
)
     Deferred revenue
(320
)
     Deferred tax liabilities, net
(2,173
)
        Total
$
79,913


World Energy Efficiency Services - Assets and liabilities held for sale
The acquisition of World Energy included the World Energy Efficiency Services business (WEES), which provides comprehensive, turnkey direct install energy efficiency services in New England. As of the acquisition date of January 5, 2015, the Company committed to a plan to sell the WEES business. Based on the Company’s evaluation of the assets held for sale criteria under ASC 360-10, Impairment and Disposal of Long-Lived Assets , the Company concluded all of the criteria were met and that the assets and liabilities of the WEES business that are expected to be sold should be classified as held for sale as of January 5, 2015.
The held for sale balances relate to operational assets and liabilities associated with in-progress contracts, and separately identifiable intangible assets, including customer relationships and developed technology that were acquired in connection with the World Energy acquisition and specifically relate to WEES. Because the Company has concluded that WEES meets the definition of a business in accordance with ASC 805, included in assets held for sale is the allocated goodwill of WEES. The following table summarizes the assets and liabilities held for sale as of March 31, 2015:

As of March 31, 2015
Goodwill
$
990

Intangible assets
800

Inventories
935

Fixed assets
49

     Assets held for sale
$
2,774




Accounts payable
$
(694
)
Deferred revenue
(189
)
     Liabilities held for sale
$
(883
)
The Company has concluded that the WEES disposal does not meet the criteria of discontinued operations under ASC 205-20, Discontinued Operations because the sale of the WEES business does not represent a strategic shift that had a major effect on the Company's operations and financial results and therefore, the results of operations of WEES have not been presented as discontinued operations in the Company’s unaudited condensed consolidated statement of operations for the three months ended March 31, 2015.

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Table of Contents

3. Intangible Assets
The following table provides the gross carrying amount and related accumulated amortization of the Company's definite-lived intangible assets as of March 31, 2015 and December 31, 2014 :
 
 
 
As of March 31, 2015
 
As of December 31, 2014
 
Weighted Average
Amortization
Period (in years)
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Gross
Carrying
Amount
 
Accumulated
Amortization
Customer relationships
6.88
 
$
64,032

 
$
(21,595
)
 
$
37,516

 
$
(19,725
)
Customer contracts
1.87
 
4,870

 
(3,745
)
 
4,912

 
(3,618
)
Employment agreements and non-compete agreements
1.20
 
3,085

 
(1,915
)
 
3,198

 
(1,821
)
Software
0.00
 
120

 
(120
)
 
120

 
(120
)
Developed technology
6.45
 
24,804

 
(4,233
)
 
13,615

 
(3,407
)
Trade name
0.46
 
1,086

 
(831
)
 
1,124

 
(777
)
Patents
4.88
 
180

 
(91
)
 
180

 
(86
)
Total
 
 
$
98,177

 
$
(32,530
)
 
$
60,665

 
$
(29,554
)
Amortization expense related to definite-lived intangible assets amounted to $3,918 and $1,883 for the three months ended March 31, 2015 and 2014 , respectively. Amortization expense for acquired developed technology, which was $990 and $351 for the three months ended March 31, 2015 and 2014 , respectively, is included in cost of revenues in the unaudited condensed consolidated statements of operations. Amortization expense for all other intangible assets is included as a component of operating expenses in the unaudited condensed consolidated statements of operations. The definite-lived intangible asset lives range from 1 to 15 years and the weighted average remaining life was 6.3 years at March 31, 2015 . Amortization expense is estimated to be approximately $10,500 , $12,696 , $9,693 , $7,018 , $6,281 and $19,459 for the nine months ending December 31, 2015 , and years ending 2016, 2017, 2018, 2019 and beyond, respectively.
4. Goodwill
The following table shows the change of the carrying amount of goodwill from December 31, 2014 to March 31, 2015 :
Balance at December 31, 2014
$
114,939

Foreign currency translation impact
(3,864
)
Acquisition
39,469

Held for sale
(990
)
Balance at March 31, 2015
$
149,554

5. Net Loss Per Share
ASC 260, Earnings Per Share (ASC 260), provides guidance on the computation, presentation and disclosure guidance for earnings per share. In particular, ASC 260-10-45-40 provides guidance on the earnings-per-share (EPS) ramifications of convertible securities. The Company concluded that it is required to separate the conversion feature embedded in the convertible notes issued in August 2014 (see Note 7 for further discussion) upon issuance, even though its ability to settle conversion requests in shares, cash or a combination of shares and cash is contingent on shareholder approval. The Company has determined the impact of the convertible notes on diluted EPS using the “if-converted” method until when and if the shareholders approve its request to settle other than by physical settlement. Under the “if-converted” method:
 
The Company (1) adds back interest expense recognized on the convertible debt to income available to common shareholders, (2) adjusts income available to common shareholders to the extent nondiscretionary adjustments based on income made during the period would have been computed differently had the interest on convertible debt never been recognized (e.g., expense associated with a profit sharing plan or a royalty agreement), and (3) adjusts income available to common shareholders for the income tax effect, if any, of (1) and (2).
The convertible debt is assumed to have been converted at the beginning of the period (or at time of issuance, if later), and the resulting common shares is included in the number of shares outstanding.

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Table of Contents

In applying the “if-converted” method, conversion is not assumed for purposes of computing diluted EPS if the effect will be anti-dilutive. For the three months ended March 31, 2015 , the convertible debt is not assumed to be converted as the impact is anti-dilutive.
When and if shareholder approval is obtained, the Company will subsequently determine the impact of the convertible notes on diluted EPS in a manner consistent with the accounting for Instrument X (i.e., the Treasury Stock Method as described in ASC 260-45-23). Instrument X presumes share settlement for diluted EPS purposes; however, the presumption that the contract will settle in common stock may be overcome if the entity controls the means of settlement and past experience or a stated policy provides a reasonable basis to believe that the contract will be partially or wholly settled in cash.
Net loss attributable to EnerNOC, Inc. utilized in the calculation of net loss per share was the same for basic and diluted.
A reconciliation of basic and diluted share amounts for the three months ended March 31, 2015 and 2014 are as follows:
 
Three Months Ended
March 31,
 
2015
 
2014
Basic weighted average common shares outstanding
28,007,756

 
27,923,861

Weighted average common stock equivalents

 

Diluted weighted average common shares outstanding
28,007,756

 
27,923,861

 
 
 
 
Anti-dilutive shares related to:
 
 
 
Stock options
402,104

 
339,125

Nonvested restricted stock
1,604,473

 
465,542

Restricted stock units
45,624

 

Escrow shares

 

In the table above, anti-dilutive shares consist of those common stock equivalents that have either an exercise price above the average stock price for the period or the common stock equivalents' related average unrecognized stock compensation expense is sufficient to “buy back” the entire amount of shares. 
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. The convertible debt is not assumed to be converted as the impact is anti-dilutive. In addition, with respect to restricted stock awards that vest based on achievement of performance conditions, because performance conditions are considered contingencies under ASC 260, the criteria for contingent shares must first be applied before determining the dilutive effect of these types of share-based payments. Prior to the end of the contingency period (i.e., before the performance conditions have been satisfied), the number of contingently issuable common shares to be included in diluted weighted average common shares outstanding should be based on the number of common shares, if any, that would be issuable under the terms of the arrangement if the end of the reporting period were the end of the contingency period (e.g., the number of shares that would be issuable based on current performance criteria) assuming the result would be dilutive.
In connection with certain of the Company’s business combinations, the Company issued common 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. As of March 31, 2015 , the Company had 87,483 shares of common stock held in escrow.
The Company includes the 254,654 shares related to a component of the deferred purchase price consideration from the acquisition of M2M Communications Corporation (M2M) in both the basic and diluted weighted average common shares outstanding amounts as the shares are not subject to adjustment and the issuance of such shares is not subject to any contingency.

18

Table of Contents

6. Fair Value Measurements
The Company’s financial instruments mainly consist of cash and cash equivalents, restricted cash, accounts receivable and accounts payable. The carrying amounts of these financial instruments approximate their respective fair value due to their short-term nature. The Company has $160,000 of convertible debt outstanding (See Note 7) as of March 31, 2015 . The fair value of the convertible debt was approximately $116,800 as of March 31, 2015 based on the trading prices of the underlying convertible notes as of that date. As of December 31, 2014 , the fair value of the convertible note was approximately $133,392 .
The table below presents the balances of assets and liabilities measured at fair value on a recurring basis at March 31, 2015 and December 31, 2014 :
 
Totals
 
Quoted Prices in
Active Markets
for Identical
Assets (Level 1)
 
Significant Other
Observable Inputs 
(Level 2)
 
Unobservable Inputs 
(Level 3)
Fair Value Measurement at March 31, 2015
 
 
 
 
 
 
 
Assets: Money market funds (1)
$
123,762

 
$
123,762

 
$

 
$

Liabilities: Contingent purchase price consideration (2)
$
599

 
$

 
$

 
$
599

Fair Value Measurement at December 31, 2014
 
 
 
 
 
 
 
Assets: Money market funds (1)
$
225,815

 
$
225,815

 
$

 
$

Liabilities: Contingent purchase price consideration (3)
$
649

 
$

 
$

 
$
649

(1) The money market funds balance included in cash and cash equivalents represents the only asset that the Company measures and records at fair value on a recurring basis. These money market funds represent excess operating cash that is invested daily into an overnight investment account.
(2) Accrued contingent purchase price consideration relates to the Company’s acquisitions of Activation Energy DSU Limited, or Activation Energy, and Entelios AG, or Entelios, in February 2014. As of March 31, 2015, approximately $505 associated with the Activation Energy acquisition has been reflected in accrued expense and other current liabilities in the condensed consolidated balance sheet. The additional $94 relates to the Entelios earn-out, which is reflected in accrued acquisition consideration in the condensed consolidated balance sheet.
(3) Accrued contingent purchase price consideration relates to the Company’s acquisitions of Activation Energy and Entelios. As of December 31, 2014, approximately $312 associated with the Activation Energy acquisition was recorded in accrued expense and other current liabilities in the condensed consolidated balance sheet. The remaining $337 was recorded in accrued acquisition consideration in the condensed consolidated balance sheet, of which $234 related to the Activation Energy acquisition and $103 related to the Entelios acquisition.
Accrued acquisition consideration on the condensed consolidated balance sheet also includes amounts due to shareholders of the ULC acquisition in April 2014 and the M2M acquisition in January 2011. These payments are contingent upon continued employment or based on the passage of time. Accordingly, such amounts are not deemed contingent consideration and are not measured at fair value on a recurring basis and therefore have not been reflected in the table above.
The following is a rollforward of the Level 3 assets and liabilities from January 1, 2015 through March 31, 2015 :
 
Liabilities
Balance January 1, 2015
$
649

Cash payment during the period
(277
)
Increase due to change in assumptions and present value accretion
272

Change due to movement in foreign exchange rates
(45
)
Balance March 31, 2015
$
599

 
7. Borrowings and Credit Arrangements
Credit Agreement
On August 11, 2014, the Company entered into a $30,000 senior secured one year revolving credit facility, the full amount of which may be available for issuances of letters of credit, pursuant to a loan and security agreement (the 2014 credit facility) with Silicon Valley Bank (SVB). The 2014 credit facility is subject to continued covenant compliance and borrowing

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base requirements. As of March 31, 2015 , the Company was in compliance with all of its covenants under the 2014 credit facility. The Company believes that it is reasonable it will comply with the covenants of the 2014 credit facility through its expiration date of August 11, 2015. As of March 31, 2015 , the Company had no borrowings, but had outstanding letters of credit totaling $21,433 under the 2014 credit facility. As of March 31, 2015 , the Company had $8,567 available under the 2014 credit facility for future borrowings or issuances of additional letters of credit.
Convertible Notes
On August 12, 2014, the Company entered into a purchase agreement with Morgan Stanley & Co. LLC relating to the Company’s sale of $160,000 aggregate principal amount of 2.25% convertible senior notes due August 15, 2019 (the Notes), as amended (the Offering). The Notes includes customary terms and covenants, including certain events of default after which the Notes may be declared or become due and payable immediately. The Notes are convertible at an initial conversion rate of 36.0933 shares of the common stock per $1,000 principal amount of Notes. However, if the Company receives stockholder approval at the annual meeting of stockholders scheduled to be held on May 27, 2015, the Company may settle conversions of Notes by paying or delivering, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at its election. The conversion rate will be subject to adjustment in some events, but will not be adjusted for any accrued and unpaid interest.
The Company has concluded that ASC 470, Debt applies to the Notes and accordingly, the Company is required to account for the liability and equity components of its Notes separately to reflect its nonconvertible debt borrowing rate. The estimated fair value of the liability component at issuance of $137,430 was determined using a discounted cash flow technique. The excess of the gross proceeds received over the estimated fair value of the liability component totaling $22,570 has been allocated to the conversion feature (equity component) with a corresponding offset recognized as a discount to reduce the net carrying value of the Notes. The discount is being amortized to interest expense over a five year period ending August 15, 2019 (the expected life of the liability component) using the effective interest method. In addition, transaction costs are required to be allocated to the liability and equity components based on their relative percentages. The applicable transaction costs allocated to the liability and equity components at issuance were $4,056 and $666 , respectively. The transaction costs allocated to the liability represent debt issuance costs and are recorded as an asset in the Company’s unaudited condensed consolidated balance sheet. As of March 31, 2015 , $706 and $2,949 of deferred issuance costs are included in Prepaid expenses and other current assets and Deposits and other assets, respectively, in the Company’s unaudited condensed consolidated balance sheet.
Interest expense under the Notes is as follows:
 
Three Months Ended
 
March 31,
2015
Accretion of debt discount
$
992

Amortization of deferred financing costs
163

Non-cash interest expense
1,155

2.25% accrued interest
880

Total interest expense from Notes
$
2,035

Based on the Company’s evaluation of the Notes in accordance with ASC 815-40, Contracts in Entity’s Own Equity , the Company determined that the Notes contain a single embedded derivative, comprising both the contingent interest feature related to timely filing failure, requiring bifurcation as the features is not clearly and closely related to the host instrument. The Company has determined that the value of this embedded derivative was nominal as of the date of issuance and as of March 31, 2015 .
8. Commitments and Contingencies
In July 2012, the Company entered into a lease for its corporate headquarters at One Marina Park Drive, Floors 4-6, Boston, Massachusetts. The lease term is through July 2020 and the lease contains both a rent holiday period and escalating rental payments over the lease term. The lease requires payments for additional expenses such as taxes, maintenance, and utilities and contains a fair value renewal option. The Company began occupying the space during the second quarter of fiscal 2013. In accordance with the terms of the lease, the landlord provided certain lease incentives with respect to the leasehold improvements. In accordance with ASC 840, Leases (ASC 840), the Company recorded the incentives as deferred rent and will reflect these amounts as reductions of lease expense over the lease term. Although lease payments under this arrangement did not commence until August 2013, as the Company had the right to use and controlled physical access to the space, it

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determined that the lease term commenced in July 2012 and, as a result, began recording rent expense on this lease arrangement at that time on a straight-line basis. The lease also contains certain provisions requiring the Company to restore certain aspects of the leased space to its initial condition. The Company has determined that these provisions represent asset retirement obligations and recorded the estimated fair value of these obligations as the related leasehold improvements were incurred. The Company will accrete the liability to fair value over the life of the lease as a component of operating expenses. As of March 31, 2015 , the Company's asset retirement obligation totaled $424 .
In October 2014, the Company entered into an amendment to this lease to lease additional space. The lease term for this additional space commenced on January 1, 2015 and coincides with the term of the existing lease unless earlier terminated or further extended as provided for in the existing lease. The lease amendment contains both a rent holiday, under which lease payments do not commence until June 2015, and escalating rental payments. As a result, the Company will record rent on a straight-line basis in accordance with ASC 840 beginning upon the lease commencement date.
In March 2014, the Company entered into a lease for its California operations. The lease term runs through September 2019 and the lease contains both a rent holiday period and escalating rental payments over the lease term. The lease requires payments for additional expenses such as taxes, maintenance, and utilities and contains a fair value renewal option. The lease commenced on April 1, 2014.
In connection with the Company’s acquisitions completed in 2014 and January 2015, the Company acquired certain facility operating lease arrangements which were all considered to contain current market terms and rates. These leases have original lease terms between one and ten years and expire through September 2022. Certain of the leases require payments for additional expenses such as taxes, maintenance, and utilities and contain fair value renewal options. There were no ongoing rent holidays or escalating rent payments over the remaining lease terms as of the dates of acquisition.
At March 31, 2015 , future minimum lease payments for operating leases with non-cancelable terms of more than one year were as follows:
 
Operating Leases
Remainder of 2015
$
6,796

2016
8,906

2017
8,027

2018
8,016

2019
7,505

Thereafter
4,313

Total minimum lease payments (not reduced by sublease rentals of $1,892)
$
43,563

As of March 31, 2015 and December 31, 2014 , the Company had a deferred rent liability representing rent expense recorded on a straight-line basis in excess of contractual lease payments of $7,453 and $7,296 , respectively, of which $ 3,422 and $ 3,584 relate to landlord lease incentives. These amounts are included in other liabilities in the accompanying unaudited condensed consolidated balance sheets.
As of March 31, 2015 , the Company was contingently liable under outstanding letters of credit for $21,433 . As of March 31, 2015 and December 31, 2014 , the Company had restricted cash balances of $344 and $813 , respectively, which primarily related to cash utilized to collateralize certain demand response programs.
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, which may be secured by cash or letters of credit. Performance guarantees as of March 31, 2015 were $20,502 and included deposits held by certain customers of $1,363 at March 31, 2015 . 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 deposits 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 March 31, 2015 , the Company had $1,010 in deferred fees

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for these arrangements which were included in deferred revenues as of March 31, 2015 . As of March 31, 2015 , the maximum termination penalty to which the Company could be subject under these arrangements, which the Company has deemed not probable of being incurred, was approximately $6,556 .

As of March 31, 2015 and December 31, 2014 , the Company accrued $417 and $344 , respectively, of performance adjustments related to fees received for its contractual commitments and participation in certain demand response programs. The Company believes that it is probable that these performance adjustments will need to be re-paid to the utility or electric power grid operator and since the utility or electric power grid operator has the right to require repayment at any point at its discretion, the amounts have been classified as a current liability.
The Company typically grants customers a limited warranty that guarantees that its hardware will substantially conform to current specifications for 1 from the delivery date. Based on the Company’s operating history, the liability associated with product warranties has been determined to be nominal.
In connection with the Company’s agreement for its employee health insurance plan, the Company could be subject to an additional payment if the agreement is terminated. The Company has not elected to terminate this agreement nor does the Company believe that termination is probable for the foreseeable future. As a result, the Company has determined that it is not probable that a loss is likely to occur and no amounts have been accrued related to this potential payment upon termination. As of March 31, 2015 , the payment due upon termination would be $928 .
On March 15, 2011, the Federal Energy Regulatory Commission (FERC) issued Order 745, Demand Response Compensation in Organized Wholesale Energy Markets, which was effective April 25, 2011. Under Order 745, FERC amended its regulations under the Federal Power Act to ensure that when a demand response resource participating in an organized wholesale energy market administered by a Regional Transmission Organization (RTO) or Independent System Operator (ISO) has the capability to balance supply and demand as an alternative to a generation resource and when dispatch of that demand response resource is cost-effective as determined by the net benefits test described in Order 745, that demand response resource must be compensated for the service it provides to the energy market at the market price for energy, referred to as the locational marginal price (LMP). As a result, Order 745 impacted the energy rates that the Company received in two open market economic demand response programs.
On May 23, 2014, the United States Court of Appeals for the District of Columbia Circuit, or the Court, issued two orders ( EPSA v. FERC) related to Order 745. In a 2-1 decision of a panel of the Court, the Court vacated Order 745 on the grounds that FERC lacked jurisdiction over demand response. The Court further stayed its own order until seven days following disposition of any timely petition for rehearing. Order 745 relates exclusively to compensation in FERC jurisdictional wholesale energy markets, and by its terms does not apply to FERC jurisdictional capacity markets. On June 11, 2014, FERC and other parties filed motions seeking rehearing en banc of the 2-1 decision vacating Order 745, which motions were denied on September 17, 2014. On September 22, 2014, FERC filed a motion with the Court to stay the issuance of the Court’s mandate in EPSA v. FERC until December 16, 2014. The Court granted that motion and subsequently granted a second motion to extend the stay until January 15, 2015, and thereafter if a petition for a writ of certiorari were filed with the United States Supreme Court. FERC, the Company and a number of other parties filed petitions for a writ of certiorari in the U.S. Supreme Court on January 15, 2015. On May 4, 2015, the U.S. Supreme Court granted petitioners’ writs of certiorari. No schedule has been set for briefs or oral argument. As a result, Order 745 remains in effect per the Court’s stay until after the U.S. Supreme Court issues its decision.
Pursuant to the Federal Power Act, Order 745 was implemented “subject to refund”, which means that FERC retained the discretion to order refunds, if appropriate, of revenues associated with implementation of Order 745. The “subject to refund” requirement does not require refund, and given FERC’s past treatment of its refund cases, the Company believes that the likelihood of refunds actually being required is not significant. The Company notes that with respect to the historical fees received from participation in programs that were impacted by Order 745, that Order 745 was effective and binding and that the Company delivered its service in accordance with the applicable market and program tariffs and manuals. As a result, the Company has concluded that the historical revenue recognition was appropriate and that the potential risk of refund as a result of the May 23, 2014 Court ruling on Order 745 should be evaluated as a potential contingent loss as a result of this event in accordance with ASC 450, Contingencies . Based on the Company’s assessment of this matter, it has determined that a loss is not currently probable. As a result, no loss accrual is currently recorded under ASC 450. Based on the Company’s assessment, it concluded that it is reasonably possible that the Company may incur a loss and the potential range of loss would be the fees received under the program, which is approximately $20,100 .
The Company has determined that due to the potential risk of refund, all fees received prospectively from continued participation after May 23, 2014 in wholesale energy market demand response programs implemented pursuant to Order 745

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and administered by a RTO or ISO will be deferred until such time as the fees are either refunded or become no longer subject to refund or adjustment. Subsequent to May 23, 2014 through March 31, 2015 , the Company has received and deferred $2,678 of fees related to these programs.
9. Stockholders’ Equity

2014 Long-Term Incentive Plan

On May 29, 2014, the Company’s stockholders approved the EnerNOC, Inc. 2014 Long-Term Incentive Plan (the 2014 Plan). The 2014 Plan provides for the grant of incentive stock options, non-statutory stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, other stock awards, and performance awards that may be settled in cash, stock, or other property.

Subject to adjustment for certain changes in the Company’s capitalization, the total number of shares of the Company’s common stock that may be issued under the 2014 Plan will not exceed 1,941,517 shares plus the number of shares subject to stock awards outstanding under the Company’s Amended and Restated 2007 Employee, Director and Consultant Stock Plan (the 2007 Plan), and the EnerNOC, Inc. Amended and Restated 2003 Stock Option and Incentive Plan (the 2003 Plan) (collectively referred to as the Plans) that (i) expire or otherwise terminate without all of the shares covered by such award having been issued, (ii) are settled in cash, (iii) are forfeited back to or repurchased by the Company because of the failure to meet a contingency or condition required for the vesting of such shares, (iv) are reacquired or withheld (or not issued) by the Company to satisfy the exercise or purchase price of an award (including any shares that are not delivered because such award is exercised through a reduction of shares subject to such award), or (v) are reacquired or withheld (or not issued) by the Company to satisfy a tax withholding obligation in connection with an award.

If a stock award granted under the 2014 Plan expires or otherwise terminates without all of the shares covered by such stock award having been issued, or is settled in cash, such expiration, termination or settlement will not reduce the number of shares of common stock that may be available for issuance under the 2014 Plan, and the unissued shares subject to such stock award will again become available for issuance under the 2014 Plan. If any shares of common stock issued pursuant to a stock award are forfeited back to or repurchased by the Company because of the failure to meet a contingency or condition required to vest such shares, then the shares that are forfeited or repurchased will again become available for issuance under the 2014 Plan. In addition, any shares of common stock reacquired or withheld (or not issued) by the Company in satisfaction of tax withholding obligations on a stock award or as consideration for the exercise or purchase price of a stock award will again become available for issuance under the 2014 Plan. During the period of the effective date of the 2014 Plan through March 31, 2015 , the Company repurchased 254,649 shares to satisfy employee tax withholdings that became available for future grant under the 2014 Plan.

All of the Company’s and its affiliates’ employees, directors and consultants are eligible to participate in the 2014 Plan and may receive all types of awards other than incentive stock options. Incentive stock options may be granted under the 2014 Plan only to the Company’s and its affiliates’ employees (including officers).

As of March 31, 2015 , 1,182,134 shares were available for future grant under the 2014 Plan.
World Energy Solutions, Inc. 2006 Stock Incentive Plan
In connection with the Company’s acquisition of World Energy in January 2015, the Company assumed the World Energy Solutions, Inc. 2006 Stock Incentive Plan (the World Energy Plan). The World Energy Plan provides for the grant of incentive and nonstatutory stock options or stock purchase rights to employees who were employees of World Energy prior to January 5, 2015. A total of 172,930 shares of the Company’s common stock have been reserved for issuance under the World Energy Plan. Of this amount, immediately after the closing of the acquisition, options with respect to 78,413 shares were outstanding and 94,517 stock-based awards were available for future grants to employees of World Energy. The weighted average exercise price for the currently outstanding options is $10.99 .
In connection with the Company’s acquisition of World Energy, options to purchase World Energy common stock that were assumed by the Company were converted into options to purchase the Company's common stock that are subject to the same vesting and other conditions that applied to the World Energy options immediately prior to the acquisition. All such options have a four year vesting schedule. Shares of World Energy common stock underlying restricted stock awards that were not tendered in the acquisition and that were subject to forfeiture risks, repurchase options or other restrictions immediately prior to the acquisition were converted into shares of the Company’s common stock as provided in the merger agreement and remain subject to the same restrictions that applied to the World Energy restricted stock awards immediately prior to the

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acquisition. The terms may be adjusted upon certain events affecting the Company’s capitalization. No awards may be granted under the World Energy Plan after the completion of ten years from August 25, 2006, which is the date on which the World Energy Plan was adopted by the World Energy Board, but awards previously granted may extend beyond that date.

Share Repurchase Program

On August 11, 2014, the Company’s Board of Directors authorized the repurchase of up to $50,000 of the Company’s common stock during the period from August 11, 2014 through August 8, 2015 (the Repurchase Program). The Company used $29,975 of the net proceeds from its Notes offering to repurchase 1,514,552 shares of its common stock at a purchase price of $19.79 per share, which was the closing price of the Common Stock on The NASDAQ Global Select Market on August 12, 2014. Additional repurchases of common stock under the Repurchase Program may be executed periodically on the open market as market and business conditions warrant. During the three months ended March 31, 2015 , the Company did not make any repurchases of its common stock.

The Company withheld 143,164 shares of its common stock during the three months ended March 31, 2015 to satisfy employee minimum statutory income tax withholding obligations in connection with the vesting of restricted stock and restricted stock units under its equity incentive plans, which the Company pays in cash to the appropriate taxing authorities on behalf of its employees. All withheld shares became immediately available for future issuance under the 2014 Plan.

Stock-Based Compensation

The 2003 Plan, the 2007 Plan, the 2014 Plan, and the World Energy Plan (collectively, the Plans) provide for the grant of incentive stock options, nonqualified stock options, restricted and unrestricted stock awards and other stock-based awards to eligible employees, directors and consultants of the Company. Options granted under the Plans are exercisable for a period determined by the Company, but in no event longer than ten years from the date of the grant. Option awards are generally granted with an exercise price equal to the market price of the Company’s common stock on the date of grant. Stock option awards, restricted stock awards and restricted stock unit awards generally vest ratably over four years , with certain exceptions. In addition, during the three months ended March 31, 2015 and 2014 , the Company issued 72,926 and 6,632 shares of its common stock, respectively, to certain executives to satisfy a portion of the Company’s bonus obligations to those individuals.


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Stock Options

The following is a summary of the Company’s stock option activity during the three months ended March 31, 2015 :
 
Three Months Ended March 31, 2015
 
 
Number of
Shares
Underlying
Options
 
Exercise
Price Per
Share
 
Weighted-
Average
Exercise Price
Per Share
 
Aggregate
Intrinsic
Value
 
Outstanding at December 31, 2014
725,578

 
$0.35 - $43.38
 
$
18.01

 
$
2,978

(2)
Granted
78,413

 
 
 
10.99

 
 
 
Exercised
(97,824
)
 
 
 
10.39

 
728

(3)
Cancelled
(4,845
)
 
 
 
19.78

 
 
 
Outstanding at March 31, 2015
701,322

 
$0.35 - $43.38
 
$
18.27

 
$
1,684

(4)
Weighted average remaining contractual life in years: 2.9
 
 
 
 
 
 
 
 
Exercisable at end of period
626,330

 
$0.35 - $43.38
 
$
19.06

 
$
1,617

(4)
Weighted average remaining contractual life in years: 2.5
 
 
 
 
 
 
 
 
Vested or expected to vest at March 31, 2015 (1)
695,623

 
$0.35 - $43.38
 
$
18.27

 
$
1,679

(4)
 
(1)
This represents the number of vested options as of March 31, 2015 plus the number of unvested options expected to vest as of March 31, 2015 based on the unvested options outstanding at March 31, 2015 , adjusted for the estimated forfeiture rate of 7.6% .
(2)
The aggregate intrinsic value was calculated based on the positive difference between the estimated fair value of the Company’s common stock on December 31, 2014 of $15.45 and the exercise price of the underlying options.
(3)
The aggregate intrinsic value was calculated based on the positive difference between the fair value of the Company’s common stock on the applicable exercise dates and the exercise price of the underlying options.
(4)
The aggregate intrinsic value was calculated based on the positive difference between the estimated fair value of the Company’s common stock on March 31, 2015 of $11.40 and the exercise price of the underlying options.
The weighted average fair value per share of options granted was $9.92 .

Of the stock options outstanding as of March 31, 2015 , all 701,322 options were held by employees and directors of the Company. For outstanding unvested stock options as of March 31, 2015 , the Company had $695 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.1 years.

Restricted Stock

The following table summarizes the Company’s restricted stock activity during the three months ended March 31, 2015 :
 
Number of
Shares
 
Weighted Average
Grant Date Fair
Value Per Share
Nonvested at December 31, 2014
2,170,267

 
$
17.18

Granted
660,296

 
11.76

Vested
(313,244
)
 
17.21

Cancelled
(68,223
)
 
15.77

Nonvested at March 31, 2015
2,449,096

 
$
15.80


During three months ended March 31, 2015 , 10,500 shares of restricted stock were granted to certain non-executive employees which were immediately vested. No shares of restricted stock were granted to members of the Company's board of directors during the three months ended March 31, 2015 . During the year ended December 31, 2014, 11,750 shares of restricted stock were granted to certain non-executive employees and 31,365 shares of restricted stock were granted to members of the Company’s board of directors, all of which were immediately vested.


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No shares of restricted stock were granted to non-employees during the three months ended March 31, 2015 . During the year ended December 31, 2013, the Company granted 33,000 shares of restricted stock to non-employee advisory board members. Of the 33,000 shares of restricted stock granted, 22,000 shares of restricted stock vest ratably on a quarterly basis over four years and 11,000 shares of restricted stock vest in equal annual tranches on July 1, 2014 and July 1, 2015, as long as the individuals continue to serve as advisory board members through the date of the applicable vesting. During the three months ended March 31, 2015 and 2014 , the Company recorded stock-based compensation expense related to these awards of $3 and $88 , respectively. As of March 31, 2015 , 17,875 shares were unvested and had a fair value of $204 .

In July 2014, the Company’s board of directors approved a modification to certain non-executive employee’s share-based awards to provide for acceleration of vesting upon a change in control accompanied by certain other actions. This modification affected 436,415 shares of non-vested restricted stock and 1,890 unvested stock options to purchase the Company’s common stock. This modification resulted in a new measurement date which increased the fair value of these awards by $590 . This incremental fair value will be recorded only if these individuals vest as a result of this modification. If these individuals vest in accordance with the original vesting terms, no incremental stock-based compensation expense will be recorded.

For non-vested restricted stock subject to service-based vesting conditions outstanding as of March 31, 2015 , the Company had $23,816 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.9 years. For non-vested restricted stock subject to performance-based vesting conditions outstanding that were probable of vesting as of March 31, 2015 , which represents all of the outstanding non-vested restricted stock subject to performance-based vesting conditions, the Company had $4,124 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 1.7 years.

Additional Information About Restricted Stock
 
Three Months Ended
March 31,
 
2015
 
2014
 
In thousands, except share and per
share amounts
Total number of shares of restricted stock granted during the period
660,296

 
491,899

Weighted average fair value per share of restricted stock granted
$
11.76

 
$
20.94

Total number of shares of restricted stock vested during the period
313,244

 
694,401

Total fair value of shares of restricted stock vested during the period
$
5,391

 
$
15,103

Restricted Stock Units

The following table summarizes the Company’s restricted stock unit activity during the three months ended March 31, 2015 :
 
Number of
Shares
 
Weighted Average
Grant Date Fair
Value Per Share
Nonvested at December 31, 2014
256,872

 
$
20.08

Granted
36,250

 
10.74

Vested
(3,126
)
 
18.84

Cancelled
(24,408
)
 
20.11

Nonvested at March 31, 2015
265,588

 
$
18.81


During the year ended December 31, 2014, the Company granted 250,382 shares of non-vested restricted stock units that contain performance-based vesting conditions to certain non-executive German employees in connection with its acquisition of Entelios. Of these shares, up to 10% vest in 2015 if the performance criteria related to certain 2014 operating results are achieved and the employee is still employed as of the vesting date, up to 20% vest in 2016 if the performance criteria related to certain 2015 operating results are achieved and the employee is still employed as of the vesting date, and up to the remaining 70% of the shares vest in 2017 if the performance criteria related to certain 2016 operating results are achieved and the employee is still employed as of the vesting date. For the year ended December 31, 2014, the performance criteria was not met

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and as a result 24,408 shares were forfeited during the three months ended March 31, 2015 . If the performance criteria related to certain 2015 and 2016 operating results are not achieved, 100% of the remaining 219,714 shares granted will be forfeited. As of March 31, 2015 , the awards have not been deemed probable of vesting.

For non-vested restricted stock units subject to service-based vesting conditions outstanding as of December 31, 2014, the Company had $496 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 3.3 years. For non-vested restricted stock units subject to outstanding performance-based vesting conditions that were not probable of vesting at March 31, 2015 , the Company had $4,418 of unrecognized stock-based compensation expense. If and when any additional portion of these non-vested restricted stock units are deemed probable to vest, the Company 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.
Additional Information About Restricted Stock Units
 
Three Months Ended
March 31,
 
2015
 
2014
 
in thousands, except share and per
share amounts
Total number of shares of restricted stock units vested during the period
3,126

 
34,250

Total fair value of shares of restricted stock units vested during the period
$
59

 
$
772

10. Income Taxes
The Company has recorded a $2,285 worldwide tax benefit for the three months ended March 31, 2015. The tax benefit consists of a tax benefit on its foreign losses for the quarter and a U.S. tax expense related to tax deductible goodwill that generates a deferred tax liability that cannot be used as a source of income against which deferred tax assets may be realized. The benefit for income taxes for the three months ended March 31, 2015 also includes a $2,268 benefit from income taxes due to the release of a portion of the U.S. valuation allowance in connection with the World Energy acquisition.
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. During the three month period ended March 31, 2015, there were no material changes in the Company’s uncertain tax positions.
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 effective tax rate for the full fiscal year and use that rate to provide for income taxes on a current year-to-date basis. However, if an enterprise is unable to make a reliable estimate of its annual effective tax rate, the actual effective tax rate for the year-to-date period may be the best estimate of the annual effective tax rate. The Company is able to reliably estimate the annual effective tax rate on its foreign earnings, but is unable to reliably estimate the annual effective tax rate on its U.S. earnings.
If the Company is able to make a reliable estimate of its U.S. annual effective tax rate as of June 30, 2015, the Company expects to provide for income taxes on a current year-to-date basis. If the Company continues to be unable to make a reliable estimate of its annual effective tax rate as of June 30, 2015, the Company expects to provide for income taxes using a consistent methodology as was applied for the three month period ended March 31, 2015.
The Company reviews all available evidence to evaluate the recovery of deferred tax assets, including the recent history of losses in all tax jurisdictions, as well as its ability to generate income in future periods. As of March 31, 2015, due to the uncertainty related to the ultimate use of certain deferred income tax assets, the Company has recorded a valuation allowance on certain of its deferred tax assets.
11. Concentrations of Credit Risk
Financial instruments that potentially subject the Company to significant concentrations of credit risk principally consist of cash and cash equivalents, restricted cash, and accounts receivable and unbilled revenue. The Company maintains its cash and cash equivalent balances with highly rated financial institutions and as a result, such funds are subject to minimal credit risk.

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The Company's significant customers consist of PJM Interconnection (PJM) and Independent Market Operator (IMO). PJM is an electric power grid operator customer in the mid-Atlantic region of the United States that is comprised of multiple utilities and was formed to control the operation of the regional power system, coordinate the supply of electricity, and establish fair and efficient markets. IMO is an entity that was established to administer and operate the Western Australia (WA) wholesale electricity market. The main objectives of the IMO are to coordinate the supply of electricity, encourage competition in the market, establish fair and efficient markets, and ensure economic supply of electricity to customers in WA. No other customers comprised more than 10% of consolidated revenues during the three months ended March 31, 2015 and 2014 .
The following table presents the Company’s significant customers.
 
Three Months Ended March 31,
 
2015
 
2014
 
Revenues
 
% of Total
Revenues
 
Revenues
 
% of Total
Revenues
PJM
*

 
*

 
$
18,218

 
35
%
IMO
$
7,279

 
14
%
 
*

 
*

* Represents less than 10% of total revenues.
 
 
 
 
 
 
 
 
PJM and IMO were the only customers that comprised 10% or more of the Company’s accounts receivable balance at March 31, 2015 , representing 19% , and 11% , respectively. PJM, Southern California Edison Company and IMO were the only customers that each comprised 10% or more of the Company’s accounts receivable balance at December 31, 2014 , representing 21% , 17% and 12% , respectively.
Unbilled revenue related to PJM was $38,950 and $96,404 at March 31, 2015 and December 31, 2014 , respectively. There was no significant unbilled revenue for any other customers at March 31, 2015 and December 31, 2014 .
Deposits consist of funds to secure performance under certain contracts and open market bidding programs with electric power grid operator and utility customers. Deposits held by these customers were $1,363 and $3,033 at March 31, 2015 and December 31, 2014 , respectively.
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 Company’s consolidated financial condition, results of operations or cash flows.
On May 3, 2013, a purported shareholder of the Company’s, or the plaintiff, filed a derivative and class action complaint in the United States District Court for the District of Delaware, or the Court, against certain of Company’s officers and directors as well as the Company as a nominal defendant, which the Company refers collectively to as the defendants. The complaint asserted derivative claims, purportedly brought on behalf of the Company, for breach of fiduciary duty, waste of corporate assets, and unjust enrichment in connection with certain equity grants (awarded in 2010, 2012, and 2013) that allegedly exceeded an annual limit on per-employee equity grants purported to be contained in the 2007 Plan. The complaint also asserted a direct claim, brought on behalf of the plaintiff and a proposed class of the Company’s shareholders, alleging the Company’s proxy statement filed on April 26, 2013 was false and misleading because it failed to disclose that the equity grants were improper. The plaintiff sought, among other relief, rescission of the equity grants, unspecified damages, injunctive relief, disgorgement, attorneys’ fees, and such other relief as the Court may deem proper.
On June 27, 2014, the parties engaged in mediation and reached agreement in principle on the terms of a potential settlement. On December 15, 2014, the Court held a fairness hearing and approved the settlement, together with an award of attorneys’ fees to plaintiffs’ counsel in the amount of $400 , a portion of which was covered by the Company’s insurance. Pursuant to the settlement, defendant members of the Company’s Board of Directors agreed to cause the Company’s insurer to make a cash payment of $500 to the Company, and to cause the Company to undertake certain reforms in connection with equity granting practices. The cash payment of $500 was received and recognized in January 2015.
On November 6, 2014, a class action lawsuit was filed in the Delaware Court of Chancery against the Company, World Energy, Wolf Merger Sub Corporation, and members of the board of directors of World Energy arising out of the merger between the Company and World Energy. The lawsuit generally alleged that the members of the board of directors of World Energy breached their fiduciary duties to World Energy’s stockholders by entering into the merger agreement because they, among other things, failed to maximize stockholder value and agreed to preclusive deal-protection terms. The lawsuit also

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alleged that the Company and World Energy aided and abetted the board of directors of World Energy in breaching their fiduciary duties. The plaintiff sought to stop or delay the acquisition of World Energy by the Company, or rescission of the merger in the event it is consummated, and seeks monetary damages in an unspecified amount to be determined at trial. The parties engaged in settlement negotiations and on December 24, 2014, without admitting, but expressly denying any liability on behalf of the defendants, the parties entered into a memorandum of understanding (MOU) regarding a proposed settlement to resolve all allegations. The MOU was filed in the Delaware Court of Chancery on December 24, 2014. Among other things, the MOU provides that, in consideration for a release and the dismissal of the litigation, World Energy would include additional disclosures in a Form SC 14D9-A to be filed with the SEC no later than December 24, 2014. The MOU also provided that the litigation, including the preliminary injunction hearing, be stayed. The merger closed on January 5, 2015. On March 26, 2015, the parties executed and filed with the Delaware Chancery Court a formal stipulation of settlement. The Company has recognized an obligation of $300 in connection with the settlement. The Delaware Chancery Court has scheduled a hearing to be held on June 30, 2015 to consider whether to approve the settlement. There can be no assurance that the stipulation of settlement will be finalized or that the Delaware Court of Chancery will approve the settlement.
13. Recent Accounting Pronouncements
In April 2014, the Financial Accounting Standards Board, or FASB, issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (ASU 2014-08). ASU 2014-08 amends the definition of discontinued operations under ASC 205-20 to only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements. This guidance is effective for all disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. The Company early adopted this guidance as of January 1, 2014. The adoption of this guidance did not have a material impact on the Company's financial condition or results of operations.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 provides guidance for revenue recognition and the standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The new guidance was effective for annual and interim periods beginning after December 15, 2016, with no early adoption permitted. The FASB voted on April 1, 2015 to propose a deferral of the effective date by one year. With the deferral, ASU No 2014-09 will be effective for the Company beginning in the first quarter of fiscal year 2018, and allows for full retrospective adoption applied to all periods presented or retrospective adoption with the cumulative effect of initially applying this update recognized at the date of initial application. The Company has not yet determined the method of adoption. The Company is currently in the process of evaluating the impact of adoption of this ASU on its consolidated financial position and results of operations.

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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, 2014 , as filed with the Securities and Exchange Commission, or the SEC, on March 12, 2015, and as amended on March 13, 2015, or our 2014 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,” “likely,” “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 2014 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 intelligence software, or EIS, and related solutions. Our enterprise customers use our software to transform how they manage and control spend for their organizations, while utilities leverage our software to better engage their customers and meet their demand-side management goals and objectives.
Our EIS and related solutions provide our enterprise customers with a Software-as-a-Service, or SaaS, solution to manage:
energy supplier selection, procurement and implementation;
energy budget forecasting;
utility bills and payment;
facility optimization, including the measurement, tracking, analysis and reporting on greenhouse gas emissions;
project tracking;
demand response, both in open and vertically-integrated markets; and
peak demand and the related cost impact.
Our EIS and related solutions provide our enterprise customers the visibility they need to prioritize resources against the activities that will deliver the highest return on investment. We offer our EIS and related solutions to our enterprise customers at four subscription levels: basic, standard, professional, and industrial. We deliver our SaaS solutions on all of the major Internet browsers and on leading mobile device operating systems. In addition to our EIS packages, we sell two categories of premium professional services, which we refer to as Software Enhancement Services and Energy and Procurement Services. Our Software Enhancement Services help our enterprise customers set their energy management strategy and enhance the effectiveness of EIS deployment. Our Energy and Procurement Services consist of audits, retro-commissioning, and supply procurement consulting. Our target enterprise customers for our EIS and related solutions are organizations that spend approximately $100 thousand/year or more per site on energy, and we sell to these customers primarily through our direct salesforce.
Our EIS for utilities is a SaaS solution that provides utilities with customer engagement, energy efficiency and demand response applications, while improving operational effectiveness. We deliver shared value for both the utility and its customers by combining our deep expertise with enterprise customers with energy data analytics, machine learning, and predictive algorithms to deliver segmentation and targeting capabilities that enable utilities to serve their most complex market segments, including commercial, institutional and industrial end-users of energy, and small and medium-sized enterprises. Our EIS and related solutions provide our utility customers with a cost-effective and holistic solution that improves customer satisfaction

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ratings, delivers savings and consumption reductions to achieve energy efficiency mandates, manages system peaks and grid constraints, and increases demand for utility-provided products and services.
Our EIS and related solutions for utility customers and electric power grid operators also include the demand response solutions and applications, EnerNOC Demand Manager™ and EnerNOC Demand Resource™. EnerNOC Demand Manager is a SaaS application that provides utilities with the underlying technology to manage their demand response programs and secure reliable demand-side resources. Our EnerNOC Demand Manager product consists of long-term contracts with a utility customer for a SaaS solution that allows utilities to manage demand response capacity in utility-sponsored demand response programs. This product provides our utility customers with real-time load monitoring, dispatching applications, customizable reports, measurement and verification, and other professional services. Our EnerNOC Demand Resource is a turnkey demand response resource where we match obligation, in the form of megawatts, or MW, that we agree to deliver to our utility customers and electric power grid operators, with supply, in the form of MW that we are able to curtail from the electric power grid through our arrangements with our enterprise customers. When we are called upon by our utility customers and electric power grid operators to deliver our contracted capacity, we use our NOC to remotely manage and reduce electricity consumption across our growing network of enterprise customer sites, making demand response capacity available to our utility customers and electric power grid operators on demand while helping our enterprise customers achieve energy savings, improve financial results and realize environmental benefits. We receive recurring payments from our utility customers and electric power grid operators for providing our EnerNOC Demand Resource and we share these recurring payments with our enterprise customers in exchange for those enterprise customers reducing their power consumption when called upon by us to do so. We occasionally reallocate and realign our capacity supply and obligation through open market bidding programs, supplemental demand response programs, auctions or other similar capacity arrangements and third-party 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.
Since inception, our business has grown substantially. We began by providing our demand response solutions in one state in the United States in 2003 and have expanded to providing our EIS and related solutions throughout the United States, as well as internationally in Australia, Brazil, Canada, China, Germany, India, Ireland, Japan, New Zealand, South Korea and the United Kingdom.


Use of Non-Financial Business and Operational Data
We utilize certain non-financial business and operational data to provide additional insight into factors and opportunities relevant to our business. This non-financial business and operational data does not necessarily have any direct correlation to our financial performance. However, the non-financial business and operational data may provide observations as to the scope of and trends related to our operations and therefore, we believe the utilization of such data can provide insights into certain aspects of our business, such as market share and penetration, and customer composition and depth.
The following table outlines certain non-financial business and operational data utilized as of and for the three months ended March 31, 2015 and as of and for the year ended December 31, 2014 :
 
March 31, 2015
 
December 31, 2014
Enterprise Customers(1)(7)
4,400

 
1,300

Enterprise Sites(1)(7)
71,800

 
35,700

Enterprise ARR (in millions)(2)(8)
$
55

 
$
20

Enterprise ARR Churn Rate(2)(9)
11
%
 
18
%
Enterprise ARR Net Churn Rate (2)(9)
6
%
 
15
%
Utility Customers(3)
52

 
52

Utility ARR (in millions)(4)(8)
$
67

 
$
67

Utility ARR Churn Rate(4)(9)
13
%
 
13
%
Utility ARR Net Churn Rate(4)(9)
8
%
 
10
%
Grid Operators(5)
14

 
14

Demand Response Customers(6)(7)
6,500

 
6,500

Demand Response Sites(6)(7)
15,200

 
15,000

 
(1) The term “Enterprise Customers,” which we formerly referred to as “C&I Customers Under Enterprise Revenue Contracts,” describes the number of our customers that purchase our EIS and related solutions for enterprises. By extension, the term “Enterprise Sites,” which we previously referred to as “C&I Sites Under Enterprise Revenue

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Contracts,” describes the number of sites across our Enterprise Customer base that purchase our EIS and related solutions for enterprises.
(2) The term “Enterprise ARR” describes the annual recurring revenue from our contracts with Enterprise Customers, defined as all contracted subscription revenue, exclusive of non-recurring or one-time fees, from Enterprise Customers under active (non-expired or terminated) contracts at period end, normalized for a one year period regardless of payment mechanism or timing. Non-recurring or one-time fees include fees related to site installation or set-up, discrete consulting or project based fees, and non-recurring professional services fees. By extension, the term “Enterprise ARR Churn Rate” describes the Enterprise ARR lost over the trailing four quarter period for any reason including, but not limited, to non-renewal, early termination, or ongoing non-payment, as a percentage of the starting Enterprise ARR value over the trailing four quarter period. The term “Enterprise ARR Net Churn Rate” describes the loss of Enterprise ARR from Enterprise Customers that were purchasing our EIS and related solutions at the start of the trailing four quarter period, inclusive of changes to Enterprise ARR from renewal or upsell activity to these Enterprise Customers, as a percentage of the starting Enterprise ARR value over the trailing four quarter period.
(3) The term “Utility Customers” describes the number of our customers that purchase our EIS and related solutions for utilities.
(4) The term “Utility ARR” describes the annual recurring revenue from our contracts with Utility Customers, defined as all contracted subscription revenue, exclusive of non-recurring or one-time fees, from Utility Customers under active (non-expired or terminated) contracts at period end, normalized for a one year period regardless of payment mechanism or timing. Non-recurring or one-time fees include fees related to product set-up, discrete consulting or project based fees, variable demand response energy payments, and non-recurring professional services fees. By extension, the term “Utility ARR Churn Rate” describes the Utility ARR lost over the trailing four quarter period for any reason including, but not limited to non-renewal, early termination, demand response customer attrition, or ongoing non-payment, as a percentage of the starting Utility ARR value over the trailing four quarter period. The term “Utility ARR Net Churn Rate” describes the loss of Utility ARR from Utility Customers that were purchasing our EIS and related solutions at the start of the trailing four quarter period, inclusive of changes to ARR from renewal or upsell activity to these customers, as a percentage of the starting Utility ARR value over the trailing four quarter period.
(5) The term “Grid Operators,” which we formerly referred to as “Grid Operator Customers,” describes the number of operators of competitive wholesale electricity markets that rely on our demand response programs to manage load on their grid. We enter into contractual commitments with these grid operators through participation in open market auctions, as well as, negotiated contractual arrangements for the express purpose of optimizing load on their grid when called upon, or dispatched, to do so.
(6) The term “Demand Response Customers,” which we formerly referred to as C&I Customers Participating in Demand Response,” describes the number of our enterprise customers under contract to participate in our demand response programs. By extension, the term “Demand Response Sites,” which we formerly referred to as “C&I Sites Participating in Demand Response,” describes the number of sites across our Demand Response Customer base under contract to participate in our demand response programs. Certain of these customers and sites may additionally use our EIS and related solutions.
(7) Amounts rounded to nearest hundred.
(8) Amounts rounded to nearest million.
(9) Amounts rounded to nearest full percentage point.
The number of enterprise customers at March 31, 2015 was approximately 4,400 compared to approximately 1,300 at December 31, 2014 . This increase primarily reflects the addition of new customers from our acquisition of World Energy Solutions, Inc., or World Energy. This increase also reflects our ongoing efforts to develop our enterprise sales team, the relative success that our enterprise sales team has had in penetrating the market for our EIS and related solutions for enterprises, and the growing need for our solutions with enterprise customers who are increasingly turning to our EIS and related solutions to make strategic decisions about the how and when they consume or procure energy. The number of enterprise sites at March 31, 2015 was approximately 71,800 compared to approximately 35,700 at December 31, 2014. The number of enterprise sites has typically increased in tandem with the increase in enterprise customers, with most of the increase in sites coming from our acquisition of World Energy. Enterprise ARR at March 31, 2015 was approximately $55 million compared to approximately $20 million at December 31, 2014. Enterprise ARR has typically increased in tandem with the increase in enterprise sites, with the increase coming from our acquisition of World Energy and our organic growth. We expect that the number of enterprise customers, the number of enterprise sites, and enterprise ARR will generally increase over time, but enterprise customers and sites may decrease in the near term as we select not to renew certain smaller or unprofitable customers acquired through our acquisition of World Energy. Our enterprise ARR churn rate was 11% at March 31, 2015 compared to 18% at December 31, 2014. Our enterprise ARR net churn rate was 6% at March 31, 2015 compared to 15% at December 31, 2014.

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The number of utility customers at March 31, 2015 was 52, consistent with the number of utility customers at December 31, 2014. Utility ARR at March 31, 2015 was approximately $67 million consistent with Utility ARR at December 31, 2014. This reflects an increase in size of certain utility software contracts offset by a reduction in size or non-renewal of certain utility demand response programs. Our utility ARR churn rate was 13% at March 31, 2015 compared to 13% at December 31, 2014. Our utility ARR net churn rate was 8% at March 31, 2015 compared to 10% at December 31, 2014. In general, we expect that the number of utility customers and utility ARR will increase over time and that our utility ARR churn rate and utility ARR net churn rate will fluctuate in future periods depending on the timing and terms of our utility contracts.
The number of grid operators at March 31, 2015 was 14, consistent with the number of grid operators at December 31, 2014. In general, we expect that the number of grid operators will remain the same or moderately increase over time.
The number of demand response customers was approximately 6,500 at March 31, 2015, consistent with the number of demand response customers at December 31, 2014. The number of demand response sites at March 31, 2015 was approximately 15,200 as compared to approximately 15,000 at December 31, 2014. The number of demand response customers and the number of demand response sites are not necessarily correlated and may increase or decrease in future periods if we choose to participate in additional or different markets in the future.
We continually evaluate the non-financial business and operational data that we review and the relevance of this data as our business continues to evolve and, as a result, such data and information may change over time.
Consolidated Results of Operations
Three Months Ended March 31, 2015 Compared to the Three Months Ended March 31, 2014
Revenues
The following table summarizes our revenues for the three months ended March 31, 2015 and 2014 ( in thousands):
 
Three Months Ended March 31,
 
Dollar
 
Percentage
 
2015
 
2014
 
Change
 
Change
Revenues:
 
 
 
 
 
 
 
Grid operator
$
23,713

 
$
35,770

 
$
(12,057
)
 
(33.7
)%
Utility
10,781

 
10,309

 
472

 
4.6
 %
Enterprise
16,057

 
6,429

 
9,628

 
149.8
 %
Total
$
50,551

 
$
52,508

 
$
(1,957
)
 
(3.7
)%

Grid Operator Revenues
The overall decrease in our revenues from grid operators was primarily attributable to changes in the following existing operating areas (dollars in thousands):
 
Increase (Decrease)
 
Three Months Ended
March 31, 2014 to
March 31, 2015
PJM
$
(18,056
)
Independent Market Operator, or IMO
7,279

Alberta Electric System Operator (AESO)
(1,540
)
Single Energy Market Operator, or SEMO (Ireland)
907

Other (1)
(647
)
Total decrease in grid operator revenues
$
(12,057
)
 
(1)
The amounts included in ‘other’ relate to net decreases in various demand response programs, domestic and international, none of which are individually material.
The decrease in revenues from grid operators during the three month period ended March 31, 2015 as compared to the same period in 2014 was primarily due to a decrease in energy payments from PJM resulting from no demand response event dispatches in the first quarter of 2015 compared to a significant number of PJM demand response event dispatches during the first quarter of 2014 related to the polar vortex. In addition, the decrease in revenues was also due to our continued deferral of revenues related to our participation in the PJM Economic program pending final resolution of FERC Order 745 (see Note 8

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contained in Part I to this Quarterly Report on Form 10-Q), as well as a decrease in pricing and enrolled MW in certain demand response programs in Alberta, Canada. This decrease in revenue was partially offset by an increase in IMO revenue resulting from our ability to recognize revenues in Western Australia ratably over the delivery period of October 1 through September 30, which commenced on October 1, 2014, as well as an increase in revenues recognized from our participation in the SEMO demand response program in Ireland during the three month period ended March 31, 2015 as compared to the same period in 2014 . We currently expect our total revenues from grid operators to decrease during fiscal 2015 as compared to fiscal 2014 due to significantly reduced capacity prices in IMO, lower revenue from our participation in PJM incremental auctions and deferral of revenue recognition to the second quarter of 2016 relating to our participation in PJM’s extended program in the 2015/2016 delivery year.
Utility Revenues
The overall increase in our revenues from utilities was primarily attributable to changes in the following (in thousands):
 
Increase (Decrease)
 
Three Months Ended
March 31, 2014 to
March 31, 2015
Pulse Energy, Inc. (Pulse Energy)
$
1,048

Utility Consulting Solutions (UCS)
(1,021
)
Other (1)
445

Total increase in utility revenues
$
472

 
(1)
The amounts included in ‘Other’ relate to various demand response programs, none of which are individually material.
The increase in utility revenues was primarily due an increase in utility revenues related to Pulse Energy Inc., or Pulse Energy, which we acquired in the fourth quarter of 2014. This increase was partially offset by a decrease in utility revenues related to the divestiture of our utility consulting business in the second quarter of 2014. We currently expect our fiscal 2015 utility revenues to grow between 13%-21% as compared to fiscal 2014 primarily due to the utility contracts acquired with Pulse Energy, expansion of existing utility customer contracts and the sale of our EIS solution to new utility customers.
 
Enterprise Revenues
The increase in enterprise revenues recognized during the three months ended March 31, 2015 related to our procurement solutions, which we expanded as part of our acquisition of World Energy Solutions, Inc., or World Energy, in the first quarter of 2015 and our utility bill management solutions, which we acquired as part of our acquisition of EnTech in the second quarter of 2014, as well as an increase in both the number of enterprise customers and overall consulting engagements. The increase in enterprise revenues was partially offset by a decrease in enterprise revenues resulting from the completion in August 2014 of our 2010 agreement with the Massachusetts Department of Energy Resources. We currently expect our fiscal 2015 enterprise revenues to grow between 70%-83% as compared to fiscal 2014 due to the acquisition of World Energy, expansion of existing enterprise customer contracts and the sale of our EIS solution to new enterprise customers.
Gross Profit and Gross Margin
The following table summarizes our gross profit and gross margin percentages for our EIS and related solutions for the three months ended March 31, 2015 and 2014 (dollars in thousands):
Three Months Ended March 31,
2015
 
2014
Gross Profit
 
Gross Margin
 
Gross Profit
 
Gross Margin
$
18,595

 
36.8
%
 
$
16,369

 
31.2
%

The increase in gross profit was primarily due to an increase in enterprise revenues and changes in our overall enterprise customer composition resulting from the acquisitions of World Energy and Entech. The increase in gross margin was primarily a result of a decrease in grid operator revenues from the delivery of our demand response solution, which historically yields a lower gross margin than our EIS and other related solutions.

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We expect that our overall gross margin percentage for fiscal 2015 will be in the low to mid 40% range. This anticipated decrease in gross margin percentage compared to fiscal 2014 is expected to result primarily from pressure on margins in our grid operator business and decreased profits from our participation in PJM incremental auctions. We expect this decrease will be partially offset by revenue growth from our higher margin enterprise and utility businesses.
Operating Expenses
The following table summarizes our operating expenses for the three months ended March 31, 2015 and 2014 (in thousands):
 
Three Months Ended March 31,
 
Percentage
 
2015
 
2014
 
Change
 
 
 
 
 
 
Selling and marketing
$
28,496

 
$
18,499

 
54.0
%
General and administrative
28,289

 
23,677

 
19.5
%
Research and development
7,451

 
5,175

 
44.0
%
     Total operating expenses
$
64,236

 
$
47,351

 
35.7
%

Selling and Marketing Expenses
The following table summarizes our selling and marketing expenses for the three months ended March 31, 2015 and 2014 (in thousands):
 
Three Months Ended March 31,
 
Percentage
 
2015
 
2014
 
Change
 
 
 
 
 
 
Payroll and related costs
$
17,284

 
$
12,107

 
42.8
%
Stock-based compensation
1,643


1,193

 
37.7
%
Other
9,569

 
5,199

 
84.1
%
     Total selling and marketing expenses
$
28,496

 
$
18,499

 
54.0
%
The increase in payroll and related costs was primarily due to an increase in the number of selling and marketing full-time employees from 244 at March 31, 2014 to 375 at March 31, 2015 , most of which resulted from acquisitions that we completed during 2014 and our acquisition of World Energy in January 2015. In addition, we experienced an increase in commission expense during the first quarter of 2015 related to our increase in enterprise revenues.
The increase in stock-based compensation expense was primarily due to the immediate recognition of $0.2 million for replacement awards issued in connection with the acquisition of World Energy during the three month period ended March 31, 2015. Stock-based compensation expense additionally increased during the three month period ended March 31, 2015 compared to the three month period ended March 31, 2014 due to an increased number of share-based payment awards granted to employees acquired in connection with fiscal 2014 acquisitions.
Other selling and marketing expenses include advertising, marketing, professional services, amortization and a company-wide overhead cost allocation. The increase in other selling and marketing expenses was primarily attributable to a $1.8 million increase in various marketing initiatives, a $1.2 million increase in amortization expense of acquired intangible assets as a result of our 2014 and 2015 acquisitions, and a $1.1 million increase in overhead, which is based on increased headcount and information technology and communication costs.

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General and Administrative Expenses
The following table summarizes our general and administrative expenses for the three months ended March 31, 2015 and 2014 (in thousands):
 
Three Months Ended March 31,
 
Percentage
 
2015
 
2014
 
Change
 
 
 
 
 
 
Payroll and related costs
$
17,749

 
$
13,446

 
32.0
 %
Stock-based compensation
2,430


2,696

 
(9.9
)%
Other
8,110

 
7,535

 
7.6
 %
     Total general and administrative expenses
$
28,289

 
$
23,677

 
19.5
 %
The increase in payroll and related costs was primarily attributable to an increase in the number of general and administrative full-time employees from 403 at March 31, 2014 to 520 at March 31, 2015 , most of which resulted from acquisitions that we completed during 2014 and our acquisition of World Energy in 2015.
The decrease in stock-based compensation expense was primarily due to the timing of annual grants issued to the Company’s board of directors, as the Company granted fully-vested share-based payment awards to its board of directors during the three month period ended March 31, 2014 and did not grant similar awards during the three month period ended March 31, 2015, resulting in a decrease of $0.7 million in stock-based compensation expense. This decrease was partially offset by the immediate recognition of $0.3 million for replacement awards issued in connection with the acquisition of World Energy during the three month period ended March 31, 2015. The remaining decrease of $0.1 million was primarily due to a decrease in the grant date fair value of stock-based awards granted subsequent to the three month period ended March 31, 2014.
Other general and administrative expenses include professional services, rent, depreciation and a company-wide overhead cost allocation. The increase in other general and administrative expenses was primarily attributable to a $0.8 million increase in rent expense related to our 2014 acquisitions and the 2014 lease amendment related to our corporate headquarters. Also contributing to the increase in other general and administrative expenses is a $0.4 million increase in direct and incremental expenses related to acquisitions or divestitures, as well as a $0.4 million increase in amortization expense related to acquired intangible assets related to our 2014 and 2015 acquisitions. The increase in other general and administrative expenses was partially offset by a $1.2 million decrease in professional services due to the number of acquisition related fees during the three months ended March 31, 2014 as compared to 2015.
Research and Development Expenses
The following table summarizes our research and development expenses for the three months ended March 31, 2015 and 2014 (dollars in thousands):
 
Three Months Ended March 31,
 
Percentage
 
2015
 
2014
 
Change
 
 
 
 
 
 
Payroll and related costs
$
4,494

 
$
3,154

 
42.5
 %
Stock-based compensation
336


338

 
(0.6
)%
Other
2,621

 
1,683

 
55.7
 %
     Total research and development expenses
$
7,451

 
$
5,175

 
44.0
 %
During the periods ended March 31, 2015 and 2014, total research and development payroll costs totaled $5.3 million and $3.8 million, respectively, of which $0.8 million and $0.7 million, respectively, were capitalized. These capitalized costs are typically amortized over a three year period in cost of revenues. The increase in payroll and related costs was primarily driven by an increase in the number of research and development full-time employees from 109 at March 31, 2014 to 179 at March 31, 2015 and an increase in salary rates per full-time employee.
Other research and development expenses include technology expenses, professional services, facilities and a company-wide overhead cost allocation. The increase in other research and development expenses was primarily attributable to an increase of $0.4 million in the allocation of company-wide overhead costs, which is based on increased headcount, information technology and communication costs of $0.3 million, and consulting and professional fees of $0.2 million.

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Interest Expense and Other (Expense) Income, Net
Interest expense was $2.3 million for the three months ended March 31, 2015 compared to $0.5 million for the three months ended March 31, 2014 . This increase was largely due to interest expense recorded on our convertible senior notes due August 2019, or the Notes, which was $2.0 million for the three months ended March 31, 2015 .
Other expense, net for the three months ended March 31, 2015 was $4.7 million , which primarily includes foreign currency losses offset partially by other income. The $5.2 million decrease as compared to the three months ended March 31, 2014 was primarily due to decreased fluctuations to the U.S. dollar in the Canadian dollar, and Euro, which resulted in a foreign currency loss of ($5.0) million for the three months ended March 31, 2015 , as compared to $(0.4) million loss for the three months ended March 31, 2014 . We currently do not hedge any of our foreign currency transactions.
Income Taxes
We recorded a $2.3 million worldwide tax benefit for the three months ended March 31, 2015. The tax benefit consists of a tax benefit on our foreign losses for the quarter and a U.S. tax expense related to tax deductible goodwill that generates a deferred tax liability that cannot be used as a source of income against which deferred tax assets may be realized. The benefit for income taxes for the three months ended March 31, 2015 also includes a $2.3 million benefit from income taxes due to the release of a portion of the U.S. valuation allowance in connection with the World Energy acquisition.

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. During the three month period ended March 31, 2015, there were no material changes in our uncertain tax positions.
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 effective tax rate for the full fiscal year and use that rate to provide for income taxes on a current year-to-date basis. However, if an enterprise is unable to make a reliable estimate of its annual effective tax rate, the actual effective tax rate for the year-to-date period may be the best estimate of the annual effective tax rate. We are able to reliably estimate the annual effective tax rate on our foreign earnings, but are unable to reliably estimate the annual effective tax rate on U.S. earnings.
We review all available evidence to evaluate the recovery of deferred tax assets, including the recent history of losses in all tax jurisdictions, as well as our ability to generate income in future periods. As of March 31, 2015, due to the uncertainty related to the ultimate use of certain deferred income tax assets, we have recorded a valuation allowance on certain of our deferred tax assets.

If we are able to make a reliable estimate of our U.S. annual effective tax rate as of June 30, 2015, we expect to provide for income taxes on a current year-to-date basis. If we continue to be unable to make a reliable estimate of its annual effective tax rate as of June 30, 2015, we expect to provide for income taxes using a consistent methodology as was applied for the three month period ended March 31, 2015.
For the three month period ended March 31, 2014, we recorded a tax benefit of $0.4 million due primarily to our foreign loss. This was partially offset by a U.S. tax expense related to tax deductible goodwill that generates a deferred tax liability that cannot be used as a source of income against which deferred tax assets may be realized.
Liquidity and Capital Resources
Overview
We have generated significant cumulative losses since inception. As of March 31, 2015 , we had an accumulated deficit of $119.6 million . As of March 31, 2015 , our principal sources of liquidity were cash and cash equivalents totaling $152.4 million , a decrease of $102.0 million from the December 31, 2014 balance of $254.4 million , which was principally driven by the cash paid for the acquisition of World Energy, as well as cash used in operations. At March 31, 2015 and December 31, 2014, the majority of our excess cash was invested in money market funds.
During the three months ended March 31, 2015 , we utilized $77.2 million ( $79.9 million less $2.7 million of acquired cash) of our cash and cash equivalents in connection with the acquisition of World Energy. We believe our existing cash and cash equivalents and our anticipated net cash flows from operating activities will be sufficient to meet our anticipated cash needs, including investing activities, for at least the next 12 months. Our future working capital requirements will depend on many factors, including, without limitation, the rate at which we sell our EIS and related solutions to enterprise customers and the increasing rate at which letters of credit or security deposits are required by electric power grid operators and utilities, the

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introduction and market acceptance of new EIS and related solutions, the expansion of our sales and marketing and research and development activities, and the geographic expansion of our business operations.
Cash Flows
The following table summarizes our cash flows for the three months ended March 31, 2015 and 2014 (in thousands):
 
Three Months Ended March 31,
 
2015
 
2014
Cash flows used in operating activities
$
(18,452
)
 
$
(11,566
)
Cash flows used in investing activities
(80,566
)
 
(30,950
)
Cash flows used in financing activities
(1,011
)
 
(3,119
)
Effects of exchange rate changes on cash
(1,894
)
 
144

     Net change in cash and cash equivalents
$
(101,923
)
 
$
(45,491
)
Cash Flows Used in Operating Activities
Cash used in operating activities primarily consists of net loss adjusted for certain non-cash items including depreciation and amortization, stock-based compensation expense, and the effect of changes in working capital and other activities.
Cash used in operating activities for the three months ended March 31, 2015 was $18.5 million and consisted of net loss of $50.3 million which was partially offset by $13.7 million of net cash provided by working capital and other activities and $18.1 million of non-cash items. The non-cash items consisted primarily of depreciation and amortization, stock-based compensation expense, unrealized foreign exchange transaction losses, deferred taxes and non-cash interest expense. Cash used in working capital and other activities consisted of a decrease of $33.0 million in accrued capacity payments, a decrease of $15.4 million in accounts payable, accrued expenses and other current liabilities, a decrease of $3.2 million in accrued payroll and related expenses, an increase in prepaid expenses and other assets of $2.3 million and an increase in other assets of $1.2 million . This was partially offset by a decrease of $57.4 million in unbilled revenues, most of which related to the PJM demand response market, a decrease of $6.3 million in accounts receivable and an increase of $5.0 million in deferred revenue primarily related to the Western Australia demand response program.
Cash used in operating activities for the three month period ended March 31, 2014 was $11.6 million and consisted of a net loss of $30.4 million offset by $11.5 million of noncash items, consisting primarily of depreciation and amortization, stock-based compensation expense, impairment charges of equipment, and deferred taxes, and by $7.3 million of net cash provided by working capital and other activities. Cash provided by working capital and other activities consisted of a decrease of $39.2 million in unbilled revenues, most of which related to the PJM demand response market, a decrease of $9.3 million in deferred revenue primarily related to the Western Australia demand response program and an increase of $0.2 million in accounts payable, accrued performance adjustments and accrued expenses primarily due to the timing of payments. These amounts were offset by cash used in working capital and other activities consisting of an increase of $10.3 million in accounts receivable due to the timing of cash receipts under the demand response programs in which we participate, an increase in capitalized incremental direct customer contract costs of $6.3 million, an increase in prepaid expenses and other assets of $3.1 million, a decrease of $0.3 million in other noncurrent liabilities, a decrease of $18.3 million in accrued capacity payments and a decrease in accrued payroll and related expenses of $3.4 million.
Cash Flows Used in Investing Activities
Cash used in investing activities was $80.6 million for the three months ended March 31, 2015 . During the three months ended March 31, 2015 , we made net payments of $77.6 million for acquisitions. This includes the purchase of World Energy, as well as an earn-out payment for Activation and a working capital settlement for Pulse Energy. In addition, during the three months ended March 31, 2015 , we made $5.2 million of capital expenditures, primarily related to software additions, including capitalized software development costs, to further expand the functionality of our software and solutions, as well as, demand response equipment expenditures due to an increase in our installed customer base. Cash used in investing activities for the three months ended March 31, 2015 was partially offset by an increase in restricted cash of $2.2 million due to an increase in deposits principally related to the financial assurance requirements for demand response programs in which we participate.
Cash used in investing activities was $30.9 million for the three month period ended March 31, 2014. During the three month period ended March 31, 2014, we made payments, net of cash acquired, of $3.9 million and $20.2 million, respectively,

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for the acquisitions of Entelios AG, or Entelios, and Activation. In addition, we made a payment of $1.0 million to acquire a cost method investment. We also incurred $6.1 million in capital expenditures primarily related to $3.4 million in software additions, including capitalized software, to further expand the functionality of our software and solutions, as well as, increased demand response equipment related to an increased installed base. We also made payments of $0.4 million for the acquisition of a customer contract. In addition, our restricted cash and deposits increased by $0.7 million due to an increase in deposits principally related to the financial assurance requirements for demand response programs in which we participate.
Cash Flows Used In Financing Activities
Cash used in financing activities was $1.0 million for the three months ended March 31, 2015 and consisted primarily of payments made for employee restricted stock minimum tax withholdings totaling $2.0 million , less $1.0 million of cash realized from the exercise of stock options.
Cash used in financing activities was $3.1 million for the three month period ended March 31, 2014 and consisted primarily of payments made for employee restricted stock minimum tax withholdings, partially offset by proceeds that we received from exercises of options to purchase shares of our common stock. 
Borrowings and Credit Arrangements
Credit Agreement
On August 11, 2014, we entered into a $30.0 million senior secured one-year revolving credit facility, the full amount of which may be available for issuances of letters of credit, pursuant to a loan and security agreement, or the 2014 credit facility, with Silicon Valley Bank. The 2014 credit facility is subject to continued covenant compliance and borrowing base requirements. As of March 31, 2015 , we were in compliance with all of our covenants under the 2014 credit facility. We believe that it is reasonably assured that we will comply with the covenants of the 2014 credit facility through its expiration date of August 11, 2015. As of March 31, 2015 , we had no borrowings, but had outstanding letters of credit totaling $21.4 million , under the 2014 credit facility. As of March 31, 2015 , we had $8.6 million available under the 2014 credit facility for future borrowings or issuances of additional letters of credit.
Convertible Notes
On August 12, 2014, we entered into a purchase agreement with Morgan Stanley & Co. LLC relating to the sale of $160.0 million aggregate principal amount of 2.25% convertible senior notes due August 15, 2019, or the Notes, in an offering exempt from registration under the Securities Act of 1933, as amended, which we refer to as the Offering. The Notes includes customary terms and covenants, including certain events of default after which the Notes may be declared or become due and payable immediately. The Notes are convertible at an initial conversion rate of 36.0933 shares of the common stock per $1.0 million principal amount of Notes. However, if we receive stockholder approval at the annual meeting of stockholders scheduled to be held on May 27, 2015, we may settle conversions of Notes by paying or delivering, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at its election. The conversion rate will be subject to adjustment in some events, but will not be adjusted for any accrued and unpaid interest.
We have concluded that ASC 470, Debt applies to the Notes and accordingly, we are required to account for the liability and equity components of the Notes separately to reflect their nonconvertible debt borrowing rate. The estimated fair value of the liability component of $137.4 million was determined using a discounted cash flow technique. The excess of the gross proceeds received over the estimated fair value of the liability component totaling $22.6 million has been allocated to the conversion feature (equity component) with a corresponding offset recognized as a discount to reduce the net carrying value of the Notes. The discount is being amortized to interest expense over a five year period ending August 15, 2019 (the expected life of the liability component) using the effective interest method. In addition, transaction costs are required to be allocated to the liability and equity components based on their relative percentages. The applicable transaction costs allocated to the liability and equity components at issuance were $4.1 million and $0.7 million , respectively. The transaction costs allocated to the liability represent debt issuance costs and are recorded as an asset in our unaudited condensed consolidated balance sheet. As of March 31, 2015 , $0.7 million and $2.9 million of deferred issuance costs are included in prepaid expenses and other current assets and deposits and other assets, respectively, in our unaudited condensed consolidated balance sheet.

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Interest expense under the Notes is as follows:
 
Three Months Ended
 
March 31,
2015
Accretion of debt discount
$
1.0

Amortization of deferred financing costs
0.2

Non-cash interest expense
$
1.2

2.25% accrued interest
0.8

Total interest expense from Notes
$
2.0

Based on our evaluation of the Notes in accordance with ASC 815-40, Contracts in Entity’s Own Equity , we determined that the Notes contain a single embedded derivative, comprising both the contingent interest feature related to timely filing failure, requiring bifurcation as the features is not clearly and closely related to the host instrument. We have determined that the value of this embedded derivative was nominal as of the date of issuance and as of March 31, 2015 .

Contingent Earn-Out Payments
As discussed in Note 2 contained in Appendix A to the 2014 Form 10-K, in connection with our 2014 acquisitions of Entelios, Activation Energy, Universal Load Center Co., Ltd., or ULC, and Pulse Energy, we may be obligated to pay additional contingent purchase price consideration related to earn-out payments.
The earn-out payment for Entelios, if any, will be based on the achievement of certain minimum defined profit metrics for the years ended December 31, 2014 and 2015. The 1.5 million Euros ($2.0 million) maximum earn-out payment includes up to 0.6 million Euros and 0.9 million Euros related to the achievement of the defined profit metrics for the years ended December 31, 2014 and 2015. If the minimum defined profit metrics are not achieved, there will be no partial payment, however, the amount of the earn-out payment can vary based on the amount that profits exceed the minimum defined profit metrics. We determined that the earn-outs’ fair value as of the acquisition date was 0.1 million Euros ($0.1 million). This reflects our 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. We did not achieve the 2014 milestones and as a result, 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 is recorded to cost of revenues in our accompanying condensed consolidated statements of operations. During the three months ended March 31, 2015, the change in the fair value that resulted from the accretion of the time value of money discount was not material; as a result, the March 31, 2015 liability remained at 0.1 million Euros ($0.1 million) representing the potential payout associated with the 2015 milestones.
The earn-out payment for Activation Energy will be based on the achievement of certain minimum defined MW enrollment, as well as profit metrics for the years ended December 31, 2014 and 2015. The 1.0 million Euros ($1.4 million) maximum earn-out payment includes up to 0.3 million Euros and 0.7 million Euros related to the achievement of the defined profit metrics for the years ended December 31, 2014 and 2015. If the minimum defined profit metrics are not achieved, there will be no partial payment, however, the amount of the earn-out payment can vary based on the amount that profits exceed the minimum defined profit metrics. We determined that the earn-outs’ fair value as of the acquisition date was 0.2 million Euros ($0.3 million). 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. In January 2015, we disbursed 0.3 million Euros ($0.3 million) related to the 2014 milestone. At March 31, 2015, the liability was recorded at 0.5 million Euros ($0.5 million) representing the potential payout associated with the 2015 milestones.
In connection with our acquisition of ULC in April 2014, we may be obligated to pay additional contingent purchase price consideration related to certain earn-out amounts up to a maximum of $1.8 million. The earn-out payments, if any, will be based on the achievement of certain defined market legislation and certain operational metrics. The market legislation metric was achieved in May 2014, with the $0.3 million payment retained to cover general business representations and warranties to be paid 18 months after the closing date. The remaining $1.5 million is payable to those stockholders of the acquired entity who are employees as of the time of payment. We concluded these payments should be accounted for as compensation arrangements and expensed ratably over the applicable service period for the amount, if achievement is deemed probable. The first performance milestone of $0.5 million was achieved in December 2014, with $0.2 million paid at such time. The remaining $0.3 million will be paid in January 2016 and 2017. The second performance milestone of $1.0 million has not yet been

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achieved. As of March 31, 2015, we have recorded a liability of approximately $0.4 million associated with the unpaid market legislation metric and the first performance milestone in accrued acquisition consideration in the accompanying balance sheet.
The earn-out payment for Pulse Energy, if any, will be based on the achievement of sales targets for the years ended December 31, 2015, 2016 and 2017. To the extent targets are reached, payment will predominantly be in the form of our common stock with immaterial amounts of cash paid to the U.S. based employees. The earn-out is a binary outcome in that either full or no payment is due. 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 and weighed probability assumptions of these outcomes. Because the contingent consideration is expected to be settled in our own shares and the criteria in ASC 815, Contracts in Entity’s Own Equity , was met, the fair value of the earn-out was recorded in equity as additional paid-in capital. The fair value of the earn-out was estimated at $1.6 million and remains within equity.
Capital Spending
We have made capital expenditures primarily for general corporate purposes to support our growth and for equipment installations related to our business. Our capital expenditures totaled $5.2 million and $6.1 million during the three months ended March 31, 2015 and 2014 , respectively. We expect our capital expenditures for 2015 to exceed our capital expenditures for 2014 due primarily to increased site installations, higher capitalized software attributable to capitalized wages consistent with the expected growth in research and development headcount, higher leasehold improvements and office equipment consistent with overall headcount growth. 
Contractual Obligations
Information regarding our significant contractual obligations is set forth in the following table and includes the operating lease arrangement described below. Payments due by period have been presented based on payments due subsequent to March 31, 2015 (in millions):
 
Payments Due By Period (in thousands)
Contractual Obligations
Total
 
Less
than
1 Year
 
1 - 3 Years
 
3 - 5 Years
 
More
than
5 Years
Interest on convertible senior notes
$
15.7

 
$
3.6

 
$
7.2

 
$
4.9

 
$

Operating lease obligations
43.7

 
9.2

 
16.6

 
15.1

 
2.8

Total contractual obligations
$
59.4

 
$
12.8

 
$
23.8

 
$
20.0

 
$
2.8

The future payments related to uncertain tax positions have not been presented in the table above due to the uncertainty of the amounts and timing of cash settlement with the taxing authorities. Refer to Note 10 contained in Part I to this Quarterly Report on Form 10-Q.
Our fixed interest payments at 2.25% per relating to our Notes, which mature on August 19, 2019, are presented in the table above.
Our operating lease obligations relate primarily to the leases of our corporate headquarters in Boston, Massachusetts and our offices in San Francisco, California; Baltimore, Maryland; Boise, Idaho; Worcester, Massachusetts; Australia, United Kingdom, Germany, Ireland, South Korea, Brazil and India, as well as certain property and equipment.
In March 2014, we entered into a lease for our California operations. The lease term is through September 2019 and the lease contains both a rent holiday period and escalating rental payments over the lease term. The lease requires payments for additional expenses such as taxes, maintenance, and utilities and contains a fair value renewal option. The lease commenced on April 1, 2014. In addition, in connection with the acquisitions we completed during 2014 and January 2015, we acquired certain facility operating lease arrangements which were all considered to contain current market terms and rates. These leases have terms that range from one to ten years and expire through March 2020. Certain of the lease agreements require payments for additional expenses such as taxes, maintenance, and utilities and contain fair value renewal options. There were no ongoing rent holidays or escalating rent payments over the remaining lease terms as of the dates of acquisition.
On October 9, 2014, we entered into an amendment to the lease for our corporate headquarters, or the 2012 Lease, to lease additional space. Our lease for this additional space commenced on or about January 1, 2015, which was the date on which we had the right to control access and physical use of the leased space, and will be subject to the terms and conditions of the 2012 Lease. The lease term for the additional space shall coincide with the term for the 2012 Lease and expire on July 31, 2020 unless earlier terminated or further extended, as provided in the 2012 Lease. The lease amendment contains both a rent holiday, under which lease payments do not commence until June 2015, and escalating rental payments.
In connection with our acquisition of M2M, we are required to pay additional consideration that was deferred at the date of the acquisition. This deferred purchase price consideration of $7.0 million will be paid upon the earlier of the satisfaction of

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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. We recorded our 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. The cash portion of the deferred purchase price consideration has been recorded as a liability, initially estimated to be less than $0.5 million, discounted to reflect the time value of money. As the milestone payment date approaches, the fair value of this liability will increase. The fair value of the deferred purchase price consideration of $3.4 million, related to the 254,654 shares of common stock to be issued upon the milestone payment date has been classified as additional paid-in capital within stockholders’ equity. With respect to the cash portion of the deferred purchase price consideration, the increase in fair value is recorded as an expense in our accompanying condensed consolidated statements of operations. During the three months ended March 31, 2015, we recorded a charge of less than $0.1 million related to the accretion for the time value of money discount. At March 31, 2015, the liability was recorded at $0.6 million . The deferred purchase price consideration to be paid in shares meets the requirements of an equity instrument and, accordingly, will not be remeasured at fair value each reporting period. This acquisition had no contingent consideration or earn-out payments.
As of March 31, 2015 , we had no borrowings, but had outstanding letters of credit totaling $ 21.4 million under the 2014 credit facility. As of March 31, 2015 , we had $ 8.6 million available under the 2014 credit facility for future borrowings or issuances of additional letters of credit.
We typically grant certain customers a limited warranty that guarantees that our hardware products will substantially conform to current specifications for one year from the delivery date. Based on our operating history, the liability associated with product warranties has been determined to be nominal. We also indemnify our customers from third-party claims relating to the intended use of our products. Pursuant to these clauses, we indemnify and agree to pay any judgment or settlement relating to a claim.
We guarantee the electrical capacity we have committed to deliver pursuant to certain long-term contracts. Such guarantees may be secured by cash or letters of credit. Performance guarantees as of March 31, 2015 and December 31, 2014 were $20.5 million and $23.7 million, respectively. For the three months ended March 31, 2015 , these performance guarantees include deposits held by certain customers of $1.4 million . For the three months ended March 31, 2014 , the performance guarantees included restricted cash utilized to collateralize certain demand response programs of $1.3 million and did not include any deposits held by customers.

Off-Balance Sheet Arrangements
As of March 31, 2015 , 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 March 31, 2015 , we had outstanding letters of credit totaling $ 21.4 million . For information on these commitments and contingent obligations, please refer to “Liquidity and Capital Resources-Borrowings and Credit Arrangements” above and Note 7 contained in Part I to this Quarterly Report on Form 10-Q.
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 loss attributable to EnerNOC, Inc., non-GAAP net loss per share attributable to EnerNOC, Inc., 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 loss attributable to EnerNOC, Inc. is GAAP net loss attributable to EnerNOC, Inc.; the GAAP measure most comparable to non-GAAP net loss per share attributable to EnerNOC, Inc. is GAAP net loss per share attributable to EnerNOC, Inc.; the GAAP measure most comparable to adjusted EBITDA is GAAP net loss attributable to EnerNOC, Inc.; and the GAAP measure most comparable to free cash flow is cash flows provided by (used in) operating activities. Reconciliations of each of these non-GAAP financial measures to the corresponding GAAP measures are included below.
Use and Economic Substance of Non-GAAP Financial Measures
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

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performance. For example, management considers non-GAAP net loss attributable to EnerNOC, Inc. to be an important indicator of the overall performance because it eliminates the material 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:
Management defines non-GAAP net loss attributable to EnerNOC, Inc. as net loss attributable to EnerNOC, Inc. before accretion expense related to the debt-discount portion of interest expense associated with the convertible note issuance, stock-based compensation, direct and incremental expenses related to acquisitions or divestitures, and amortization expenses related to acquisition-related intangible assets, net of related tax effects.
Management defines adjusted EBITDA as net loss attributable to EnerNOC, Inc., excluding depreciation, amortization, stock-based compensation, direct and incremental expenses related to acquisitions or divestitures, interest expense, income taxes and other (expense) income.
Management defines free cash flow as net cash provided by (used in) operating activities, less capital expenditures, plus net cash provided by (used in) the sale of assets or disposals of components of an entity. Management defines capital expenditures as purchases of property and equipment, which includes capitalization of internal-use software development costs.
Material Limitations Associated with the Use of Non-GAAP Financial Measures
Non-GAAP net loss attributable to EnerNOC, Inc., non-GAAP net loss per share attributable to EnerNOC, Inc., 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 Loss attributable to EnerNOC, Inc. and Non-GAAP Net Loss per Share attributable to EnerNOC, Inc.
Net loss for the three months ended March 31, 2015 was $50.3 million , or $1.80 per basic and diluted share, compared to net loss of $30.4 million, or $1.09 per basic and diluted share for the three months ended March 31, 2014 . Excluding accretion expense related to the debt-discount portion of interest expense associated with the convertible note issuance, stock-based compensation expense, and amortization expenses related to acquisition-related intangible assets, net of related tax effects, non-GAAP net loss for the three months ended March 31, 2015 was $39.6 million , or $1.41 per basic and diluted share, compared to non-GAAP net loss of $23.4 million, or $0.84 per basic and diluted share, for the three months ended March 31, 2014 .

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The reconciliation of GAAP net loss attributable to EnerNOC, Inc. to non-GAAP net loss attributable to EnerNOC, Inc. is set forth below (dollars in thousands, except share and per share data):
 
Three Months Ended March 31,
 
2015
 
2014
GAAP net loss attributable to EnerNOC, Inc.
$
(50,301
)
 
$
(30,413
)
ADD: Stock-based compensation expense
4,409

 
4,227

ADD: Amortization expense of acquired intangible assets
3,918

 
1,883

ADD: Direct and incremental expenses related to acquisitions or divestitures (1)
1,382

 
946

ADD: Debt discount portion of convertible debt
992

 

     Non-GAAP net loss attributable to EnerNOC, Inc.
$
(39,600
)
 
$
(23,357
)
 
 
 
 
GAAP net loss per diluted share attributable to EnerNOC, Inc.
$
(1.80
)
 
$
(1.09
)
ADD: Stock-based compensation expense
0.16

 
0.15

ADD: Amortization expense of acquired intangible assets
0.14

 
0.07

ADD: Direct and incremental expenses related to acquisitions or divestitures (1)
0.05

 
0.03

ADD: Debt discount portion of convertible debt
0.04

 

     Non-GAAP net loss per diluted share attributable to EnerNOC, Inc.
$
(1.41
)
 
$
(0.84
)
 
 
 
 
Weighted average number of common shares outstanding
 

 
 
Basic and diluted
28,007,756

 
27,923,861

 
 
 
 
(1) Includes third party professional service costs such as legal, accounting and valuation, and compensation, severance and related costs.

Adjusted EBITDA
Adjusted EBITDA was ($30.0) million , and ($18.4) million for the three months ended March 31, 2015 and 2014 , respectively.

44


The reconciliation of net loss to adjusted EBITDA is set forth below (dollars in thousands):
 
Three Months Ended March 31,
 
2015
 
2014
Net loss attributable to EnerNOC, Inc.
$
(50,301
)
 
$
(30,413
)
Add back:
 
 
 
     Depreciation and amortization
9,834

 
7,365

     Stock-based compensation expense
4,409

 
4,227

     Direct and incremental expenses related to acquisitions or divestitures
1,382

 
946

     Other expense (income) (1)
4,657

 
(574
)
     Interest expense
2,292

 
450

     Benefit from income tax
(2,285
)
 
(425
)
Adjusted EBITDA
$
(30,012
)
 
$
(18,424
)
 
(1)
Other expense primarily relates to foreign exchange losses.


Free Cash Flow
Cash flows used in operating activities were $18.5 million  for the three months ended March 31, 2015 . Cash flows used in operating activities were $11.6 million for the three months ended March 31, 2014 . We had negative free cash flow of $23.7 million for the three months ended March 31, 2015 compared to negative free cash flow of $17.7 million for the three months ended March 31, 2014 . The reconciliation of cash flows from operating activities to free cash flow is set forth below (in thousands):
 
Three Months Ended March 31,
 
2015
 
2014
Net cash used in operating activities
$
(18,452
)
 
$
(11,566
)
Subtract:
 
 
 
Purchases of property and equipment
(5,206
)
 
(6,113
)
Free cash flow
$
(23,658
)
 
$
(17,679
)
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 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 may 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 unaudited 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 2014

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Form 10-K. Except as disclosed herein, there have been no material changes to our critical accounting policies or estimates during the three months ended March 31, 2015 .
Revenue Recognition
We recognize revenues in accordance with ASC 605, Revenue Recognition (ASC 605). Our customers include enterprises, grid operators, and utilities. We derive recurring revenues from the sale of our EIS and related solutions. We do not recognize any revenues until persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and we deem collection to be reasonably assured. In making these judgments, we evaluate the following criteria:
Evidence of an arrangement .    We consider a definitive agreement signed by the customer and us or an arrangement enforceable under the rules of an open market bidding program to be representative of persuasive evidence of an arrangement.
Delivery has occurred .    We consider delivery to have occurred when service has been delivered to the customer and no significant post-delivery obligations exist. In instances where customer acceptance is required, delivery is deemed to have occurred when customer acceptance has been achieved.
Fees are fixed or determinable .    We consider the fee to be fixed or determinable unless the fee is subject to refund or adjustment or is not payable within normal payment terms. If the fee is subject to refund or adjustment and we cannot reliably estimate this amount, we recognize revenues when the right to a refund or adjustment lapses. If we offer payment terms significantly in excess of our normal terms, we recognize revenues as the amounts become due and payable or upon the receipt of cash.
Collection is reasonably assured .    We conduct credit reviews at the inception of an arrangement to determine the creditworthiness of the customer. Collection is reasonably assured if, based upon evaluation, we expect that the customer will be able to pay amounts under the arrangement as payments become due. If we determine that collection is not reasonably assured, revenues are deferred and recognized upon the receipt of cash.
We maintain a reserve for customer adjustments and allowances as a reduction in revenues. In determining our revenue reserve estimate, and in accordance with internal policy, we rely on historical data and known performance adjustments. These factors, and unanticipated changes in the economic and industry environment, could cause our reserve estimates to differ from actual results. We record a provision for estimated customer adjustments and allowances in the same period as the related revenues are recorded. These estimates are based on the specific facts and circumstances of a particular program, analysis of credit memo data, historical customer adjustments, and other known factors. If the data we use to calculate these estimates do not properly reflect reserve requirements, then a change in the allowances would be made in the period in which such a determination was made and revenues in that period could be affected.
Revenues from grid operators and revenues from utilities principally represent demand response revenues. During the three months ended March 31, 2015 and 2014 , revenues from grid operators and utilities were comprised of $32.6 million and $44.1 million, respectively, of demand response revenues.
Our enterprise revenues from the sales of our EIS and related solutions to our enterprise customers generally represent ongoing software or service arrangements under which the revenues are recognized ratably over the same period commencing upon delivery of the EIS and related solutions to the enterprise customer. Under certain of our arrangements, a portion of the fees received may be subject to adjustment or refund based on the validation of the energy savings delivered after the implementation is complete. As a result, we defer the portion of the fees that are subject to adjustment or refund until such time as the right of adjustment or refund lapses, which is generally upon completion and validation of the implementation.
Our EIS and related solutions for utility customers and electric power grid operators also include the demand response applications and solutions, EnerNOC Demand Resource and EnerNOC Demand Manager. Our grid operator revenues and utility revenues primarily reflect the sale of our EnerNOC Demand Resource solution. The revenues primarily consist of capacity and energy payments, including ancillary services payments, as well as payments derived from the effective management of our portfolio of demand response capacity, including our participation in capacity auctions and third-party contracts and ongoing fixed fees for the overall management of utility-sponsored demand response programs. We derive revenues from our EnerNOC Demand Resource solution by making demand response capacity 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 utilities, generally ranging from three to ten years in duration, to deploy our EnerNOC Demand Resource solution. We refer to these contracts as utility contracts.
With respect to the EnerNOC Demand Manager application, we generally receive an ongoing fee for overall management of the utility demand response program based on enrolled capacity or enrolled enterprise customers, which is not subject to adjustment based on performance during a demand response dispatch. We recognize revenues from these fees ratably over the applicable service delivery period commencing upon when the enterprise customers have been enrolled and the contracted

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services have been delivered. In addition, under this offering, we may receive additional fees for program start-up, as well as, for enterprise customer installations. We have determined that these fees do not have stand-alone value due to the fact that such services do not have value without the ongoing services related to the overall management of the utility demand response program and therefore, we recognize these fees over the estimated customer relationship period, which is generally the greater of three years or the contract period, commencing upon the enrollment of the enterprise customers and delivery of the contracted services.
For further discussion of our revenue recognition policy, please refer to Note 1 contained in Part I to this Quarterly Report on Form 10-Q.
Recent Accounting Pronouncements
In April 2014, the Financial Accounting Standards Board, or FASB, issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (ASU 2014-08). ASU 2014-08 amends the definition of discontinued operations under ASC 205-20 to only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements. This guidance is effective for all disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. We early adopted this guidance as of January 1, 2014. The adoption of this guidance did not have a material impact on our financial condition or results of operations.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 provides guidance for revenue recognition and the standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The new guidance was effective for annual and interim periods beginning after December 15, 2016, with no early adoption permitted. The FASB voted on April 1, 2015 to propose a deferral of the effective date by one year. With the deferral, ASU No 2014-09 will be effective for us beginning in the first quarter of fiscal year 2018, and allows for full retrospective adoption applied to all periods presented or retrospective adoption with the cumulative effect of initially applying this update recognized at the date of initial application. We have not yet determined the method of adoption. We are currently in the process of evaluating the impact of adoption of this ASU on our consolidated financial position and results of operations.

Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Except as disclosed herein, there have been no material changes during the three months ended March 31, 2015 in 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 2014 Form 10-K.
Foreign Currency 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 majority of our foreign expenses and sales activities are transacted in local currencies, including Australian dollars, Euros, Brazilian real, British pounds, Canadian dollars, Indian rupee, Japanese yen, South Korean Won and New Zealand dollars. 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 or receivables (third party or intercompany) in a foreign currency. During the three months ended March 31, 2015 and 2014 , our sales generated outside the United States were 41% and 17%, respectively. We anticipate that sales generated outside the United States will continue to represent greater than 10% of our consolidated sales and will continue to grow in subsequent fiscal years.
The operating expenses of our international subsidiaries that are incurred in local currencies did not have a material adverse effect on our business, results of operations or financial condition for three months ended March 31, 2015 . 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 operating 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.

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During the three months ended March 31, 2015 and 2014 , we recognized foreign exchange (losses) gains of ($5.0) million and $(0.4) million , respectively. This primarily relates to intercompany receivables denominated in foreign currencies, largely driven by fluctuations to the Canadian dollar, and Euro.
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 foreign exchange gains and losses, 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.
Interest Rate Risk
We incur interest expense on borrowings outstanding under our Notes and 2014 credit facility. The Notes have fixed interest rates. Borrowings under our 2014 credit facility bear interest at a rate per annum, at our option, initially. The interest on revolving loans under the 2014 credit facility will accrue, at our election, at either (i) the LIBOR (determined based on the per annum rate of interest at which deposits in United States Dollars are offered to SVB in the London interbank market) plus 2.00%, or (ii) the “prime rate” as quoted in the Wall Street Journal with respect to the relevant interest period plus 1.00%.
As of March 31, 2015 , we had no aggregate principal amount outstanding under the 2014 credit facility, but had outstanding letters of credit totaling $ 21.4 million under the 2014 credit facility.
The return from cash and cash equivalents will vary as short-term interest rates change. A hypothetical 10% increase or decrease in interest rates, however, would not have a material adverse effect on our financial condition.
 
Item 4.
Controls and Procedures
Disclosure Controls and Procedures.
Our principal executive officer and principal financial officer, after evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this 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

Item 1.
Legal Proceedings
We are subject to legal proceedings, claims and litigation arising in the ordinary course of business. We do not expect the ultimate costs to resolve these matters to have a material adverse effect on our consolidated financial condition, results of operations or cash flows.
On May 3, 2013, a purported shareholder of ours, or the plaintiff, filed a derivative and class action complaint in the United States District Court for the District of Delaware, or the Court, against certain of our officers and directors as well as the Company as a nominal defendant, which we refer collectively to as the defendants. The complaint asserted derivative claims, purportedly brought on behalf of the Company, for breach of fiduciary duty, waste of corporate assets, and unjust enrichment in connection with certain equity grants (awarded in 2010, 2012, and 2013) that allegedly exceeded an annual limit on per-employee equity grants purported to be contained in the Company’s Amended and Restated 2007 Employee, Director and Consultant Stock Plan. The complaint also asserted a direct claim, brought on behalf of the plaintiff and a proposed class of our shareholders, alleging our proxy statement filed on April 26, 2013 was false and misleading because it failed to disclose that the

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equity grants were improper. The plaintiff sought, among other relief, rescission of the equity grants, unspecified damages, injunctive relief, disgorgement, attorneys’ fees, and such other relief as the Court may deem proper.
On June 27, 2014, the parties engaged in mediation and reached agreement in principle on the terms of a potential settlement. On December 15, 2014, the Court held a fairness hearing and approved the settlement, together with an award of attorneys’ fees to plaintiffs’ counsel in the amount of $0.4 million, a portion of which was covered by our insurance. Pursuant to the settlement, defendant members of our Board of Directors agreed to cause our insurer to make a cash payment of $0.5 million to the Company, and to cause the Company to undertake certain reforms in connection with equity granting practices. The cash payment of $0.5 million was received and recognized in January 2015.
On November 6, 2014, a class action lawsuit was filed in the Delaware Court of Chancery against us, World Energy, Wolf Merger Sub Corporation, and members of the board of directors of World Energy arising out of the merger between us and World Energy. The lawsuit generally alleged that the members of the board of directors of World Energy breached their fiduciary duties to World Energy’s stockholders by entering into the merger agreement because they, among other things, failed to maximize stockholder value and agreed to preclusive deal-protection terms. The lawsuit also alleged that we and World Energy aided and abetted the board of directors of World Energy in breaching their fiduciary duties. The plaintiff sought to stop or delay the acquisition of World Energy by us, or rescission of the merger in the event it was consummated, and seeks monetary damages in an unspecified amount to be determined at trial. The parties engaged in settlement negotiations and on December 24, 2014, without admitting, but expressly denying any liability on behalf of the defendants, the parties entered into a memorandum of understanding, or the MOU, regarding a proposed settlement to resolve all allegations. The MOU was filed in the Delaware Court of Chancery on December 24, 2014. Among other things, the MOU provides that, in consideration for a release and the dismissal of the litigation, World Energy would include additional disclosures in a Form SC 14D9-A to be filed with the SEC no later than December 24, 2014. The MOU also provided that the litigation, including the preliminary injunction hearing, be stayed. The merger closed on January 5, 2015. On March 26, 2015, the parties executed and filed with the Delaware Chancery Court a formal stipulation of settlement. The Company has recognized an obligation of $0.3 million in connection with the settlement. The Delaware Chancery Court has scheduled a hearing to be held on June 30, 2015 to consider whether to approve the settlement. There can be no assurance that the stipulation of settlement will be finalized or that the Delaware Court of Chancery will approve the settlement.

Item 1A.
Risk Factors
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 2014 Form 10-K. During the three months ended March 31, 2015, there were no material changes to the risk factors that were disclosed in our 2014 Form 10-K other than as set forth below.
The following risk factors replace and supersede the corresponding risk factors set forth in our 2014 Form 10-K:
Unfavorable regulatory decisions, changes to the market rules applicable to the programs in which we currently participate or may participate in the future, and varying regulatory structures in certain regional electric power markets could negatively affect our business and results of operations.
Unfavorable regulatory decisions in markets where we currently operate or choose to operate in the future could significantly and negatively affect our business. For example, in a May 23, 2014 decision by the United States Court of Appeals for the D.C. Circuit, the court held that the Federal Energy Regulatory Commission, or FERC, did not have jurisdiction under the Federal Power Act to issue FERC Order 745, an order that required, among other things, that economic demand response resources participating in the wholesale energy markets administered by electric power grid operators, such as PJM, be paid the locational marginal price of energy. The U.S. Supreme Court has granted certiorari to review the decision of the D.C. Circuit. While we believe that Order 745 was effective and binding and that we delivered service in accordance with the applicable market and program tariffs and manuals, if the decision affirmed and FERC Order 745 is invalidated, certain revenues earned prior to May 23, 2014 in connection with our participation in price-based/economic demand response programs, which we have estimated to be approximately $20.1 million, may become subject to refund, which could negatively impact our business and results of operations. Revenue of $2.7 million earned subsequent to May 23, 2014 and through March 31, 2015 has been deferred; we will continue to defer future revenues relating to these programs until final regulation resolution is reached. In the event the court’s decision is broadened to include capacity or ancillary services markets in which we currently operate or choose to operate in the future, our future revenues and profit margins may be significantly reduced and our results of operations and financial condition could be negatively impacted. Program or market rules could also be modified to change the design of or pricing related to a particular demand response program, which may adversely affect our participation in that program or cause us to cease participation in that program altogether, or a demand response program in which we currently

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participate could be eliminated in its entirety and/or replaced with a new program that is more expensive for us to operate or require substantial changes to the business to enable continued participation. Any elimination or change in the design of any demand response program, including the retroactive application of market rule changes, could adversely impact our ability to successfully manage our portfolio of demand response capacity in that program, especially in the PJM market where we continue to have substantial operations, and could have a material adverse effect on our results of operations and financial condition.
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. For example, the Environmental Protection Agency, or the EPA, issued a final rule in the Nat