ENERNOC INC - FORM 10-Q - November 5, 2015

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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 September 30, 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 30,793,605 shares of the registrant’s common stock, $0.001 par value per share, outstanding as of November 2, 2015.
 


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


2



EnerNOC, Inc.
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands, except par value and share data)
 
September 30, 2015
 
December 31, 2014
ASSETS
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
141,940

 
$
254,351

Restricted cash
2,314

 
813

Trade accounts receivable, net of allowance for doubtful accounts of $957 and $679 at September 30, 2015 and December 31, 2014, respectively
61,206

 
40,875

Unbilled revenue
111,835

 
97,512

Capitalized incremental direct customer contract costs
21,047

 
7,633

Deferred tax assets
6,891

 
6,524

Prepaid expenses and other current assets
14,852

 
12,613

Assets held for sale
1,423

 
—

Total current assets
361,508

 
420,321

Property and equipment, net of accumulated depreciation of $108,636 and $94,976 at September 30, 2015 and December 31, 2014, respectively
51,750

 
50,458

Goodwill
149,239

 
114,939

Intangible assets, net
58,279

 
31,111

Deferred tax assets
766

 
680

Deposits and other assets
6,840

 
7,193

Total assets
$
628,382

 
$
624,702

LIABILITIES AND STOCKHOLDERS’ EQUITY
 
 
 
Current liabilities
 
 
 
Accounts payable
$
2,242

 
$
9,250

Accrued capacity payments
130,479

 
92,332

Accrued payroll and related expenses
18,862

 
18,446

Accrued expenses and other current liabilities
25,493

 
28,724

Deferred revenue
36,138

 
13,738

Liabilities held for sale
477

 
—

Total current liabilities
213,691

 
162,490

Convertible senior notes
141,971

 
138,908

Deferred tax liability
16,878

 
16,449

Deferred revenue
6,509

 
5,816

Other liabilities
9,341

 
8,919

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, 30,830,238 and 29,833,578 shares issued and outstanding at September 30, 2015 and December 31, 2014, respectively
31

 
30

Additional paid-in capital
374,583

 
365,855

Accumulated other comprehensive loss
(9,471
)
 
(4,752
)
Accumulated deficit
(125,355
)
 
(69,260
)
Total EnerNOC, Inc. stockholders’ equity
239,788

 
291,873

Noncontrolling interest
204

 
247

Total stockholders’ equity
239,992

 
292,120

Total liabilities and stockholders’ equity
$
628,382

 
$
624,702

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

3

EnerNOC, Inc.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share data)
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Revenues:
 
 
 
 
 
 
 
Grid operator
$
173,374

 
$
291,848

 
$
238,632

 
$
350,592

Utility
27,160

 
27,741

 
50,498

 
50,011

Enterprise
16,790

 
9,833

 
51,245

 
25,382

Total revenues
217,324

 
329,422

 
340,375

 
425,985

Cost of revenues
143,146

 
168,564

 
208,645

 
232,505

Gross profit
74,178

 
160,858

 
131,730

 
193,480

Operating expenses:
 
 
 
 
 
 
 
Selling and marketing
22,397

 
18,972

 
74,563

 
56,997

General and administrative
26,707

 
24,472

 
83,450

 
72,340

Research and development
6,626

 
5,260

 
21,812

 
15,432

Gain on sale of service line (Note 14)
—

 
(359
)
 
—

 
(3,737
)
Gain on the sale of assets (Note 15)
—

 
—

 
(2,991
)
 
(2,171
)
Total operating expenses
55,730

 
48,345

 
176,834

 
138,861

Income (loss) from operations
18,448

 
112,513

 
(45,104
)
 
54,619

Other expense, net
(2,814
)
 
(2,224
)
 
(5,766
)
 
(1,276
)
Interest expense
(2,253
)
 
(1,523
)
 
(6,785
)
 
(2,576
)
Income (loss) before income tax
13,381

 
108,766

 
(57,655
)
 
50,767

(Provision for) benefit from income tax
(417
)
 
(12,111
)
 
1,523

 
(11,950
)
Net income (loss)
12,964

 
96,655

 
(56,132
)
 
38,817

Net loss attributable to noncontrolling interest
(23
)
 
(18
)
 
(37
)
 
(58
)
Net income (loss) attributable to EnerNOC, Inc.
$
12,987

 
$
96,673

 
$
(56,095
)
 
$
38,875

Net income (loss) per common share
 
 
 
 
 
 
 
Basic
$
0.46

 
$
3.48

 
$
(1.98
)
 
$
1.38

Diluted
$
0.44

 
$
3.11

 
$
(1.98
)
 
$
1.33

Weighted average number of common shares used in computing net income (loss) per common share
 
 
 
 
 
 
 
Basic
28,507,939

 
27,795,154

 
28,282,647

 
28,075,291

Diluted
34,623,574

 
31,434,164

 
28,282,647

 
30,074,187

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


4

EnerNOC, Inc.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2015
 
2014
 
2015
 
2014
Net income (loss)
$
12,964

 
$
96,655

 
$
(56,132
)
 
$
38,817

Foreign currency translation adjustments
(2,069
)
 
(1,572
)
 
(4,719
)
 
(678
)
Comprehensive income (loss)
10,895

 
95,083

 
(60,851
)
 
38,139

Comprehensive loss attributable to noncontrolling interest
(24
)
 
(18
)
 
(43
)
 
(52
)
Comprehensive income (loss) attributable to EnerNOC, Inc.
$
10,919

 
$
95,101

 
$
(60,808
)
 
$
38,191

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


5

EnerNOC, Inc.
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
 
Nine Months Ended
 
September 30,
 
2015
 
2014
Cash flows from operating activities
 
 
 
Net (loss) income
$
(56,132
)
 
$
38,817

Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
 
 
 
Depreciation
17,652

 
16,414

Amortization of acquired intangible assets
11,607

 
6,753

Fair value adjustment of contingent purchase price
468

 
291

Stock-based compensation expense
10,890

 
12,161

Excess tax benefits from exercise of stock-based awards
—

 
(219
)
Gain on sale of service line
—

 
(3,737
)
Gain on sale of assets
(2,991
)
 
(2,171
)
Impairment of property and equipment and definite lived intangible assets
495

 
856

Unrealized foreign exchange translation loss
6,010

 
2,417

Deferred income taxes
(2,271
)
 
5,594

Non-cash interest expense
3,791

 
861

Other, net
79

 
371

Changes in operating assets and liabilities, net of effects of acquisitions:
 
 
 
Trade accounts receivable
(13,199
)
 
(19,957
)
Unbilled revenue
(14,429
)
 
(89,783
)
Prepaid expenses and other current assets
(7,353
)
 
(1,524
)
Capitalized incremental direct customer contract costs
(12,766
)
 
2,910

Other noncurrent assets
(844
)
 
225

Deferred revenue
23,017

 
(6,709
)
Accrued capacity payments
39,367

 
49,660

Accrued payroll and related expenses
(2,692
)
 
1,466

Accounts payable, accrued expenses and other current liabilities
(19,462
)
 
15,531

Other noncurrent liabilities
537

 
(515
)
Net cash (used in) provided by operating activities
(18,226
)
 
29,712

Cash flows from investing activities
 
 
 
Purchases of property and equipment
(17,724
)
 
(19,248
)
Payments made for acquisitions, net of cash acquired
(77,559
)
 
(36,406
)
Payments made for investments
—

 
(2,500
)
Proceeds from sale of service line
—

 
4,275

Proceeds from sale of assets
2,991

 
2,171

Change in restricted cash and deposits
3,411

 
(1,349
)
Payments made for acquisition of customer contract
—

 
(403
)
Net cash used in investing activities
(88,881
)
 
(53,460
)
Cash flows from financing activities
 
 
 
Proceeds from convertible debt offering
400

 
155,277

Proceeds from exercises of stock options
1,074

 
1,456

Payments made for buy back of common stock
—

 
(29,973
)
Payments made for employee restricted stock minimum tax withholdings
(3,805
)
 
(5,874
)
Excess tax benefit related to exercise of options, restricted stock and restricted stock units
—

 
219

Net cash (used in) provided by financing activities
(2,331
)
 
121,105

Effects of exchange rate changes on cash and cash equivalents
(2,973
)
 
(331
)
Net change in cash and cash equivalents
(112,411
)
 
97,026

Cash and cash equivalents at beginning of period
254,351

 
149,189

Cash and cash equivalents at end of period
$
141,940

 
$
246,215

Supplemental disclosure of cash flow information

 

Cash paid for interest
$
2,993

 
$
1,194

Cash paid for income taxes
$
4,046

 
$
1,691

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

Acquisition of property and equipment in accrued expenses
$
1,940

 
$
1,392

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

6

EnerNOC, Inc.
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(in thousands, except share and per share data)
1. Description of Business, Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
EnerNOC, Inc. (the Company) is a leading provider of energy intelligence software (EIS) and related solutions. The Company’s enterprise customers use the Company's Software-as-a-Service (SaaS) solutions to transform how they manage and control energy spend for their organizations, while utilities leverage the Company's SaaS solutions to better engage their customers, deliver savings and consumption reductions to help achieve energy efficiency mandates, manage system peaks and grid constraints, and increase demand for utility-provided products and services.
The Company’s 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. EnerNOC Demand Resource is a turnkey demand response resource that matches obligation, in the form of megawatts (MWs) that the Company agrees to deliver to the Company’s utility customers and electric power grid operators, with supply, in the form of MWs that are curtailed from the electric power grid through its arrangements with its enterprise customers.
Reclassifications
The Company has reclassified certain amounts in its consolidated balance sheet as of December 31, 2014 to conform to the consolidated balance sheet presentation as of September 30, 2015. The reclassifications made relate to the merger of various balance sheet captions, specifically (i) the noncurrent portion of capitalized incremental direct customer contract costs was merged into deposits and other assets and (ii) accrued acquisition consideration was merged into other liabilities.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States for complete financial statements. All adjustments, which, in the opinion of management, are considered necessary for a fair presentation of the results of operations for the periods shown, are of a normal recurring nature and have been reflected in the condensed consolidated financial statements and accompanying notes. The results of operations for the periods presented are not necessarily indicative of the results expected for the full year or for any future period partially because of the seasonality of the Company’s business. The information included in these condensed consolidated financial statements should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in this report and the consolidated financial statements and accompanying notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, as amended.
The condensed consolidated financial statements of the Company include the accounts of its wholly-owned subsidiaries. All significant transactions and balances between the Company and its subsidiaries have been eliminated. The Company owns 60% of EnerNOC Japan K.K, for which it consolidates the operations in accordance with Accounting Standards Codification (ASC) 810, Consolidation (ASC 810). The remaining 40% represents non-controlling interest in the accompanying unaudited condensed consolidated balance sheets and statements of operations.
The Company recorded an adjustment in the condensed consolidated statement of operations during the three months ended June 30, 2015 to increase cost of goods sold by approximately $610 related to the recognition of payments owed to enterprise customers enrolled in demand response programs relating to the year ended December 31, 2014.   The Company assessed the materiality of the historical misstatements, individually and in aggregate, on its prior annual and quarterly consolidated financial statements and concluded the effect of the error was not material to its consolidated financial statements for any of the periods.


7

Summary of Significant Accounting Policies
Use of Estimates in Preparation of Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying notes. Significant estimates made by management relate to revenue recognition reserves, allowances for doubtful accounts, valuations and purchase price allocations related to business combinations, including the fair value of intangible assets and accrued acquisition consideration, expected future cash flows used to evaluate the recoverability of long-lived assets, 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. While the Company believes that such estimates are fair when considered in conjunction with the condensed consolidated financial position and results of operations taken as a whole, the actual amounts of such items, when known, will vary from these estimates.
Beginning in the third quarter of 2015 the Company changed its U.S. paid time off program from a capped program based on service and employment status to an unlimited time off program.  This change in policy resulted in a $2,308 reduction in the Company’s accrued vacation expense that was recorded in the three months ended September 30, 2015.
Revenue Recognition
The Company recognizes revenues in accordance with ASC 605, Revenue Recognition (ASC 605). The Company's customers include enterprises, utilities and grid operators. The Company derives recurring revenues from the sale of EIS and related solutions. The Company recognizes revenue when it is earned and all of the following criteria are met: persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and we deem collection to be reasonably assured.
The Company maintains a reserve for customer adjustments and allowances as a reduction in revenues. In determining the 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 used 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 was made and revenues in that period could be affected.
The Company's enterprise revenues from the sales of EIS and related solutions to 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.
EnerNOC Demand Resource
The Company's grid operator revenues and utility revenues primarily reflect demand response revenues from the sale of EnerNOC Demand Resource. During the three and nine months ended September 30, 2015, revenues from grid operators and utilities for EnerNOC Demand Resource were $198,701 and $282,845, respectively. During the three and nine months ended September 30, 2014, revenues from grid operators and utilities for the EnerNOC Demand Resource solution were $318,629 and $396,051, respectively.
The revenues from EnerNOC Demand Resource primarily consist of capacity and energy payments, including ancillary services payments, as well as payments derived from the effective management of the Company's portfolio of demand response capacity, 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 EnerNOC Demand Resource by making demand response capacity available in open market programs and pursuant to contracts that the Company enters into with electric power grid operators and utilities.
The Company recognizes revenue from EnerNOC Demand Resource 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

8

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. EnerNOC Demand Resource energy 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.
EnerNOC Demand Resource 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 months ended September 30 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 Limited demand response product are recognized during the three months ended September 30. As a result of the billing period not coinciding with the revenue recognition period, the Company had $110,584 and $96,404 in unbilled revenues from PJM at September 30, 2015 and December 31, 2014, respectively.
Two new demand response programs, which we refer to as the PJM Extended program and the PJM Annual program, were introduced in the PJM market beginning in the 2014/2015 delivery year (June 1, 2014-May 31, 2015). 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 program are separate and distinct from the Company’s participation in other offerings within the PJM open market program. 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 and therefore, revenue from the PJM Extended program is deferred and recognized at the end of the delivery period (i.e., May). Under the PJM Annual program, the delivery period is from June through May of the following year. Consistent with the PJM Limited and PJM Extended programs, to the extent the Company has MW obligation in the PJM Annual program, until the Company is able to reliably estimate the amount of fees potentially subject to adjustment or refund, revenue from the PJM Annual program will be deferred and recognized at the end of the delivery period (i.e., May). However, in the event the Company reduces its MW obligation for a given program to zero through the effective management of its portfolio, including the Company’s participation in PJM incremental auctions, the Company recognizes revenue from such products at the beginning of the delivery year.
Historically, all capacity revenues related to the Company's participation in the Western Australia open market have been deferred and recognized upon an emergency event dispatch or the end of the program period on September 30th as the Company was not able to reliably estimate the amount of fees potentially subject to adjustment or refund. As of September 30, 2014, the Company determined that the amount of fees potentially subject to adjustment or refund were reliably estimable and began recognizing revenue ratably over the twelve month program period beginning with the new program year in Western Australia commencing on October 1, 2014.
EnerNOC Demand Manager
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, and recognizes 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 program start-up and installation fees, which the Company recognizes over the estimated customer relationship period, which is generally the greater of three years or the contract period.
Stock-Based Compensation
The Company maintains stock-based compensation plans for its employees and outside directors and accounts for stock-based compensation arrangements in accordance with the authoritative guidance, which requires the Company to measure and record compensation expense in its condensed consolidated financial statements using a fair value method. See Note 9 for further information regarding the Company’s stock-based compensation plans.

9

Internal Use Software
The Company applies the provisions of ASC 350-40, Internal-Use Software (ASC 350-40), which requires computer software costs associated with internal use software to be expensed as incurred until certain capitalization criteria are met. Internal use software development costs of $2,583 and $1,507 for the three months ended September 30, 2015 and 2014, respectively, and $6,155 and $4,648 for the nine months ended September 30, 2015 and 2014, have been capitalized in accordance with ASC 350-40. Capitalized costs are amortized over the assets' estimated useful lives. Amortization of capitalized software development costs was $1,893 and $1,547 for the three months ended September 30, 2015 and 2014, respectively and $5,288 and $4,573 for the nine months ended September 30, 2015 and 2014, respectively. Accumulated amortization of capitalized software development costs was $32,891 and $27,603 as of September 30, 2015 and December 31, 2014, respectively.
Cost Method Investments
The Company holds investments in privately-held companies of approximately $2,500 and $1,000 as of September 30, 2015 and December 31, 2014, respectively, which are accounted for based on the cost method and are included in deposits and other assets in the accompanying condensed consolidated balance sheets.
In August 2014, the Company purchased a convertible promissory note for a purchase price of $1,500 in a privately-held SaaS company that serves businesses seeking an innovative approach to measure and track the positive business impact of engaging employees in sustainability through technology. At the time of the purchase, the Company concluded that this investment should be accounted for as an available-for-sale investment and was classified as such as of December 31, 2014. During the nine months ended September 30, 2015, the note was converted into Series A-1 preferred stock. As the preferred stock does not have a readily determinable fair value it is exempt from the scope of ASC 320, Investments-Debt and Equity Securities, and is thus carried at cost as of September 30, 2015.
The Company periodically reviews these investments for impairment. If the Company determines that an other-than-temporary impairment has occurred, it will write-down the investment to its fair value. For the three and nine months ended September 30, 2015, the Company determined that the fair value of its cost method investments was not estimable and to do so would be impractical as there were no identified events or changes in circumstances that had a significant adverse effect on the fair value of the investments.
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.
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 of World Energy's outstanding common stock 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 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 for which the per share exercise price was equal to or less than $5.50 per share, and issued replacement awards for World Energy vested, out-of-the-money stock options and non-vested stock options for a total value 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.

10

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 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 September 30, 2015, the acquired intangible assets will be amortized as follows: customer relationships (backlog) of 4.2 years; customer relationships (contract renewals) of 14.2 years and developed technology of 9.2 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


As of the filing date of this Quarterly Report on Form 10-Q, the Company remains in the process of valuing the assets acquired and liabilities assumed of World Energy’s business, including accounts receivable and other liabilities.
     Cash
$
2,702

     Accounts receivable (1)
8,946

     Prepaid expenses and other current assets
1,596

     Property and equipment
449

     Identified intangible assets
41,400

     Goodwill
39,560

     Accounts payable, accrued expenses and other liabilities (1)
(12,247
)
     Deferred revenue
(320
)
     Deferred tax liabilities, net
(2,173
)
        Total
$
79,913

(1) During the nine months ended September 30, 2015, the Company recorded an acquisition accounting adjustment of $391 to reduce accounts receivable and a $300 adjustment to reduce accrued expenses and other liabilities. The acquisition accounting is not complete and additional information that existed at the acquisition date may become known to the Company during the fourth quarter of 2015.

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 WEES. 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 WEES that were expected to be sold should be classified as held for sale as of January 5, 2015. A definitive asset purchase agreement was executed on July 31, 2015 and the sale of WEES subsequently closed on October 16, 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.

11

The following table summarizes the assets and liabilities held for sale as of September 30, 2015:

As of September 30, 2015
Goodwill
$
751

Inventories
623

Fixed assets
49

     Assets held for sale
$
1,423




Accounts payable
$
(422
)
Deferred revenue
(55
)
     Liabilities held for sale
$
(477
)
The Company has concluded that the sale of WEES does not meet the criteria of discontinued operations under ASC 205-20, Discontinued Operations, because it 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 and nine months ended September 30, 2015.
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 September 30, 2015 and December 31, 2014:
 
 
 
As of September 30, 2015
 
As of December 31, 2014
 
Weighted Average
Amortization
Period (in years)
 
Gross
Carrying
Amount
 
Accumulated
Amortization
 
Gross
Carrying
Amount
 
Accumulated
Amortization
Customer relationships
6.86
 
$
60,715

 
$
(23,527
)
 
$
37,516

 
$
(19,725
)
Customer contracts
1.33
 
7,896

 
(6,398
)
 
4,912

 
(3,618
)
Employment and non-compete agreements
0.94
 
3,091

 
(2,174
)
 
3,198

 
(1,821
)
Software
0.00
 
170

 
(170
)
 
120

 
(120
)
Developed technology
6.36
 
24,561

 
(6,063
)
 
13,615

 
(3,407
)
Trade name
0.25
 
1,097

 
(1,002
)
 
1,124

 
(777
)
Patents
4.38
 
180

 
(97
)
 
180

 
(86
)
Total
 
 
$
97,710

 
$
(39,431
)
 
$
60,665

 
$
(29,554
)
Amortization expense related to definite-lived intangible assets amounted to $3,662 and $2,391 for the three months ended September 30, 2015 and 2014, respectively and $11,607 and $6,753 for the nine months ended September 30, 2015 and 2014, respectively. Amortization expense for acquired developed technology, which was $923 and $515 for the three months ended September 30, 2015 and 2014, respectively, and $2,848 and $1,482 for the nine months ended September 30, 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 years at September 30, 2015. Amortization expense is estimated to be approximately $2,945, $10,943, $9,175, $7,172, $5,893 and $22,151 for the three months ending December 31, 2015, and years ending 2016, 2017, 2018, 2019 and through the remaining years of the asset's useful life, respectively.

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4. Goodwill
The Company accounts for goodwill in accordance with ASC 350, Intangibles-Goodwill and Other (ASC 350), which requires that goodwill is not amortized, but is subject to an annual impairment test. There was no impairment of goodwill as a result of the annual impairment test analysis completed during the fourth quarter of 2014. There were no indicators of impairment during the nine months ended September 30, 2015.
The following table shows the change of the carrying amount of goodwill from December 31, 2014 to September 30, 2015:
Balance at December 31, 2014
$
114,939

Foreign currency translation impact
(4,769
)
Acquisition of World Energy (Note 2)
39,560

Assets held for sale
(751
)
Current period purchase price adjustment (1)
260

Balance at September 30, 2015
$
149,239

(1) The current period purchase price adjustment relates to the December 2014 acquisition of Pulse Energy, Inc. for which the Company adjusted certain estimates associated with the acquired deferred tax assets.
5. Net Income (Loss) Per Share

Computation of basic and diluted net income (loss) per share is as follows (in thousands, except per share information):
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
Numerator:
2015
 
2014
 
2015
 
2014
Net income (loss) for basic earnings per share
12,987

 
96,673

 
(56,095
)
 
38,875

ADD: Interest expense related to convertible notes
2,118

 
980

 
6,251

 
980

Net income (loss) for diluted earnings per share
15,105

 
97,653

 
(49,844
)
 
39,855

Denominator:
 
 
 
 
 
 
 
Basic weighted average common shares outstanding
28,507,939

 
27,795,154

 
28,282,647

 
28,075,291

Weighted average common stock equivalents
340,707

 
877,088

 
—

 
1,068,138

Incremental shares from assumed conversion of convertible notes
5,774,928

 
2,761,922

 
—

 
930,758

Diluted weighted average common shares outstanding
34,623,574

 
31,434,164

 
28,282,647

 
30,074,187

 
 
 
 
 
 
 
 
Basic net income (loss) per share
$
0.46

 
$
3.48

 
$
(1.98
)
 
$
1.38

Diluted net income (loss) per share
$
0.44

 
$
3.11

 
$
(1.98
)
 
$
1.33

 
 
 
 
 
 
 
 
Anti-dilutive shares relate to:
 
 
 
 
 
 
 
Stock options
473,848

 
1,667

 
418,024

 
4,602

Nonvested restricted stock
2,285,100

 
91,755

 
2,228,630

 
384,031

Restricted stock units
72,261

 
7,144

 
72,261

 
10,076

Convertible debt
—

 
—

 
5,774,928

 
—

In reporting periods in which the Company reports net loss, anti-dilutive shares consist of the impact of those number of shares that would have been dilutive had the Company had net income plus the number of common stock equivalents that would have been anti-dilutive had the Company had net income. In those reporting periods in which the Company reports net income, 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.

13

On May 27, 2015, the Company received stockholder approval at its annual meeting of stockholders (the Annual Meeting) to elect to settle conversions of $160,000 aggregate principal amount of its 2.25% convertible senior notes due August 15, 2019 (the 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. Under the applicable accounting standards, if an entity controls the means of settlement and past experience or a stated policy provides a reasonable basis to believe that the Notes will be partially or wholly settled in cash, the shares issuable upon conversion of convertible debt instruments may be excluded from the calculation of diluted earnings per share. The Company used the "if-converted" method to calculate diluted earnings per share for the three months ended September 30, 2015 as a result of an uncertainty as to its ability to reliably estimate cash flows into 2019 that would support repayment in cash. For the nine months ended September 30, 2015, the convertible debt is not assumed to be converted as the impact is anti-dilutive. See Note 7 for further information regarding the Company's convertible debt.
The Company excludes the shares issued in connection with restricted stock awards from the calculation of basic weighted average common shares outstanding until such time as those shares vest. In addition, with respect to restricted stock awards that vest based on achievement of performance conditions, because performance conditions are considered contingencies under ASC 260, Earnings Per Share, 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 September 30, 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 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.

14

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 $2,500 of investments recorded at cost as of September 30, 2015. The Company has $160,000 of convertible debt outstanding (Note 7) as of September 30, 2015. The fair value of the convertible debt was approximately $112,800 and $133,392 as of September 30, 2015 and December 31, 2014 and was determined based on the quoted market price and is classified as Level 1 measurement.
The table below presents the balances of assets and liabilities measured at fair value on a recurring basis at September 30, 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 September 30, 2015
 
 
 
 
 
 
 
Assets: Money market funds (1)
$
113,745

 
$
113,745

 
$
—

 
$
—

 
 
 
 
 
 
 
 
Liabilities: Contingent purchase price consideration (2)
803

 
—

 
—

 
803

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

 
$
225,815

 
$
—

 
$
—

 
 
 
 
 
 
 
 
Liabilities: Contingent purchase price consideration (2)
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 (Activation Energy) and Entelios AG (Entelios) in February 2014. As of September 30, 2015, approximately $700 associated with the Activation Energy acquisition has been reflected in accrued expense and other current liabilities in the condensed consolidated balance sheet. The additional $103 relates to the Entelios earn-out, which is reflected in other liabilities in the condensed consolidated balance sheet. As of December 31, 2014, approximately $312 was recorded in accrued expense and other current liabilities, while the remaining $337 was recorded in other liabilities in the condensed consolidated balance sheet.
The following is a rollforward of the Level 3 assets and liabilities from January 1, 2015 through September 30, 2015:
 
Liabilities
Balance January 1, 2015
$
649

Cash payment during the period
(277
)
Increase due to change in assumptions and present value accretion
468

Change due to movement in foreign exchange rates
(37
)
Balance September 30, 2015
$
803

 
7. Borrowings and Credit Arrangements
Credit Agreement
On August 11, 2014, the Company entered into a $30,000 senior secured 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), which was subsequently amended on October 23, 2014. The 2014 credit facility is subject to continued covenant compliance and borrowing base requirements. As of September 30, 2015, the Company was in compliance with all of its covenants under the 2014 credit facility. On August 6, 2015, the Company and SVB entered into a second amendment to the 2014 credit facility to extend the termination date from August 11, 2015 to August 9, 2016. The Company believes that it is reasonably assured that it will comply with the covenants of the 2014 credit facility through its expiration date of August 9, 2016. As of September 30, 2015, the Company had no borrowings, but had outstanding letters of credit totaling

15

$22,599 under the 2014 credit facility. As of September 30, 2015, the Company had $7,401 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). The Notes include 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, because the Company received approval at the Annual Meeting, it may elect to 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. 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. During the three months ended September 30, 2015, the Company was reimbursed for transaction costs totaling $400 which was allocated to the liability component. The transaction costs allocated to the liability represent debt issuance costs which are recorded as an asset and are being amortized to interest expense on a straight-line basis over a five year period. As of September 30, 2015, $710 and $2,285 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
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
Accretion of debt discount
$
1,043

 
$
474

 
$
3,063

 
$
474

Amortization of deferred financing costs
175

 
76

 
508

 
76

Non-cash interest expense
1,218

 
550

 
3,571

 
550

2.25% accrued interest
900

 
430

 
2,680

 
430

Total interest expense from Notes
$
2,118

 
$
980

 
$
6,251

 
$
980

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, comprised of the contingent interest feature related to timely SEC filing failure, which requires bifurcation as the feature 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 September 30, 2015.
8. Commitments and Contingencies
The Company leases certain office space under various operating leases. In addition to rent, the leases require the Company to pay for taxes, insurance, maintenance and other operating expenses. Certain of these leases contain stated escalation clauses while others contain renewal options. The Company recognizes rent expense on a straight-line basis over the term of the lease, excluding renewal periods, unless renewal of the lease is reasonably assured.
As of September 30, 2015, the Company was contingently liable under outstanding letters of credit for $22,599. As of September 30, 2015 and December 31, 2014, the Company had restricted cash balances of $2,314 and $813, respectively, which primarily related to cash utilized to collateralize certain demand response programs. These amounts are included in prepaid expenses and other current assets and deposits and other assets, respectively, in the unaudited condensed consolidated balance sheet.

16

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 September 30, 2015 were $20,410 and included deposits held by certain customers of $47 at September 30, 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 September 30, 2015, the Company had $600 in deferred fees for these arrangements which were included in deferred revenues. As of September 30, 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 $7,422.
On May 23, 2014, the United States Court of Appeals for the D.C. Circuit held in EPSA v. FERC that 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. See Part I-Item IA under the heading “Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, as amended, for further information regarding EPSA v. FERC. 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 and oral arguments were heard on October 14, 2015. Order 745 remains in effect per the Court’s stay pending the issuance of a decision by the U.S. Supreme Court.
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 and as a result, no loss accrual is currently recorded under ASC 450. However, the Company has 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 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 September 30, 2015, the Company has received and deferred $2,772 of fees related to these programs.
The Company is currently involved in an ongoing matter related to a review of certain services provided under a contractual arrangement with an enterprise customer. This matter is in initial stages and no lawsuit has currently been filed. The Company does not currently believe it is probable that a loss has been incurred and therefore, no amounts have been accrued related to this matter. However, the Company has determined that it is reasonably possible that it may incur a loss related to this matter. The potential amount of such a loss is not currently estimable because the matter is at an early stage and involves unresolved questions of fact.


17

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), which was amended by the Company’s stockholders at the Annual Meeting held on May 27, 2015 to increase the number of shares of common stock authorized for issuance under the 2014 Plan by 1,700,000 shares. As of September 30, 2015, 2,580,300 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). As a result of the assumption, incentive and nonstatutory stock options or stock purchase rights may be granted under the World Energy Plan to employees of the Company who were employees of World Energy prior to January 5, 2015 or were hired by the Company after January 5, 2015. At September 30, 2015, 94,517 stock-based awards were available for future grants. 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 and Tax Withholding Obligations
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 2014 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.
On August 6, 2015, the Company's Board of Directors approved a new share repurchase program, effective upon the expiration of the Company’s 2014 Repurchase Program on August 8, 2015, that will enable the Company to repurchase up to $50,000 of the Company’s common stock during the period from August 9, 2015 to August 9, 2016 (the 2015 Repurchase Program). Repurchases under the Company’s 2015 Repurchase Program are expected to be made periodically on the open market as market and business conditions warrant, or under a Rule 10b5-1 plan. During the three and nine months ended September 30, 2015, the Company did not make any repurchases of its common stock under the 2014 Repurchase Program or the 2015 Repurchase Program.
The Company withheld 68,367 and 311,244 shares of its common stock during the three and nine months ended September 30, 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 and the World Energy Plan.
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.
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.

18

Stock-based compensation expense recorded in the unaudited condensed consolidated statements of operations was as follows:
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
Selling and marketing expenses
$
1,243

 
$
1,512

 
$
3,194

 
$
4,077

General and administrative expenses
2,061

 
2,262

 
7,187

 
7,066

Research and development expenses
351

 
361

 
1,004

 
1,018

Total stock-based compensation expense (1)
$
3,655

 
$
4,135

 
$
11,385

 
$
12,161

(1) Stock-based compensation expense for the three and nine months ended September 30, 2015 include $2 and $495, respectively, related to the acquisition of World Energy that was settled with the equivalent cash payments.
In June 2015, the Company entered into a separation agreement with a former employee. The Company recorded a reversal of previously recognized stock-based compensation expense during the nine months ended September 30, 2015 in the amount of $834 related to the cancellation of non-vested awards upon termination.
Stock-based compensation expense related to share-based awards granted to non-employees was not material for the three and nine months ended September 30, 2015 and 2014. The Company recognized an income tax benefit of $219 from stock-based compensation arrangements during the three and nine months ended September 30, 2014. The Company did not recognize an income tax benefit from stock-based compensation arrangements during the three and nine months ended September 30, 2015. No material stock-based compensation expense was capitalized during the three and nine months ended September 30, 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 and nine months ended September 30, 2015, the Company recorded $128 and $380 of stock-based compensation expense related to this performance based bonus. During the three and nine months ended September 30, 2014, the Company recorded $129 and $382 of stock-based compensation expense related to this performance based bonus.
The EnerNOC, Inc. Amended and Restated 2003 Stock Option and Incentive Plan, the Amended and Restated 2007 Employee, Director and Consultant Stock 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. During the nine months ended September 30, 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.

19

Stock Options
The following is a summary of the Company’s stock option activity during the nine months ended September 30, 2015:
 
Nine Months Ended September 30, 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
(109,617
)
 
 
 
9.80

 
771

(3)
Canceled
(57,624
)
 
 
 
16.60

 
 
 
Outstanding at September 30, 2015
636,750

 
$0.51 - $43.38
 
$
18.69

 
$
933

(4)
Weighted average remaining contractual life in years: 2.2
 
 
 
 
 
 
 
 
Exercisable at end of period
603,208

 
$0.51 - $43.38
 
$
19.06

 
$
932

(4)
Weighted average remaining contractual life in years: 2.1
 
 
 
 
 
 
 
 
Vested or expected to vest at September 30, 2015 (1)
634,234

 
$0.51 - $43.38
 
$
18.69

 
$
933

(4)
 
(1)This represents the number of vested options as of September 30, 2015 plus the number of non-vested options expected to vest as of September 30, 2015 based on a 7.5% forfeiture rate.
(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 weighted-average exercise price of the underlying options.
(3)The aggregate intrinsic value was calculated based on the difference between the fair value of the Company’s common stock on the applicable exercise dates and the weighted-average 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 September 30, 2015 of $7.90 and the weighted-average exercise price of the underlying options.
The weighted average fair value per share of options granted during the nine months ended September 30, 2015 was $9.92.
As of September 30, 2015, all 636,467 options were held by employees and directors of the Company and 283 option were held by a consultant. As of September 30, 2015, the Company had $461 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 1.6 years.

Restricted Stock
The following table summarizes the Company’s restricted stock activity during the nine months ended September 30, 2015:
 
Number of
Shares
 
Weighted Average
Grant Date Fair
Value Per Share
Nonvested at December 31, 2014
2,170,267

 
$
17.18

Granted
1,439,283

 
10.98

Vested
(834,269
)
 
16.13

Cancelled
(317,526
)
 
15.67

Nonvested at September 30, 2015
2,457,755

 
$
14.60

For non-vested restricted stock subject to service-based vesting conditions outstanding as of September 30, 2015, the Company had $23,427 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.7 years. For non-vested restricted stock subject to performance-based vesting conditions outstanding that were probable of vesting as of September 30, 2015, which represents all of the outstanding non-vested restricted stock subject to performance-based vesting conditions, the Company had $2,075 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 1.4 years.

20

In February 2015, the Company entered into a separation agreement with a former employee, which changed the employee’s status to non-employee consultant as of July 1, 2015 and provided for the vesting of 12,514 shares of previously non-vested restricted stock, to continue to vest through January 2, 2016, as long as the individual continues to serve as a consultant through the date of the applicable vesting. Through the non-employee consultation period, the restricted stock will be fair valued at the end of each reporting period, with changes in fair value being recorded to the consolidated statement of operations.
Restricted Stock Units
The following table summarizes the Company’s restricted stock unit activity during the nine months ended September 30, 2015:
 
Number of
Shares
 
Weighted Average
Grant Date Fair
Value Per Share
Nonvested at December 31, 2014
256,872

 
$
20.08

Granted
69,950

 
10.59

Vested
(4,939
)
 
19.64

Cancelled
(39,266
)
 
19.00

Nonvested at September 30, 2015
282,617

 
$
17.84

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. Vesting would be triggered for these shares if the employee remained employed with the Company and if certain earnings targets were met in 2014, 2015, and 2016.  As of September 30, 2015, the Company has determined that the earnings targets were not probable of being met, and thus the awards have not been deemed probable of vesting.
For non-vested restricted stock units subject to service-based vesting conditions outstanding as of September 30, 2015, the Company had $631 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 3.1 years. For non-vested restricted stock units subject to outstanding performance-based vesting conditions that were not probable of vesting at September 30, 2015, the Company had $4,220 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.
10. Income Taxes
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. For the nine month period ended September 30, 2015, the Company determined that it was able to reliably estimate its annual effective tax rate in all jurisdictions in which it operates.
The Company recorded a $417 tax expense and $1,523 tax benefit for the three month and nine month periods ended September 30, 2015. The tax expense for the three months ended September 30, 2015 consists of 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, and tax expense generated from foreign operations for the quarter. The benefit for income taxes for the nine months ended September 30, 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.
The Company recorded a tax expense of $12,111 and $11,950 for the three month and nine month periods ended September 30, 2014, respectively. The tax expense for the three months ended September 30, 2014 consists of a tax expense on its foreign income, a U.S. tax expense related to state income taxes where no net operating losses are available, 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 tax expense for the nine months ended September 30, 2014 includes a $1,069 benefit from income taxes due to the release of a portion of the U.S. valuation allowance in connection with the Entech acquisition during the three months ended June 30, 2014 and a $1,120 expense for deferred income taxes in connection with the sale of Utility Solution Consulting (Note 14) during the three months ended June 30, 2014.
ASC 740, Income Taxes, 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 and nine month periods ended September 30, 2015, there were no material changes in the Company’s uncertain tax positions.

21

The Company makes judgments regarding the realizability of our deferred tax assets. The balance sheet carrying value of our net deferred tax assets is based on whether it believes that it is more likely than not that it will generate sufficient future taxable income to realize these deferred tax assets after consideration of all available evidence. The Company regularly reviews its deferred tax assets for recoverability considering historical profitability, projected future taxable income, the expected timing of the reversals of existing temporary differences and tax planning strategies. In assessing the need for a valuation allowance, it considers both positive and negative evidence related to the likelihood of realization of the deferred tax assets. The weight given to the positive and negative evidence is commensurate with the extent to which the evidence may be objectively verified. As such, it is generally difficult for positive evidence regarding projected future taxable income exclusive of reversing taxable temporary differences to outweigh objective negative evidence of recent financial reporting losses. Generally, cumulative loss in recent years is a significant piece of negative evidence that is difficult to overcome in determining that a valuation allowance is not needed.
As of September 30, 2015, the Company has a valuation allowance recorded against certain deferred tax assets. If it is subsequently able to utilize all or a portion of the deferred tax assets for which the remaining valuation allowance has been established, then it may be required to recognize these deferred tax assets through the reduction of the valuation allowance which could result in a material benefit to our results of operations in the period in which the benefit is determined.
11. Concentrations of Credit Risk
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 and New England regions 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 a fair and efficient market. IMO is an entity that was established to administer and operate the Western Australia (WA) wholesale electricity market. No other customers comprised more than 10% of consolidated revenues during the three or nine months ended September 30, 2015 and 2014.
The following table presents the Company’s significant customers.
 
Three Months Ended September 30,
 
2015
 
2014
 
Revenues
 
% of Total
Revenues
 
Revenues
 
% of Total
Revenues
PJM
$
143,804

 
66
%
 
$
224,540

 
68
%
IMO
6,726

 
3
%
 
42,983

 
13
%
 
 
 
 
 
 
 
 
 
Nine Months Ended September 30,
 
2015
 
2014
 
Revenues
 
% of Total
Revenues
 
Revenues
 
% of Total
Revenues
PJM
$
161,618

 
47
%
 
$
245,752

 
58
%
IMO
21,201

 
6
%
 
$
47,380

 
11
%

PJM, Pacific Gas & Electric and Southern California Edison Company were the only customers that each comprised 10% or more of the Company’s accounts receivable balance at September 30, 2015, representing 10%, 11% and 13%, 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 $110,584 and $96,404 at September 30, 2015 and December 31, 2014, respectively. There was no significant unbilled revenue for any other customers at September 30, 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 $47 and $3,033 at September 30, 2015 and December 31, 2014, respectively.
12. 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 has determined that its chief operating decision maker is 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

22

United Kingdom. Revenues are based upon the location of the Company's entity that provides the service, and internationally totaled $22,703 and $57,739 for the three months ended September 30, 2015 and 2014, respectively and $64,254 and $80,471 for the nine months ended September 30, 2015 and 2014.
Revenues by geography as a percentage of total revenues are as follows:
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
United States
90
%
 
82
%
 
81
%
 
81
%
Australia
3

 
13

 
7

 
12

Canada
2

 
3

 
5

 
3

All other
5

 
2

 
7

 
4

Total
100
%
 
100
%
 
100
%
 
100
%
As of September 30, 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.
13. 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 the Company’s consolidated financial condition, results of operations or cash flows.
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 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. Among other things, the MOU provided 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. On August 20, 2015, after holding a hearing, the Delaware Court of Chancery Court approved the settlement.
14. Gain on Sale of Service Line
On April 16, 2014, the Company entered into an agreement with a third party to sell a component of the business, Utility Solutions Consulting, that the Company acquired in connection with its acquisition of Global Energy Partners, Inc. (Global Energy) related to consulting and engineering support services to the global electric utility industry, with a particular focus on providing consulting services to utilities.
On May 30, 2014, the Company sold the component for $4,750. The Company concluded that Utility Solutions Consulting met the definition of a business in accordance with ASC 805.
The following table summarizes the assets sold in connection with this transaction:
Customer relationship intangible assets, net
$
153

Other definite-lived intangible assets, net
39

Goodwill
489

Total assets sold
$
681

The amount of goodwill allocated to Global Energy was based on the relative fair values of this business. In accordance with the agreement, the Company received $4,275 at closing and $475 was held in escrow to cover general representations and warranties, as well as, potential purchase price adjustment, if any, for fees that could have been earned related to contracts that were not assigned. The potential remaining purchase price adjustment for fees that could have been earned for contracts that

23

were not assigned was $364 as of June 30, 2014. During the three months ended June 30, 2015, the Company was reimbursed $364 from escrow. The Company recognized a gain from the sale of Global Energy totaling $3,378, net of transaction costs totaling $327 during the three months ended June 30, 2014. During the three months ended September 30, 2014, the remaining applicable contracts were assigned and the Company recognized $359 of the previously deferred gain resulting in a total gain recognized during the nine months ended September 30, 2014 of $3,737.
The Company concluded that the Utility Solutions Consulting disposal group meets the criteria of discontinued operations under ASC 205-20, Discontinued Operations (ASC 205-20). However, the Company determined that the operations of Utility Solutions Consulting were neither quantitatively or qualitatively material to the Company’s current or historical consolidated operations and therefore, the results of operations of Utility Solutions Consulting have not been presented as discontinued operations in the Company’s accompanying consolidated statements of operations for the three and nine months ended September 30, 2014. As a result, the gain has been reflected as a separate component within income from operations with the corresponding discrete tax charge of $1,102 related to the increase in the deferred tax liability as a result of the increased book and tax basis difference in goodwill being recorded as a component of the Company’s provision for income taxes during the nine month periods ended September 30, 2014.
15. Gain on Sale of Assets
On April 22, 2014, the Company entered into an agreement with a third party, enterprise customer of the Company to sell its remaining two contractual demand response capacity resources 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 each of these two demand response capacity resources with such sale and transfer being effective as of the date that each resource has been paid for in full. The aggregate payment of $5,740 was allocated between each demand response capacity resource based on each resource’s relative fair value as determined by the potential future cash flows from each resource with $2,171 being allocated to the first demand response capacity resource and $3,569 being allocated to the second demand response capacity resource, of which guaranteed fees of $517 were recognized ratably through the end of the contractual period of March 31, 2015. The third party fully paid the purchase price for the first demand response capacity resource during the three months ended June 30, 2014 and as a result, the sale of this resource was completed. As a result of the first sale, the Company recognized a gain on the sale of this asset equal to the purchase price of $2,171 during the nine months ended September 30, 2014. During the nine months ended September 30, 2015, the Company received the remaining balance in the amount of $2,991 from the third party for the second demand response capacity resource and completed the sale resulting in the recognition of a gain on the sale of this asset equal to the purchase price of $2,991.

16. Recent Accounting Pronouncements
In May 2014, the FASB issued guidance codified in ASC 606, Revenue Recognition - Revenue from Contracts with Customers (ASC 606), which amends the guidance in former ASC 605, Revenue Recognition, and most other existing revenue guidance in GAAP, to require an entity to recognize revenue in an amount that reflects the consideration to which the entity expects to be entitled in exchange for transferring goods or services to customers and provide additional disclosures. As amended, the effective date for public entities is annual reporting periods beginning after December 15, 2017 and interim periods therein. As such, we will be required to adopt the standard in the first quarter of fiscal year 2018. Early adoption is not permitted before the first quarter of fiscal year 2017. ASC 606 may be adopted either using a “full retrospective” approach, in which the standard is applied to all of the periods presented, or a “modified retrospective” approach. The Company is currently evaluating which transition method to use and how ASC 606 will affect its financial statements.
In August 2014, the FASB issued Accounting Standards Update (ASU) 2014-15, Presentation of Financial Statements — Going Concern: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (ASU 2014-15). The standard requires that the Company evaluates, at each interim and annual reporting period, whether there are conditions or events that raise substantial doubt about its ability to continue as a going concern within one year after the date the financial statements are issued, and provide related disclosures. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter, and early adoption is permitted. The Company does not expect to early adopt ASU 2014-15, which will be effective for its fiscal year ending December 31, 2016. The Company does not believe the standard will have a material impact on its consolidated financial position and results of operations.
In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (ASU 2015-03). The amendments in this update require that debt issuance costs related to a recognized debt liability (other than revolving credit facilities) be presented in the consolidated balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. This update deals solely with financial statement display matters; recognition and measurement of debt issuance costs are unaffected. ASU 2015-03 is effective for annual periods ending after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for

24

financial statements that have not previously been issued. The Company does not expect to early adopt ASU 2015-03, which will be effective for its fiscal year ending December 31, 2016. 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.
In April 2015, the FASB issued ASU 2015-05, Intangibles—Goodwill and Other—Internal-Use Software: Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement (ASU 2015-05). The standard clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software under ASC 350-40. ASU 2015-05 is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2015, and early adoption is permitted. The Company does not expect to early adopt ASU 2015-05, which will be effective for its fiscal year ending December 31, 2016. The Company does not believe the standard will have a material impact on its consolidated financial position and results of operations.
In September 2015, the FASB issued 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (ASU 2015-16). The standard requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The standard update is effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years. The standard update is to be applied prospectively to adjustments of provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. The Company does not believe the standard will have a material impact on its consolidated financial position and results of operations.


25

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 (EIS) and related solutions. Our enterprise customers use our Software-as-a-Service (SaaS) solutions to transform how they manage and control energy spend for their organizations, while utilities leverage our SaaS solutions to better engage their customers, deliver savings and consumption reductions to help achieve energy efficiency mandates, manage system peaks and grid constraints, and increase 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. EnerNOC Demand Resource is a turnkey demand response resource that matches obligation, in the form of megawatts, or MWs, that we agree to deliver to our utility customers and electric power grid operators, with supply, in the form of MWs that are curtailed from the electric power grid through our arrangements with our enterprise customers.

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.

26

The following table outlines certain non-financial business and operational data utilized as of September 30, 2015 and December 31, 2014:
 
September 30, 2015
 
December 31, 2014
Enterprise Customers(1)(7)
4,100

 
1,300

Enterprise Sites(1)(7)
77,300

 
35,700

Enterprise ARR (in millions)(2)(8)
$
58

 
$
20

Enterprise ARR Gross Churn Rate(2)(9)
15
 %
 
18
%
Enterprise ARR Net Churn Rate (2)(9)
(3
)%
 
15
%
Utility Customers(3)
51

 
52

Utility ARR (in millions)(4)(8)
$
65

 
$
67

Utility ARR Gross Churn Rate(4)(9)
16
 %
 
13
%
Utility ARR Net Churn Rate(4)(9)
14
 %
 
10
%
Grid Operators(5)
14

 
14

Demand Response Customers(6)(7)
6,400

 
6,500

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

 
15,000

 
(1) The term “Enterprise Customers,” which we previously 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 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 Gross 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 (gain) 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 Gross 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

27

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 September 30, 2015 was approximately 4,100 compared to approximately 1,300 at December 31, 2014. This increase primarily reflects the addition of new enterprise 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 enterprise customers, 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 September 30, 2015 was approximately 77,300 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 and new sales of our EIS and related solutions for enterprise customers. Enterprise ARR at September 30, 2015 was approximately $58 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 enterprise 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 gross churn rate was 15% at September 30, 2015 compared to 18% at December 31, 2014. Our enterprise ARR net churn rate was negative 3% at September 30, 2015 compared to 15% at December 31, 2014, which reflects the addition of ARR through upsells to existing enterprise customers.
The number of utility customers at September 30, 2015 was 51 compared to 52 at December 31, 2014. This decrease primarily reflects the non-renewal of certain utility contracts for our demand response offerings, partially offset by added utility software contracts. Utility ARR at September 30, 2015 was approximately $65 million compared to $67 million at December 31, 2014. This decrease primarily reflects a reduction in size or non-renewal of certain utility demand response programs, partially offset by an increase in size of certain utility software contracts. Our utility ARR gross churn rate was 16% at September 30, 2015 compared to 13% at December 31, 2014. Our utility ARR net churn rate was 14% at September 30, 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 gross 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 September 30, 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 6,400 at September 30, 2015, compared to 6,500 at December 31, 2014. The number of demand response sites at September 30, 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.

28

Consolidated Results of Operations
Three and Nine Months Ended September 30, 2015 Compared to the Three and Nine Months Ended September 30, 2014
Revenues
The following table summarizes our revenues for the three and nine months ended September 30, 2015 and 2014 (in thousands):
 
Three Months Ended September 30,
 
Dollar
 
Percentage
 
2015
 
2014
 
Change
 
Change
Revenues:
 
 
 
 
 
 
 
Grid operator
$
173,374

 
$
291,848

 
$
(118,474
)
 
(40.6
)%
Utility
27,160

 
27,741

 
(581
)
 
(2.1
)%
Enterprise
16,790

 
9,833

 
6,957

 
70.8
 %
Total
$
217,324

 
$
329,422

 
$
(112,098
)
 
(34.0
)%
 
Nine Months Ended September 30,
 
Dollar
 
Percentage
 
2015
 
2014
 
Change
 
Change
Revenues:
 
 
 
 
 
 
 
Grid operator
$
238,632

 
$
350,592

 
$
(111,960
)
 
(31.9
)%
Utility
50,498

 
50,011

 
487

 
1.0
 %
Enterprise
51,245

 
25,382

 
25,863

 
101.9
 %
Total
$
340,375

 
$
425,985

 
$
(85,610
)
 
(20.1
)%

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
September 30, 2014 to
September 30, 2015
 
Nine Months Ended
September 30, 2014 to
September 30, 2015
PJM
$
(79,964
)
 
$
(83,381
)
Western Australia (IMO)
(36,257
)
 
(26,178
)
South Korea (KPX)
6,214

 
10,564

New England (ISO NE)
(1,973
)
 
(4,351
)
Alberta (AESO)
(4,174
)
 
(4,742
)
Ontario (OPA)
(1,704
)
 
(2,276
)
Other (1)
(616
)
 
(1,596
)
Total decrease in grid operator revenues
$
(118,474
)
 
$
(111,960
)
 (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 and nine months ended September 30, 2015 as compared to the same periods in 2014 was primarily due to lower revenue associated with capacity auctions and bilateral contracts in the PJM and ISO-NE demand response programs, our increased participation in PJM’s extended program in the 2015/2016 delivery year, which resulted in the deferral of revenue recognition to the second quarter of 2016, and a change during the fourth quarter of 2014 to ratable revenue recognition and decreased pricing in the IMO program. The decrease in revenues was also due to lower pricing associated with fewer enrolled MWs in our Canadian demand response programs in AESO and OPA, and foreign currency exchange losses due to relative weakness of the Canadian and Australian dollars against the US dollar. This decrease in revenue was partially offset by revenue associated with our demand response program in South Korea. In addition, the decrease in PJM revenues for the nine months ended September 30, 2015 as compared to the same period in 2014 was also attributed to significantly lower energy payments resulting from fewer demand response event dispatches during 2015. We currently expect our total revenues from grid operators to decrease during fiscal 2015 as compared to fiscal 2014.


29

Utility Revenues
The overall change in our revenues from utilities was primarily attributable to changes in the following existing operating areas (in thousands):
 
Increase (Decrease)
 
Three Months Ended
September 30, 2014 to
September 30, 2015
 
Nine Months Ended
September 30, 2014 to
September 30, 2015
Pacific Gas & Electric (PG&E)
$
(1,902
)
 
$
(3,144
)
Utility Software
896

 
3,040

Southern California Edison (SCE)
3,772

 
4,804

Idaho Power/Salt River Project (SRP)
(1,972
)
 
(2,754
)
PacifiCorp
(960
)
 
(960
)
Other (1)
(415
)
 
(499
)
Total (decrease) increase in utility revenues
$
(581
)
 
$
487

 
(1)The amounts included in ‘Other’ primarily relate to various utility demand response programs and services, none of which are individually material.
The change in revenues from utility customers during the three and nine months ended September 30, 2015, as compared to the same period in 2014, was primarily due to an increase in utility software revenues related to our acquisition of Pulse Energy, which we acquired in the fourth quarter of 2014, and improved performance during demand response events in our SCE demand response program. This increase was offset by reduced revenue from the conclusion of two domestic demand response programs and a decrease in participation in our PG&E and PacifiCorp demand response programs. We currently expect our fiscal 2015 utility revenues to be relatively consistent with 2014 utility revenues.
 
Enterprise Revenues
The increase in enterprise revenues during the three and nine months ended September 30, 2015, as compared to the same periods in 2014, was primarily related to the expansion of our procurement solutions resulting from our acquisition of World Energy in the first quarter of 2015. We currently expect our fiscal 2015 enterprise revenues to grow between 83%-95% 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 and nine months ended September 30, 2015 and 2014 (dollars in thousands):
Three Months Ended September 30,
2015
 
2014
Gross Profit
 
Gross Margin
 
Gross Profit
 
Gross Margin
$
74,178

 
34.1
%
 
$
160,858

 
48.8
%
Nine Months Ended September 30,
2015
 
2014
Gross Profit
 
Gross Margin
 
Gross Profit
 
Gross Margin
$
131,730

 
38.7
%
 
$
193,480

 
45.4
%
The decrease in gross profit for the three and nine months ended September 30, 2015 as compared to the same periods in 2014, was primarily due to lower revenue associated with capacity auctions and bilateral contracts in the PJM and ISO-NE demand response programs as compared to the same period in 2014, lower pricing and MWs from our Canadian demand response programs in AESO and OPA, and foreign currency exchange losses due to relative weakness of the Canadian and Australian dollars against the US dollar. The decrease was also due to our increased participation in PJM’s extended program in the 2015/2016 delivery year, which resulted in the deferral of profits to the second quarter of 2016, and a change during the fourth quarter of 2014 to ratable revenue recognition and decreased pricing in the IMO program.
The decrease in gross margin for the three and nine months ended September 30, 2015 as compared to the same periods in 2014 was primarily due to a decrease in the percentage of higher margin revenues recognized as a result of the adjustment of

30

our zonal capacity obligations through our participation in PJM incremental auctions and a decrease in the percentage of higher margin revenues recognized from IMO.
We expect that our overall gross margin percentage for fiscal 2015 will be in the high 30% to low 40% range.

Operating Expenses
The following table summarizes our operating expenses for the three and nine months ended September 30, 2015 and 2014 (in thousands):
 
Three Months Ended September 30,
 
Percentage
 
2015
 
2014
 
Change
Selling and marketing
$
22,397

 
$
18,972

 
18.1
 %
General and administrative
26,707

 
24,472

 
9.1
 %
Research and development
6,626

 
5,260

 
26.0
 %
Gain on sale of service line
—

 
(359
)
 
(100.0
)%
     Total operating expenses
$
55,730

 
$
48,345

 
15.3
 %
 
Nine Months Ended September 30,
 
Percentage
 
2015
 
2014
 
Change
Selling and marketing
$
74,563

 
$
56,997

 
30.8
 %
General and administrative
83,450

 
72,340

 
15.4
 %
Research and development
21,812

 
15,432

 
41.3
 %
Gain on sale of service line
—

 
(3,737
)
 
(100.0
)%
Gain on sale of assets
(2,991
)
 
(2,171
)
 
37.8
 %
     Total operating expenses
$
176,834

 
$
138,861

 
27.3
 %

Selling and Marketing Expenses
The following table summarizes our selling and marketing expenses for the three and nine months ended September 30, 2015 and 2014 (in thousands):
 
Three Months Ended September 30,
 
Percentage
 
2015
 
2014
 
Change
Payroll and related costs
$
14,707

 
$
11,914

 
23.4
 %
Stock-based compensation
1,243


1,512

 
(17.8
)%
Other
6,447

 
5,546

 
16.2
 %
     Total selling and marketing expenses
$
22,397

 
$
18,972

 
18.1
 %
 
Nine Months Ended September 30,
 
Percentage
 
2015
 
2014
 
Change
Payroll and related costs
$
47,553

 
$
36,332

 
30.9
 %
Stock-based compensation
3,194

 
4,077

 
(21.7
)%
Other
23,816

 
16,588

 
43.6
 %
     Total selling and marketing expenses
$
74,563

 
$
56,997

 
30.8
 %
The increase in payroll and related costs for the three and nine months ended September 30, 2015 was primarily due to an increase in the number of selling and marketing full-time employees from 274 at September 30, 2014 to 335 at September 30, 2015, most of which resulted from acquisitions that we completed during fiscal 2014 and our acquisition of World Energy in January 2015, and an increase in salary rates per full-time employee. In addition, we experienced an increase in commission expense during the nine months ended September 30, 2015 due to an increase in enterprise revenues. Partially offsetting this increase was the reversal of accrued vacation in the amount of $0.8 million resulting from a change in our U.S. vacation policy from a capped plan to an unlimited plan.
The decrease in stock-based compensation expense for the three months ended September 30, 2015 was primarily due to a decrease in the number of stock-based awards granted during the period. The decrease in stock-based compensation expense

31

for the nine months ended September 30, 2015 was primarily due to the reversal of $0.8 million of stock-based compensation expense related to the cancellation of awards upon the execution of a separation agreement with a former executive officer and the decrease in grant date fair value of stock-based awards. This decrease was partially offset by an increase in the number of stock-based awards granted during the nine months ended September 30, 2015, as well as the immediate recognition of replacement awards issued to certain employees in connection with the acquisition of World Energy.
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 for the three and nine months ended September 30, 2015 was primarily attributable to $0.9 million and $3.4 million increases, respectively, in amortization expense of acquired intangible assets as a result of our 2014 and 2015 acquisitions and $0.3 million and $1.5 million increases, respectively, in overhead, which is based on increased headcount and information technology and communication costs. Also contributing to the increase in other selling and marketing expenses for the nine months ended September 30, 2015 was a $2.2 million increase in various marketing initiatives including channel partner fees and a $0.4 million increase in training and development costs.
General and Administrative Expenses
The following table summarizes our general and administrative expenses for the three and nine months ended September 30, 2015 and 2014 (in thousands):
 
Three Months Ended September 30,
 
Percentage
 
2015
 
2014
 
Change
Payroll and related costs
$
14,497

 
$
13,795

 
5.1
 %
Stock-based compensation
2,061


2,262

 
(8.9
)%
Other
10,149

 
8,415

 
20.6
 %
     Total general and administrative expenses
$
26,707

 
$
24,472

 
9.1
 %
 
Nine Months Ended September 30,
 
Percentage
 
2015
 
2014
 
Change
Payroll and related costs
$
48,028

 
$
40,880

 
17.5
 %
Stock-based compensation
7,187

 
7,066

 
1.7
 %
Other
28,235

 
24,394

 
15.7
 %
     Total general and administrative expenses
$
83,450

 
$
72,340

 
15.4
 %
The increase in payroll and related costs for the three and nine months ended September 30, 2015 was primarily attributable to an increase in the number of general and administrative full-time employees from 438 at September 30, 2014 to 567 at September 30, 2015, most of which resulted from acquisitions that we completed during 2014 and our acquisition of World Energy in January 2015. Partially offsetting this increase was the reversal of accrued vacation in the amount of $1.1 million resulting from a change in our U.S. vacation policy from a capped plan to an unlimited plan.
The decrease in stock-based compensation expense for the three months ended September 30, 2015 was primarily due to a decrease in the number of stock-based awards granted during the period. The slight increase in stock-based compensation expense for the nine months ended September 30, 2015 related to awards settled and replaced in connection with the World Energy acquisition. Partially offsetting this increase was a decrease in grant date fair value of stock-based awards.
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 for the three months ended September 30, 2015 was primarily attributable to a $1.1 million increase in professional service expenses and a $1.1 million increase in software licenses and fees. The increase in other general and administrative expenses for the nine months ended September 30, 2015 was primarily attributable to a $1.5 million increase in rent expense related to our 2014 acquisitions, a $1.4 million increase in direct and incremental expenses in connection with the World Energy acquisition, and a $0.6 million increase in various marketing initiatives. This increase was partially offset by a $1.0 million decrease in professional services.

32

Research and Development Expenses
The following table summarizes our research and development expenses for the three and nine months ended September 30, 2015 and 2014 (in thousands):
 
Three Months Ended September 30,
 
Percentage
 
2015

2014
 
Change
Payroll and related costs
$
3,785

 
$
2,977

 
27.1
 %
Stock-based compensation
351


361

 
(2.8
)%
Other
2,490

 
1,922

 
29.6
 %
     Total research and development expenses
$
6,626

 
$
5,260

 
26.0
 %
 
Nine Months Ended September 30,
 
Percentage
 
2015
 
2014
 
Change
Payroll and related costs
$
12,767

 
$
9,182

 
39.0
 %
Stock-based compensation
1,004

 
1,018

 
(1.4
)%
Other
8,041

 
5,232

 
53.7
 %
     Total research and development expenses
$
21,812

 
$
15,432

 
41.3
 %
During the three months ended September 30, 2015 and 2014, total research and development payroll costs totaled $5.3 million and $4.3 million, respectively, of which $1.5 million and $1.3 million, respectively, were capitalized. During the nine months ended September 30, 2015 and 2014, total research and development payroll costs totaled $16.8 million and $12.6 million, respectively, of which $4.0 million and $3.4 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 140 at September 30, 2014 to 199 at September 30, 2015, most of which resulted from acquisitions that we completed during 2014 and our acquisition of World Energy in January 2015. Partially offsetting this increase was the reversal of accrued vacation in the amount of $0.4 million resulting from a change in our U.S. vacation policy from a capped plan to an unlimited plan.
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 for the three and nine months ended September 30, 2015 was primarily attributable to increases in information technology and communication costs of $0.2 million and $1.6 million, respectively, and consulting and professional fees of $0.3 million and $0.5 million, respectively.
Gain on Sale of Service Line
During the three months ended June 30, 2014, we sold Utility Solutions Consulting for $4.8 million, a component of the business that we acquired in connection with our acquisition of Global Energy related to consulting and engineering support services. We recognized a gain from the sale of Utility Solutions Consulting totaling $3.7 million, net of direct transaction costs totaling $0.3 million during the nine months ended September 30, 2014.
Gain on Sale of Assets
During the three months ended June 30, 2014, we entered into an agreement with a third party enterprise customer to sell two contractual demand response capacity resources related to an open market demand response program to that third party allowing the third party the ability to enroll directly with the applicable grid operator. The third party fully paid the purchase price for the first demand response capacity resource during the three months ended June 30, 2014 and as a result, the sale of this resource was completed resulting in the recognition of a gain on the sale of this asset equal to the purchase price of $2.2 million. During the nine months ended September 30, 2015, we received payment in full from the third party for the second demand response capacity resource and completed the sale resulting in the recognition of a gain on the sale of this asset of $3.0 million.
Interest Expense and Other Expense, Net
Interest expense was $2.3 million for the three months ended September 30, 2015 compared to $1.5 million for the three months ended September 30, 2014 and $6.8 million for the nine months ended September 30, 2015 compared to $2.6 million for the nine months ended September 30, 2014. This increase was largely due to interest expense recorded on our convertible senior notes due August 2019, which was $2.1 million and $6.3 million for the three and nine months ended September 30, 2015, respectively.
Other expense, net for the three and nine months ended September 30, 2015 was $2.8 million and $5.8 million, respectively, which primarily includes foreign currency losses offset partially by other income. The $0.6 million and the $4.5 million increases as compared to the three and nine months ended September 30, 2014, respectively, was primarily due to

33

fluctuations in the Canadian dollar, EURO and Australian dollar, which resulted in foreign currency losses of $2.9 million and $6.2 million for the three and nine months ended September 30, 2015, respectively, as compared to $2.5 million and $1.8 million losses for the three and nine months ended September 30, 2014, respectively. We currently do not hedge any of our foreign currency transactions.
Income Taxes
Each interim period is considered an integral part of the annual period and tax expense is measured using an estimated annual effective tax rate. An enterprise is required at the end of each interim reporting period to make its best estimate of the annual effective tax rate for the full fiscal year and use that rate to provide for income taxes on a current year-to-date basis. 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. For the nine month period ended September 30, 2015, we determined that we were able to reliably estimate our annual effective tax rate in all jurisdictions in which we operate.
For the three and nine month periods ended September 30, 2015, we recorded a $0.4 million tax expense and $1.5 million tax benefit, respectively. The tax expense is due to 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, and tax expense generated from foreign operations for the quarter. The benefit for income taxes for the nine month period ended September 30, 2015 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.
We recorded a tax expense of $12,111 and $11,950 for the three month and nine month periods ended September 30, 2014, respectively. The tax expense for the three months ended September 30, 2014 consists of a tax expense on our foreign income, a U.S. tax expense related to state income taxes where no net operating losses are available, 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 tax expense for the nine months ended September 30, 2014 includes a $1,069 benefit from income taxes due to the release of a portion of the U.S. valuation allowance in connection with the Entech acquisition during the three months ended June 30, 2014 and a $1,120 expense for deferred income taxes in connection with the sale of Utility Solution Consulting during the three months ended June 30, 2014.
ASC 740, Income Taxes (ASC740), 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 and nine month periods ended September 30, 2015, there were no material changes in our uncertain tax positions.
Deferred tax assets are reduced by a valuation allowance if, based on the weight of available positive and negative evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of September 30, 2015, we have a valuation allowance recorded against certain net domestic and foreign deferred tax assets. Based on our analysis, we have concluded that it is not more likely than not that the majority of our deferred tax assets can be realized and therefore a valuation allowance has been assigned to these deferred tax assets. If we are subsequently able to utilize all or a portion of the deferred tax assets for which a valuation allowance has been established, then we may be required to recognize these deferred tax assets through the reduction of the valuation allowance which could result in a material benefit to our results of operations in the period in which the benefit is determined.

Liquidity and Capital Resources
Overview
We have generated significant cumulative losses since inception. As of September 30, 2015, we had an accumulated deficit of $125.4 million. As of September 30, 2015, our principal sources of liquidity were cash and cash equivalents totaling $141.9 million, a decrease of $112.5 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 September 30, 2015 and December 31, 2014, the majority of our excess cash was invested in money market funds.
During the nine months ended September 30, 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 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 introduction and market acceptance of our new EIS and related solutions, the expansion of our selling and marketing and research and development activities, and the geographic expansion of our business operations.

34

Cash Flows
The following table summarizes our cash flows for the nine months ended September 30, 2015 and 2014 (in thousands):
 
Nine Months Ended September 30,
 
2015
 
2014
Cash flows (used in) provided by operating activities
$
(18,226
)
 
$
29,712

Cash flows used in investing activities
(88,881
)
 
(53,460
)
Cash flows (used in) provided by financing activities
(2,331
)
 
121,105

Effects of exchange rate changes on cash and cash equivalents
(2,973
)
 
(331
)
     Net change in cash and cash equivalents
$
(112,411
)
 
$
97,026

Cash Flows (Used in) Provided by Operating Activities
Cash used in operating activities for the nine months ended September 30, 2015 was $18.2 million and consisted of net loss of $56.1 million and $7.8 million of net cash used in working capital which was partially offset by $45.7 million of non-cash items. The non-cash items consisted primarily of depreciation and amortization, stock-based compensation expense, unrealized foreign exchange translation losses, non-cash interest expense and deferred taxes. Cash used in working capital consisted of an increase of $13.2 million in trade accounts receivable, an increase of $14.4 million in unbilled revenue, most of which related to the PJM demand response market, an increase in capitalized incremental direct customer contract costs of $12.8 million, a decrease of $19.5 million in accounts payable, accrued expenses and other current liabilities, and an increase in prepaid expenses and other current assets of $7.4 million. Cash used in working capital was partially offset by an increase of $39.4 million in accrued capacity payments, and an increase of $23.0 million in deferred revenue.
Cash provided by operating activities for the nine month period ended September 30, 2014 was $29.7 million and consisted of net income of $38.8 million and $45.5 million of non-cash items, offset by gains of $5.9 million on the sales of service line and assets, which are included as a component of net income but represent investing activities and $48.7 million of net cash used in working capital. The non-cash items consisted primarily of depreciation and amortization, stock-based compensation charges, equipment charges, unrealized foreign exchange transaction losses, deferred taxes and non-cash interest expense. Cash used in working capital consisted of an increase of $20.0 million in accounts receivable due to the timing of cash receipts under the demand response programs in which we participate, an increase of $89.8 million in unbilled revenues, most of which related to the PJM demand response market, an increase in prepaid expenses and other assets of $1.5 million, a decrease in other noncurrent liabilities of $0.5 million and a decrease of $6.7 million in deferred revenue primarily related to the Western Australia demand response program. These amounts were partially offset by cash provided by working capital consisting of a decrease in capitalized incremental direct customer contract costs of $2.9 million, an increase of $49.7 million in accrued capacity payments, an increase of $1.5 million in accrued payroll and related expenses, and an increase of $15.5 million in accounts payable, accrued expenses and other current liabilities primarily due to the timing of payments.
Cash Flows Used in Investing Activities
Cash used in investing activities was $88.9 million for the nine months ended September 30, 2015. During the nine months ended September 30, 2015, we made net payments of $77.6 million for acquisitions, which includes the purchase of World Energy, as well as an earn-out payment for Activation Energy DSU Limited, or Activation Energy, a working capital settlement for Pulse Energy and a purchase price adjustment related to Pulse Energy. In addition, during the nine months ended September 30, 2015, we made $17.7 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 nine months ended September 30, 2015 was partially offset by a decrease in our restricted cash and deposits of $3.4 million due to a decrease in deposits principally related to the financial assurance requirements for the demand response programs in which we participate, in addition to the proceeds from the sale of assets of $3.0 million.
Cash used in investing activities was $53.5 million for the nine month period ended September 30, 2014. During the nine month period ended September 30, 2014, we made payments, net of cash acquired, of $3.9 million, $20.2 million, $12.0 million and $0.3 million for the acquisitions of Activation, Entelios, EnTech Utility Service Bureau, Ltd., and another immaterial acquisition of a foreign entity, respectively. In addition, during the nine month period ended September 30, 2014, we made payments of $2.5 million to acquire investments and a payment of $0.4 million for the acquisition of a customer contract. Also, during the nine month period ended September 30, 2014, our restricted cash and deposits increased by $1.4

35

million due to an increase in deposits principally related to the financial assurance requirements for the demand response programs in which we participate. We made $19.2 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. We have also made capital expenditures for office equipment, furniture and fixtures, and leasehold improvements associated with leasing new office space. Cash used in investing activities for the nine month period ended September 30, 2014 was partially offset by cash provided from investing activities of $4.3 million and $2.2 million related to our sale of a service line and our sale of assets, respectively.
Cash Flows (Used In) Provided By Financing Activities
Cash used in financing activities was $2.3 million for the nine months ended September 30, 2015 and consisted of payments made for employee restricted stock minimum tax withholdings totaling $3.8 million, offset by $1.1 million of cash received from the exercise of stock options and $0.4 million reimbursement of transaction costs relating to our convertible debt offering.
Cash provided by financing activities was $121.1 million for the nine months ended September 30, 2014 and consisted primarily of the net proceeds from the sale and issuance of our Notes in August 2014 totaling $155.3 million, less $30.0 million of the net proceeds which was used to repurchase shares of our common stock. We realized $1.5 million of cash from the exercise of stock options, recognized an excess tax benefit related to exercise of options, restricted stock and restricted stock units of $0.2 million and made payments of approximately $5.9 million for employee restricted stock minimum tax withholdings.  
Borrowings and Credit Arrangements
Credit Agreement
On August 11, 2014, we entered into a $30.0 million senior secured 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 (SVB), which was subsequently amended on October 23, 2014. The 2014 credit facility is subject to continued covenant compliance and borrowing base requirements. As of September 30, 2015, we were in compliance with all of our covenants under the 2014 credit facility. On August 6, 2015, the Company and SVB entered into a second amendment to the 2014 credit facility to extend the termination date from August 11, 2015 to August 9, 2016. 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 9, 2016. As of September 30, 2015, we had no borrowings, but had outstanding letters of credit totaling $22.6 million, under the 2014 credit facility. As of September 30, 2015, we had $7.4 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 thousand principal amount of Notes. However, because we received approval at the annual meeting of our stockholders held on May 27, 2015, we may elect to settle conversions of Notes by paying or delivering, as the case may be, cash, shares of our common stock or a combination of cash and shares of common stock. 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. During the three months ended September 30, 2015, we were reimbursed for transaction costs totaling $0.4 million which was allocated to the liability component. The transaction costs allocated to the liability represent debt issuance costs and are recorded as an asset and are being amortized to interest expense on a straight-line basis over a five year period. As of September 30, 2015, $0.7 million and $2.3 million of

36

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.
Interest expense under the Notes is as follows (in millions):
 
Three Months Ended
September 30,
 
Nine Months Ended
September 30,
 
2015
 
2014
 
2015
 
2014
Accretion of debt discount
$
1.0

 
$
0.5

 
$
3.1

 
$
0.5

Amortization of deferred financing costs
0.2

 
0.1

 
0.5

 
0.1

Non-cash interest expense
$
1.2

 
0.6

 
$
3.6

 
$
0.6

2.25% accrued interest
0.9

 
0.4

 
2.7

 
0.4

Total interest expense from Notes
$
2.1

 
$
1.0

 
$
6.3

 
$
1.0

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, comprised of the contingent interest feature related to timely SEC filing failure, which requires bifurcation as the feature 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 September 30, 2015.

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 $17.7 million and $19.2 million during the nine months ended September 30, 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. 
Off-Balance Sheet Arrangements
As of September 30, 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 September 30, 2015, we had outstanding letters of credit totaling $22.6 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 income (loss) attributable to EnerNOC, Inc., non-GAAP net income (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 income (loss) attributable to EnerNOC, Inc. is GAAP net income (loss) attributable to EnerNOC, Inc.; the GAAP measure most comparable to non-GAAP net income (loss) per share attributable to EnerNOC, Inc. is GAAP net income (loss) per share attributable to EnerNOC, Inc.; the GAAP measure most comparable to adjusted EBITDA is GAAP net income (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 performance. For example, management considers non-GAAP net income (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

37

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 income (loss) attributable to EnerNOC, Inc. as net income (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, direct and incremental expenses related to restructuring activities, and amortization expenses related to acquisition-related intangible assets, net of related tax effects.
•Management defines adjusted EBITDA as net income (loss) attributable to EnerNOC, Inc., excluding depreciation, amortization, stock-based compensation, direct and incremental expenses related to acquisitions or divestitures, direct and incremental expenses related to restructuring activities, interest expense, income taxes and other expense, net.
•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 income (loss) attributable to EnerNOC, Inc., non-GAAP net income (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 Income (Loss) attributable to EnerNOC, Inc. and Non-GAAP Net Income (Loss) per Share attributable to EnerNOC, Inc.
Non-GAAP net income for the three months ended September 30, 2015 was $21.4 million, or $0.75 per basic and $0.74 per diluted share, compared to non-GAAP net income of $100.3 million, or $3.61 per basic and $3.50 per diluted share, for the three months ended September 30, 2014. Non-GAAP net loss for the nine months ended September 30, 2015 was $27.1 million, or $0.96 per basic and diluted share, compared to non-GAAP net income of $56.3 million, or $2.00 per basic and $1.93 per diluted share, for the nine months ended September 30, 2014.

38

The reconciliation of GAAP net income (loss) attributable to EnerNOC, Inc. to non-GAAP net income (loss) attributable to EnerNOC, Inc. is set forth below (dollars in thousands, except share and per share data):
 
Three Months Ended September 30,
 
2015
 
2014
GAAP net income attributable to EnerNOC, Inc.
$
12,987

 
$
96,673

ADD: Stock-based compensation expense
3,656

 
4,135

ADD: Amortization expense of acquired intangible assets
3,662

 
2,391

ADD: Direct and incremental expenses related to acquisitions or divestitures (1)
69

 
197

ADD: Debt discount portion of interest expense related to convertible notes
1,043

 
474

ADD: Income tax effect on Non-GAAP adjustments
—

 
(3,548
)
     Non-GAAP net income attributable to EnerNOC, Inc.
$
21,417

 
$
100,322

 
 
 
 
GAAP net income per basic share attributable to EnerNOC, Inc.
$
0.46

 
$
3.48

ADD: Stock-based compensation expense
0.13

 
0.15

ADD: Amortization expense of acquired intangible assets
0.13

 
0.09

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

 
0.01

ADD: Debt discount portion of convertible debt
0.03

 
0.01

ADD: Income tax effect on Non-GAAP adjustments
—

 
(0.13
)
     Non-GAAP net income per basic share attributable to EnerNOC, Inc.
$
0.75

 
$
3.61

 
 
 
 
GAAP net income per diluted share attributable to EnerNOC, Inc.
$
0.44

 
$
3.11

Impact of including interest expense and excluding incremental shares from convertible notes (2)
0.01

 
0.27

ADD: Stock-based compensation expense
0.13

 
0.13

ADD: Amortization expense of acquired intangible assets
0.13

 
0.08

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

 
0.01

ADD: Debt discount portion of convertible debt
0.03

 
0.02

ADD: Income tax effect on Non-GAAP adjustments
—

 
(0.12
)
     Non-GAAP net income per diluted share attributable to EnerNOC, Inc.
$
0.74

 
$
3.50

 
 
 
 
Weighted average number of common shares outstanding
 

 
 
Basic
28,507,939

 
27,795,154

Diluted
34,623,574

 
31,434,164


39

 
Nine Months Ended September 30,
 
2015
 
2014
GAAP net (loss) income attributable to EnerNOC, Inc.
$
(56,095
)
 
$
38,875

ADD: Stock-based compensation expense
11,386

 
12,161

ADD: Amortization expense of acquired intangible assets
11,607

 
6,753

ADD: Direct and incremental expenses related to acquisitions or divestitures (1)
1,672

 
1,556

ADD: Direct and incremental expenses related to restructuring (3)
1,240

 
—

ADD: Debt discount portion of interest expense related to convertible notes
3,063

 
474

ADD: Income tax effect on Non-GAAP adjustments
—

 
(3,548
)
     Non-GAAP net (loss) income attributable to EnerNOC, Inc.
$
(27,127
)
 
$
56,271

 
 
 
 
GAAP net (loss) income per basic share attributable to EnerNOC, Inc.
$
(1.98
)
 
$
1.38

ADD: Stock-based compensation expense
0.40

 
0.43

ADD: Amortization expense of acquired intangible assets
0.41

 
0.24

ADD: Direct and incremental expenses related to acquisitions or divestitures (1)
0.06

 
0.06

ADD: Direct and incremental expenses related to restructuring (3)
0.04

 
—

ADD: Debt discount portion of interest expense related to convertible notes
0.11

 
0.02

ADD: Income tax effect on Non-GAAP adjustments
—

 
(0.13
)
     Non-GAAP net (loss) income per basic share attributable to EnerNOC, Inc.
$
(0.96
)
 
$
2.00

 
 
 
 
GAAP net (loss) income per diluted share attributable to EnerNOC, Inc.
$
(1.98
)
 
$
1.33

ADD: Stock-based compensation expense
0.40

 
0.42

ADD: Amortization expense of acquired intangible assets
0.41

 
0.23

ADD: Direct and incremental expenses related to acquisitions or divestitures (1)
0.06

 
0.05

ADD: Direct and incremental expenses related to restructuring (3)
0.04

 
—

ADD: Debt discount portion of convertible debt
0.11

 
0.02

ADD: Income tax effect on Non-GAAP adjustments
—

 
(0.12
)
     Non-GAAP net (loss) income per diluted share attributable to EnerNOC, Inc.
$
(0.96
)
 
$
1.93

 
 
 
 
Weighted average number of common shares outstanding
 

 
 
Basic
28,282,647

 
28,075,291

Diluted
28,282,647

 
30,074,187


(1) Represents costs primarily related to acquisitions for third party professional services (legal, accounting, valuation) and severance.

(2) The calculation of non-GAAP net income (loss) per diluted share adjusted for the impact of the numerator and denominator as follows:
(a) The numerator includes interest expense related to convertible notes of $2,118 for the three months ended September 30, 2015 and $980 for the three and nine months ended September 30, 2014.
(b) The denominator excludes incremental shares from the assumed conversion of the convertible notes: 5,774,928 for the three months ended September 30, 2015, and 2,761,922 and 930,758 for the three and nine months ended September 30, 2014.

(3) Represents costs associated with reorganizing the business for our continued enterprise and utility focus.

Adjusted EBITDA
Adjusted EBITDA was $31.7 million and $125.2 million for the three months ended September 30, 2015 and 2014, respectively. Adjusted EBITDA was ($1.5) million and $90.4 million for the nine months ended September 30, 2015 and 2014, respectively.

40

The reconciliation of net loss to adjusted EBITDA is set forth below (dollars in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Net income (loss) attributable to EnerNOC, Inc.
$
12,987

 
$
96,673

 
$
(56,095
)
 
$
38,875

Add back:
 
 
 
 
 
 
 
     Depreciation and amortization
9,511

 
7,960

 
29,259

 
23,167

     Stock-based compensation expense
3,656

 
4,135

 
11,386

 
12,161

     Direct and incremental expenses related to acquisitions or divestitures (1)
69

 
197

 
1,672

 
1,556

     Direct and incremental expenses related to restructuring (2)
—

 
—

 
1,240

 
—

     Other expense, net (3)
2,814

 
2,224

 
5,766

 
1,276

     Interest expense
2,253

 
1,523

 
6,785

 
2,576

     Provision for (benefit from) income tax (4)
417

 
12,441

 
(1,523
)
 
10,830

Adjusted EBITDA
$
31,707

 
$
125,153

 
$
(1,510
)
 
$
90,441

 
(1)
Represents costs primarily related to acquisitions for third party professional services (legal, accounting, valuation) and severance.
(2)
Represents costs associated with reorganizing the business for our continued enterprise and utility focus.
(3)
Other expense primarily relates to foreign currency losses.
(4)
Excludes discrete tax benefit of ($330) and discrete tax provision of $1,120 recorded during the three and nine months ended September 30, 2014 related to the sale of the Utility Solutions Consulting business component.


Free Cash Flow
Cash flows provided by (used in) operating activities were $3.8 million and $(18.2) million for the three and nine months ended September 30, 2015, respectively. Cash flows provided by operating activities were $24.0 million and $29.7 million for the three and nine months ended September 30, 2014, respectively. We had negative free cash flow of $1.0 million for the three months ended September 30, 2015 compared to positive free cash flow of $17.3 million for the three months ended September 30, 2014. We had negative free cash flow of $33.0 million for the nine months ended September 30, 2015 compared to positive free cash flow of $16.9 million for the nine months ended September 30, 2014. The reconciliation of cash flows from operating activities to free cash flow is set forth below (in thousands):
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
2015
 
2014
 
2015
 
2014
Net cash provided by (used in) operating activities
$
3,771

 
$
23,986

 
$
(18,226
)
 
$
29,712

Add:
 
 
 
 
 
 
 
Net cash provided by the sale of assets or disposals of components of an entity
—

 
—

 
2,991

 
6,446

Subtract:
 
 
 
 
 
 
 
Purchases of property and equipment
(4,763
)
 
(6,662
)
 
(17,724
)
 
(19,248
)
Free cash flow
$
(992
)
 
$
17,324

 
$
(32,959
)
 
$
16,910

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.

41

As described in our 2014 10-K, our most critical accounting policies and estimates upon which our consolidated financial statements were prepared were those relating to revenue recognition, assumptions used to determine fair value of goodwill and intangible assets, capitalization of software development costs, deferred tax assets and related valuation allowance, and stock-based compensation. We have reviewed our policies and estimates and determined that these remain our most critical accounting policies and estimates for the nine months ended September 30, 2015. Readers should refer to our 2014 10-K under “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Critical Accounting Policies and Use of Estimates” and Note 16 contained in Part I to this Quarterly Report on Form 10-Q for descriptions of these policies and estimates.

Recent Accounting Pronouncements
For discussion of recent accounting pronouncements, please refer to Note 16 contained in Part I to this Quarterly Report on Form 10-Q.

42

Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Except as disclosed herein, there have been no material changes during the three or nine months ended September 30, 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 September 30, 2015 and 2014, our sales generated outside the United States were 10% and 18%, respectively. During the nine months ended September 30, 2015 and 2014, our sales generated outside the United States were 19%. 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.
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.
During the three months ended September 30, 2015 and 2014, we recognized foreign exchange losses of $2.9 million and $2.5 million, respectively. During the nine months ended September 30, 2015 and 2014, we recognized foreign exchange losses of $6.2 million and $1.8 million, respectively. These changes primarily relate to intercompany receivables denominated in foreign currencies, largely driven by fluctuations to the Canadian dollar, EURO and Australian dollar.
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 September 30, 2015, we had no aggregate principal amount outstanding under the 2014 credit facility, but had outstanding letters of credit totaling $22.6 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.
 

43

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.

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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 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. Among other things, the MOU provided 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. On August 20, 2015, after holding a hearing, the Delaware Court of Chancery approved 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 and our subsequent Quarterly Reports on Form 10-Q. During the three months ended September 30, 2015, there were no material changes to the risk factors that were disclosed in our 2014 Form 10-K or our subsequent Quarterly Reports on Form 10-Q.





45

Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds

Issuer’s Purchases of Equity Securities
The following table provides information about our purchases of our common stock during the third quarter ended September 30, 2015:
Fiscal Period
Total Number
of Shares
Purchased (1)
Average Price
Paid per Share (2)
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs (3)
Approximate Dollar
Value of Shares that
May Yet Be Purchased
Under the Plans
or Programs  (3)
Through June 30, 2015
—

$
—

—

$
20,027,016

July 1, 2015 -July 31, 2015
32,021

10.15

—

20,027,016

August 1, 2015 - August 31, 2015
9,939

9.43

29,972,984

50,000,000

September 1, 2015 - September 30, 2015
26,407

8.94

—

50,000,000

Total for the third quarter of 2015
68,367

$
9.58

—

$
50,000,000

 
(1)
We repurchased a total of 68,367 shares of our common stock in the third quarter of fiscal 2015 to cover employee minimum statutory income tax withholding obligations in connection with the vesting of restricted stock under our equity incentive plans, which we pay in cash to the appropriate taxing authorities on behalf of our employees. Shares withheld (or not issued) to satisfy a tax withholding obligation in connection with an award will immediately be added to the share reserve as and when such shares become returning shares and become available for issuance.
(2)
Average price paid per share is calculated based on the average price per share paid for the repurchase of shares under our publicly announced share repurchase program and the average price per share related to shares repurchases of our common stock to cover employee minimum statutory income tax withholding obligations in connection with the vesting of restricted stock under our equity incentive plans which we pay in cash to the appropriate taxing authorities on behalf of our employees. Amounts disclosed are rounded to the nearest two decimal places.
(3)
On August 11, 2014, our Board of Directors authorized the repurchase of up to $50.0 million of our common stock during the period from August 11, 2014 through August 8, 2015. We refer to this as the 2014 Repurchase Program. There were no repurchases of our common stock in the first or second quarters of fiscal 2015 pursuant to the 2014 Repurchase Program. On August 6, 2015, our Board of Directors approved a new share repurchase program, effective upon the expiration of our 2014 Repurchase Program which happened on August 8, 2015, that enabled us to repurchase up to $50.0 million of our common stock during the period from August 9, 2015 to August 9, 2016 (the 2015 Repurchase Program). Repurchases under our 2015 Repurchase Program are expected to be made periodically on the open market as market and business conditions warrant, or under a Rule 10b5-1 plan.


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Item 6. Exhibits.
31.1*
Certification of Chief Executive Officer of EnerNOC, Inc. pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
 
 
31.2*
Certification of Chief Operating Officer and Chief Financial Officer of EnerNOC, Inc. pursuant to Rule 13a-14(a) or Rule 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
 
 
32.1*
Certification of the Chief Executive Officer and Chief Operating Officer and Chief Financial Officer of EnerNOC, Inc. pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
101*
The following materials from EnerNOC, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, formatted in XBRL (Extensible Business Reporting Language): (i) the Unaudited Condensed Consolidated Balance Sheets, (ii) the Unaudited Condensed Consolidated Statements of Operations, (iii) the Unaudited Condensed Consolidated Statements of Comprehensive Loss, (iv) the Unaudited Condensed Consolidated Statements of Cash Flows, and (v) Notes to Unaudited Condensed Consolidated Financial Statements.
 
*
Filed herewith
@ Management contract, compensatory plan or arrangement


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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
EnerNOC, Inc.
 
 
 
 
Date: November 5, 2015
By:
 
/s/ Timothy G. Healy
 
 
 
Timothy G. Healy
 
 
 
Chief Executive Officer
 
 
 
(principal executive officer)
 
 
 
 
Date: November 5, 2015
By:
 
/s/ Neil Moses
 
 
 
Neil Moses
 
 
 
Chief Operating Officer and Chief Financial Officer (principal financial and accounting officer)


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ENERNOC INC Reports