EnerNOC, Inc.
ENERNOC INC (Form: 10-Q, Received: 08/08/2014 06:02:39)
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

 

FORM 10-Q

 

 

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2014

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   x     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   x     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   x
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   x

There were 30,559,292 shares of the registrant’s common stock, $0.001 par value per share, outstanding as of August 1, 2014.

 

 

 


Table of Contents

EnerNOC, Inc.

Index to Form 10-Q

 

         Page  
Part I - Financial Information   
Item 1.  

Financial Statements

  
 

Unaudited Condensed Consolidated Balance Sheets at June 30, 2014 and December 31, 2013

     3   
 

Unaudited Condensed Consolidated Statements of Operations for the three and six months ended June  30, 2014 and 2013

     4   
 

Unaudited Condensed Consolidated Statements of Comprehensive Loss for the three and six months ended June  30, 2014 and 2013

     5   
 

Unaudited Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013

     6   
 

Notes to Unaudited Condensed Consolidated Financial Statements

     7   
Item 2.  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     39   
Item 3.  

Quantitative and Qualitative Disclosures About Market Risk

     67   
Item 4.  

Controls and Procedures

     68   
Part II - Other Information   
Item 1.  

Legal Proceedings

     68   
Item 1A  

Risk Factors

     69   
Item 6.  

Exhibits

     93   
 

Signatures

     94   

 

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EnerNOC, Inc.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except par value and share data)

 

     June 30, 2014     December 31, 2013  

ASSETS

    

Current assets

    

Cash and cash equivalents

   $ 108,903     $ 149,189  

Restricted cash

     916       1,834  

Trade accounts receivable, net of allowance for doubtful accounts of $559 and $454 at June 30, 2014 and December 31, 2013, respectively

     25,193       35,933  

Unbilled revenue

     1,147       66,675  

Capitalized incremental direct customer contract costs

     43,805       9,509  

Deposits

     295       252  

Prepaid expenses and other current assets

     12,092       6,610  

Assets held for sale

     —         681  
  

 

 

   

 

 

 

Total current assets

     192,351       270,683  

Property and equipment, net of accumulated depreciation of $85,242 and $75,810 at June 30, 2014 and December 31, 2013, respectively

     49,616       47,419  

Goodwill

     102,655       77,104  

Customer relationship intangible assets, net

     22,001       14,247  

Other definite-lived intangible assets, net

     6,576       2,939  

Capitalized incremental direct customer contract costs, long-term

     1,956       1,995  

Deposits and other assets

     3,188       1,568  
  

 

 

   

 

 

 

Total assets

   $ 378,343     $ 415,955  
  

 

 

   

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

    

Current liabilities

    

Accounts payable

   $ 2,301     $ 2,031  

Accrued capacity payments

     38,339       76,676  

Accrued payroll and related expenses

     15,394       13,370  

Accrued expenses and other current liabilities

     28,921       10,145  

Accrued performance adjustments

     420       1,720  

Deferred revenue

     51,141       20,625  

Liabilities held for sale

     —         521  
  

 

 

   

 

 

 

Total current liabilities

     136,516       125,088  

Deferred acquisition consideration

     824       566  

Accrued acquisition contingent consideration

     427       —    

Deferred tax liability

     9,715       6,211  

Deferred revenue

     7,168       6,819  

Other liabilities

     7,621       7,776  

Commitments and contingencies (Note 10)

     —         —    

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, 30,618,012 and 29,920,807 shares issued and outstanding at June 30, 2014 and December 31, 2013, respectively

     31       30  

Additional paid-in capital

     356,482       353,354  

Accumulated other comprehensive loss

     (1,647     (2,535

Accumulated deficit

     (139,152     (81,354
  

 

 

   

 

 

 

Total EnerNOC, Inc. stockholders’ equity

     215,714       269,495  

Noncontrolling interest

     358       —    
  

 

 

   

 

 

 

Total stockholders’ equity

     216,072       269,495  
  

 

 

   

 

 

 

Total liabilities and stockholders’ equity

   $ 378,343     $ 415,955  
  

 

 

   

 

 

 

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

 

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UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

 

     Three Months Ended June 30,     Six Months Ended June 30,  
     2014     2013     2014     2013  

Revenues:

        

Grid operator

   $ 22,974     $ 15,080     $ 58,744     $ 30,143  

Utility

     11,961       13,397       22,270       25,166  

Enterprise

     9,120       7,676       15,549       13,694  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     44,055       36,153       96,563       69,003  

Cost of revenues

     27,802       23,873       63,941       46,070  
  

 

 

   

 

 

   

 

 

   

 

 

 

Gross profit

     16,253       12,280       32,622       22,933  

Operating expenses (income):

        

Selling and marketing

     19,526       19,030       38,025       34,683  

General and administrative

     24,191       21,005       47,868       41,126  

Research and development

     4,997       4,770       10,172       9,590  

Gain on sale of service line (Note 15)

     (3,378     —         (3,378     —    

Gain on the sale of assets (Note 16)

     (2,171     —         (2,171     —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating expenses and income

     43,165       44,805       90,516       85,399  
  

 

 

   

 

 

   

 

 

   

 

 

 

Loss from operations

     (26,912     (32,525     (57,894     (62,466

Other income (expense), net

     374       (1,184     948       (1,117

Interest expense

     (603     (448     (1,053     (761
  

 

 

   

 

 

   

 

 

   

 

 

 

Loss before income tax

     (27,141     (34,157     (57,999     (64,344

(Provision for) benefit from income tax

     (264     (194     161       (544
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

     (27,405     (34,351     (57,838     (64,888

Net loss attributable to noncontrolling interest

     (20     —         (40     —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss attributable to EnerNOC, Inc.

   $ (27,385   $ (34,351   $ (57,798   $ (64,888
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss per common share (basic and diluted)

   $ (0.96   $ (1.23   $ (2.05   $ (2.35
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average number of common shares used in computing basic and diluted net loss per common share

     28,461,111       27,852,298       28,225,518       27,610,797  
  

 

 

   

 

 

   

 

 

   

 

 

 

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

 

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EnerNOC, Inc.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in thousands)

 

     Three Months Ended June 30,     Six Months Ended June 30,  
     2014     2013     2014     2013  

Net loss

   $ (27,405   $ (34,351   $ (57,838   $ (64,888

Foreign currency translation adjustments

     347       (1,018     894       (1,042
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive loss

     (27,058     (35,369     (56,944     (65,930

Comprehensive loss attributable to noncontrolling interest

     (13     —         (34     —    
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive loss attributable to EnerNOC, Inc.

   $ (27,045   $ (35,369   $ (56,910   $ (65,930
  

 

 

   

 

 

   

 

 

   

 

 

 

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

 

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EnerNOC, Inc.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

 

     Six Months Ended June 30,  
     2014     2013  

Cash flows from operating activities

    

Net loss

   $ (57,838   $ (64,888

Adjustments to reconcile net loss to net cash provided by operating activities:

    

Depreciation

     10,845       10,004  

Amortization of acquired intangible assets

     4,362       3,557  

Stock based compensation expense

     8,026       8,011  

Gain on sale of service line

     (3,378     —    

Gain on sale of assets

     (2,171     —    

Impairment of equipment

     352       239  

Impairment of definite lived intangible assets

     323       —    

Unrealized foreign exchange transaction (gain) loss

     (79     1,607  

Deferred taxes

     627       744  

Non-cash interest expense

     245       151  

Accretion of fair value of deferred purchase price and accrued contingent purchase price consideration related to acquisitions

     120       59  

Other, net

     (63     46  

Changes in operating assets and liabilities, net of effects of acquisitions:

    

Accounts receivable, trade

     12,628       9,507  

Unbilled revenue

     65,560       44,433  

Prepaid expenses and other current assets

     (4,040     (4,480

Capitalized incremental direct customer contract costs

     (33,759     (14,750

Other assets

     290       (503

Other noncurrent liabilities

     (488     5,898  

Deferred revenue

     29,936       29,258  

Accrued capacity payments

     (38,656     (18,334

Accrued payroll and related expenses

     579       350  

Accounts payable, accrued performance adjustments and accrued expenses and other current liabilities

     12,305       1,255  
  

 

 

   

 

 

 

Net cash provided by operating activities

     5,726       12,164  

Cash flows from investing activities

    

Purchases of property and equipment

     (12,586     (27,186

Payments made for acquisitions, net of cash acquired

     (35,010     —    

Payments made for cost method investment

     (1,000     —    

Proceeds from sale of service line

     4,275       —    

Proceeds from sale of assets

     2,171       —    

Change in restricted cash and deposits

     689       1,833  

Payments made for acquisition of customer contract

     (403     —    
  

 

 

   

 

 

 

Net cash used in investing activities

     (41,864     (25,353

Cash flows from financing activities

    

Proceeds from exercises of stock options

     603       791  

Payments related to employee restricted stock minimum tax withholdings

     (5,051     —    
  

 

 

   

 

 

 

Net cash (used in) provided by financing activities

     (4,448     791  

Effects of exchange rate changes on cash and cash equivalents

     300       (1,067
  

 

 

   

 

 

 

Net change in cash and cash equivalents

     (40,286     (13,465

Cash and cash equivalents at beginning of period

     149,189       115,041  
  

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 108,903     $ 101,576  
  

 

 

   

 

 

 

Non-cash financing and investing activities

    

Issuance of common stock in satisfaction of bonuses

   $ 145     $ 154  
  

 

 

   

 

 

 

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

 

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EnerNOC, Inc.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(in thousands, except share and per share data)

 

1. Description of Business and Basis of Presentation

Description of Business

EnerNOC, Inc. (the Company) is a leading provider of energy intelligence software, or EIS, and related solutions. The Company unlocks the full value of energy management for commercial, institutional and industrial end-users of energy, which the Company refers to as C&I or enterprise customers, as well as its electric power grid operator and utility customers by delivering a comprehensive suite of demand-side management solutions. The Company’s EIS and related solutions help its customers buy energy better, use less energy and be more strategic about when they consume energy in order to reduce overall energy spend and maximize productivity of that spend.

The Company’s EIS and related solutions provide technology-enabled demand response, demand management, utility bill management, supply management, visibility and reporting, facility optimization, and project management applications and services for its enterprise, electric power grid operator and utility customers. Demand response is an alternative to traditional electric power generation and transmission infrastructure projects that enables electric power grid operators and utilities to reduce the likelihood of service disruptions, such as brownouts and blackouts, during periods of peak electricity demand, and otherwise manage the electric power grid during short-term imbalances of supply and demand or during periods when energy prices are high. The Company’s solutions for utilities and grid operators include EnerNOC Demand Resource™, a turnkey demand response resource with a firm capacity commitment, and EnerNOC Demand Manager™, a Software-as-a-Service (SaaS) application that provides utilities and energy retailers with the underlying technology to manage their demand response programs and secure reliable demand-side resources. When the Company enters into an EnerNOC Demand Resource contract, it matches obligation, in the form of megawatts, or MW, that it agrees to deliver to its utility and electric power grid operator customers, with supply, in the form of MW that the Company is able to curtail from the electric power grid through its arrangements with its enterprise customers. When the Company is called upon by its utility or electric power grid operator customers to deliver its contracted capacity, the Company uses its Network Operations Center, or NOC, to remotely manage and reduce electricity consumption across its growing network of enterprise customer sites, making demand response capacity available to electric power grid operators and utilities on demand while helping enterprise customers achieve energy savings, improve financial results and realize environmental benefits. The Company receives recurring payments from electric power grid operators and utilities for providing its EnerNOC Demand Resource and the Company shares these recurring payments with its enterprise customers in exchange for those enterprise customers reducing their power consumption when called upon by the Company to do so. The Company occasionally reallocates and realigns its capacity supply and obligation through open market bidding programs, supplemental demand response programs, auctions or other similar capacity arrangements and bilateral contracts to account for changes in supply and demand forecasts, as well as changes in programs and market rules in order to achieve more favorable pricing opportunities. The Company refers to the above activities as managing its portfolio of demand response capacity. The Company’s EnerNOC Demand Manager product consists of long-term contracts with a utility customer for a SaaS solution that allows utilities to manage demand response capacity in utility-sponsored demand response programs. The Company’s EnerNOC Demand Manager provides its utility customers with real-time load monitoring, dispatching applications, customizable reports, measurement and verification, and other professional services.

The Company builds on its position as the world’s leading demand response provider by using its EIS to provide its enterprise customers with the ability to:

 

    manage energy supplier selection, procurement and implementation;

 

    manage energy budget forecasting;

 

    manage utility bills and payment; and

 

    measure, track, analyze, report and manage greenhouse gas emissions.

The Company’s EIS and related solutions provide its enterprise customers with the visibility they need to prioritize resources against the activities that will deliver the highest return on investment.

 

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During the third quarter of fiscal 2014, the Company began to offer its EIS and related solutions at three subscription levels: basic, standard, and professional. The Company delivers SaaS solutions on all of major Internet browsers and on leading mobile device operating systems. In addition to its EIS packages, the Company sells a data-driven energy efficiency suite of premium consulting and custom training services, including technology integration services, supply consulting, energy efficiency planning, audits, assessments, commissioning and retro-commissioning services, which are available for an hourly or fixed fee. The Company’s target customers for its EIS and related solutions are enterprises that spend approximately $100/year per site or more on energy, and the Company sells to these customers primarily through its direct sales force.

Since inception, the Company’s business has grown substantially. The Company began by providing its demand response solutions in one state in the United States in 2003 and has expanded to providing its EIS and related solutions in several regions throughout the United States, as well as internationally in Australia, Brazil, China, Germany, India, Ireland, Japan, New Zealand and the United Kingdom.

Reclassifications

The Company has reclassified certain amounts in its unaudited condensed consolidated statements of operations for the three and six month periods ended June 30, 2013, to conform to the 2014 presentation. The reclassifications made relate to the presentation of the Company’s revenues from DemandSMART and EfficiencySMART, SupplySMART and other revenues to revenues from grid operators, revenues from utilities, and revenues from enterprise customers and was done in order to provide the users of its consolidated financial statements with additional insight into how the Company and its management views and evaluates its revenues and related growth. This reclassification within the unaudited condensed consolidated statements of operations for the three and six month periods ended June 30, 2013 had no impact on previously reported total consolidated revenues or consolidated results of operations.

Basis of Consolidation

The unaudited condensed consolidated financial statements of the Company include the accounts of its wholly-owned subsidiaries and have been prepared in conformity with accounting principles generally accepted in the United States (GAAP) and variable interest entities (VIE) in which the Company has variable interests are consolidated as the Company is the primary beneficiary and thus controls the VIE. Intercompany transactions and balances are eliminated upon consolidation.

On February 13, 2014, the Company acquired all of the outstanding capital stock of Entelios AG (Entelios) and all of the outstanding capital stock of Activation Energy DSU Limited (Activation) in separate purchase business combinations.

On April 2, 2014, the Company completed an acquisition of all of the outstanding stock of an international demand response entity.

On April 17, 2014, the Company completed acquisitions of all of the outstanding stock of EnTech Utility Service Bureau, Inc. (Entech US) and EnTech Utility Service Bureau Ltd. (Entech UK) and on May 9, 2014, the Company completed the acquisition of the remaining 50% ownership in EnTech USB Private Limited (Entech India), which was a joint venture between EnTech US and a third party (collectively all referred to as, Entech).

The results of operations of the acquired entities discussed above are included in the Company’s unaudited condensed consolidated statement of operations from the date of acquisition forward.

Subsequent Events Consideration

The Company considers events or transactions that occur after the balance sheet date but prior to the issuance of the financial statements to provide additional evidence relative to certain estimates or to identify matters that require additional disclosure. Subsequent events have been evaluated as required.

There were no material recognizable subsequent events recorded or requiring disclosure in the June 30, 2014 unaudited condensed consolidated financial statements.

Use of Estimates in Preparation of Financial Statements

The accompanying unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). Certain information and footnote disclosures normally included in

 

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financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to SEC rules and regulations. In the opinion of the Company’s management, the unaudited condensed consolidated financial statements and notes thereto have been prepared on the same basis as the audited consolidated financial statements contained in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013, and include all adjustments (consisting of normal, recurring adjustments) necessary for the fair presentation of the Company’s financial position at June 30, 2014 and statements of operations, statements of comprehensive loss and statements of cash flows for the three and six month periods ended June 30, 2014 and 2013. Operating results for the three and six month periods ended June 30, 2014 are not necessarily indicative of the results to be expected for any other interim period or the entire fiscal year ending December 31, 2014 (fiscal 2014).

The preparation of these unaudited condensed consolidated financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, the Company evaluates its estimates, including those related to revenue recognition, allowance for doubtful accounts, valuations and purchase price allocations related to business combinations, fair value of deferred acquisition consideration, fair value of accrued acquisition contingent consideration, expected future cash flows including growth rates, discount rates, terminal values and other assumptions and estimates used to evaluate the recoverability of long-lived assets and goodwill, estimated fair values of intangible assets and goodwill, amortization methods and periods, certain accrued expenses and other related charges, stock-based compensation, contingent liabilities, fair value of asset retirement obligations, tax reserves and recoverability of the Company’s net deferred tax assets and related valuation allowance.

Although the Company regularly assesses these estimates, actual results could differ materially. Changes in estimates are recorded in the period in which they become known. The Company bases its estimates on historical experience and various other assumptions that it believes to be reasonable under the circumstances. Actual results may differ from management’s estimates if these results differ from historical experience or other assumptions prove not to be substantially accurate, even if such assumptions are reasonable when made.

The Company is subject to a number of risks similar to those of other companies of similar and different sizes both inside and outside of its industry, including, but not limited to, rapid technological changes, competition from similar energy management applications, services and products provided by larger companies, customer concentration, government regulations, market or program rule changes, protection of proprietary rights and dependence on key individuals.

Revenue Recognition

The Company recognizes revenues in accordance with Accounting Standards Codification (ASC) 605, Revenue Recognition (ASC 605). In all of the Company’s arrangements, it does not recognize any revenues until it can determine that persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and it deems collection to be reasonably assured. In making these judgments, the Company evaluates the following criteria:

 

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

 

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

 

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

 

    Collection is reasonably assured. The Company conducts a credit review at the inception of an arrangement to determine the creditworthiness of the customer. Collection is reasonably assured if, based upon evaluation, the Company expects that the customer will be able to pay amounts under the arrangement as payments become due. If the Company determines that collection is not reasonably assured, revenues are deferred and recognized upon the receipt of cash.

The Company maintains a reserve for customer adjustments and allowances as a reduction in revenues. In determining the Company’s revenue reserve estimate, and in accordance with company policy, 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

 

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of a particular program, analysis of credit memo data, historical customer adjustments, and other known factors. If the data the Company uses to calculate these estimates does not properly reflect reserve requirements, then a change in the allowances would be made in the period in which such a determination is made and revenues in that period could be affected. As of June 30, 2014 and December 31, 2013, the Company’s revenue reserves were $475 and $475, respectively.

Revenues from grid operators and revenues from utilities principally represent demand response revenues. During the three and six month periods ended June 30, 2014, revenues from grid operators and utilities comprised of $33,328 and $77,428 of demand response revenues, respectively, and $1,607 and $3,586 of enterprise EIS and related solutions revenues, respectively. During the three and six month periods ended June 30, 2013, revenues from grid operators and utilities were comprised of $26,504 and $50,986 of demand response revenues, respectively, and $1,973 and $4,323 of enterprise EIS and solutions revenues, respectively.

All revenues from enterprise customers for the three and six month periods ended June 30, 2014 and 2013 were derived from enterprise EIS and related solutions.

Demand Response Revenues

The Company enters into contracts and open market bidding programs with utilities and electric power grid operators to provide demand response applications and services. Currently the Company has two principal service offerings under which it provides demand response applications and services: (1) full-service turnkey offering to utilities under which it manages all aspects of demand response program delivery to deliver a firm capacity resource (Demand Resource) and (2) utility partnership offering under which utilities can utilize software through a software as a service offering, integrated metering hardware, and professional services to support their tariff-based C&I demand response programs on a service-level agreement basis (Demand Manager).

The Company has evaluated the factors within ASC 605 regarding gross versus net revenue reporting for its demand response revenues and its payments to C&I customers. Based on the evaluation of the factors within ASC 605, the Company has determined that all of the applicable indicators of gross revenue reporting were met. The applicable indicators of gross revenue reporting included, but were not limited to, the following:

 

    The Company is the primary obligor in its arrangements with electric power grid operators and utility customers because the Company provides its demand response services directly to electric power grid operators and utilities under long-term contracts or pursuant to open market programs and contracts separately with C&I customers to deliver such services. The Company manages all interactions with the electric power grid operators and utilities, while C&I customers do not interact with the electric power grid operators and utilities. In addition, the Company assumes the entire performance risk under its arrangements with electric power grid operators and utility customers, including the posting of financial assurance to assure timely delivery of committed capacity with no corresponding financial assurance received from its C&I customers. In the event of a shortfall in delivered committed capacity, the Company is responsible for all penalties assessed by the electric power grid operators and utilities without regard for any recourse the Company may have with its C&I customers.

 

    The Company has latitude in establishing pricing, as the pricing under its arrangements with electric power grid operators and utilities is negotiated through a contract proposal and contracting process or determined through a capacity auction. The Company then separately negotiates payment to C&I customers and has complete discretion in the contracting process with the C&I customers.

 

    The Company has complete discretion in determining which suppliers (C&I customers) will provide the demand response services, provided that the C&I customer is located in the same region as the applicable electric power grid operator or utility.

 

    The Company is involved in both the determination of service specifications and performs part of the services, including the installation of metering and other equipment for the monitoring, data gathering and measurement of performance, as well as, in certain circumstances, the remote control of C&I customer loads.

As a result, the Company has concluded that it earns revenue (as a principal) from the delivery of demand response services to electric power grid operators and utility customers and records the amounts billed to the electric power grid operators and utility customers as gross demand response revenues and the amounts paid to C&I customers as cost of revenues.

 

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EnerNOC Demand Resource Solution

The majority of the Company’s demand response revenues are generated from the EnerNOC Demand Resource solution. Demand response revenues consist of two elements: revenue earned from the Company’s ability to deliver committed capacity to its electric power grid operator and utility customers, which the Company refers to as capacity revenue; and revenue earned from additional payments made to the Company for the amount of energy usage actually curtailed from the grid during a demand response event, which the Company refers to as energy event revenue.

The Company recognizes demand response revenue when it has provided verification to the electric power grid operator or utility of its ability to deliver the committed capacity which entitles the Company to payments under the contract or open market program. Committed capacity is generally verified through the results of an actual demand response event or a measurement and verification test. Once the capacity amount has been verified, the revenue is recognized and future revenue becomes fixed or determinable and is recognized monthly until the next demand response event or test. In subsequent verification events, if the Company’s verified capacity is below the previously verified amount, the electric power grid operator or utility customer will reduce future payments based on the adjusted verified capacity amounts. Ongoing demand response revenue recognized between demand response events or tests that are not subject to penalty or customer refund are recognized in revenue. If the revenue is subject to refund and the amount of refund cannot be reliably estimated, the revenue is deferred until the right of refund lapses.

All demand response capacity revenues related to the Company’s participation in the PJM summer-only open market program are being recognized at the end of the four-month delivery period of June through September, or during the three month period ended September 30 th of each year. Because the period during which the Company is required to perform (June through September) is shorter than the period over which payments are received under the program (June through May), a portion of the revenues that have been earned are recorded and accrued as unbilled revenue. Substantially all revenues related to the PJM open market program for the program year ended September 30, 2013 were recognized during the three month period ended September 30, 2013 and as a result of the billing period not coinciding with the revenue recognition period, the Company had $64,643 in unbilled revenues from PJM at December 31, 2013. Due to the fact the demand response capacity revenues related to the PJM summer-only open market program are not recognized until the three month period ended September 30 th of each year, there were no unbilled revenues related to this program as of June 30, 2014.

With respect to the PJM open market program, the Company commenced participation in a new service offering within this program commencing on June 1, 2014. Under this new service delivery offering, which the Company refers to as the PJM Extended demand response program, the delivery period is from June through October and then May in the subsequent calendar year. The revenues and any associated penalties, if any, for underperformance related to participation in the PJM Extended demand response program are separate and distinct from the Company’s participation in other offerings within the PJM open market program. Under the PJM Extended demand response program, penalties incurred as a result of underperformance for a demand response event dispatched during the months of June through September and for a demand response test event are the same as the historical service offering that the Company has participated in, which the Company refers to as the PJM summer only demand response program. However, penalties incurred as a result of underperformance for an event dispatched during the month of October or the month of May are 1/52 multiplied by the number of the shortfall amount (committed capacity less actual delivered capacity) times the applicable capacity rate. Consistent with the PJM summer only demand response program, the Company notes that the fees could potentially be subject to adjustment or refund based on performance during applicable performance period. Therefore, the Company is currently evaluating whether it has the ability to reliably estimate the amount of fees potentially subject to adjustment or refund as of the end of September or whether revenues related to its participation in this program will be recognized at the end of the performance period, or during the three month period ended June 30 th of the following calendar year. For the PJM Extended demand response program period that commenced on June 1, 2014 and ends on May 31, 2015, the potential fees that could be earned are not material.

Demand response capacity revenues related to the Company’s participation in an open market program in Western Australia are potentially subject to refund and therefore, are deferred until a portion of such capacity revenues are fixed which occurs upon an emergency event dispatch or until the end of the program period on September 30 th . Historically all capacity revenues have been recognized during the three month period ended September 30 th as there have previously been no emergency event dispatches. During the three month period ended June 30, 2014, there was an emergency event dispatch in this open market program and as a result, a portion of the capacity revenues were fixed and no longer subject to adjustment resulting in the recognition of $4,344 of capacity revenues and $1,982 of related cost of revenues during the three month period ended June 30, 2014.

Energy event revenues are recognized when earned. Energy event revenue is deemed to be substantive and represents the culmination of a separate earnings process and is recognized when the energy event is initiated by the electric power grid operator or utility customer and the Company has responded under the terms of the contract or open market program. During the three and six month periods ended June 30, 2014, the Company recognized $4,199 and $24,769, respectively, of energy event revenues, and during the three and six month periods ended June 30, 2013, the Company recognized $2,224 and $4,159, respectively, of energy event revenues.

 

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In 2012, the Company decided to net settle a portion of its future contractual delivery obligations in a certain open market bidding program. As of June 30, 2014, the Company entered into transactions to net settle a significant portion of its future delivery obligations and these transactions have been approved by the customer. As a result, as long as the other criteria for revenue recognition are met, the Company will recognize these fees from the net settlement transactions as revenues as they become due and payable with such fees being recorded as a component of grid operator revenues. During the three and six month periods ended June 30, 2014, the Company recognized revenues of $4,031 and $7,802, respectively, related to these net settlement transactions.

The Company has evaluated the forward capacity programs in which it participates and has determined that its contractual obligations in these programs do not currently meet the definition of derivative contracts under ASC 815, Derivatives and Hedging (ASC 815).

EnerNOC Demand Manager Solution

Under the Company’s EnerNOC Demand Manager solution, the Company generally receives an ongoing fee for overall management of the utility demand response program based on enrolled capacity or enrolled C&I customers, which is not subject to adjustment based on performance during a demand response dispatch. The Company recognizes revenues from these fees ratably over the applicable service delivery period commencing upon when the C&I customers have been enrolled and the contracted services have been delivered. In addition, under this offering, the Company may receive additional fees for program start-up, as well as, for C&I customer installations. The Company has determined that these fees do not have stand-alone value as such services do not have value without the ongoing services related to the overall management of the utility demand response program. Therefore, the Company recognizes these fees over the estimated customer relationship period, which is generally the greater of 3 years or the contract period, commencing upon the enrollment of the C&I customers and delivery of the contracted services. Through June 30, 2014, revenues from EnerNOC Demand Manager have not been material to the Company’s consolidated results of operations.

Enterprise EIS and Related Solutions

The Company’s enterprise EIS and related solutions revenues generally represent ongoing service arrangements where the revenues are recognized ratably over the service period commencing upon delivery of the contracted service with the customer. Under certain of the Company’s arrangements, a portion of the fees received may be subject to adjustment or refund based on the validation of the energy savings delivered after the implementation is complete. As a result, the Company defers the portion of the fees that are subject to adjustment or refund until such time as the right of adjustment or refund lapses, which is generally upon completion and validation of the implementation. In addition, under certain other of the Company’s arrangements, the Company sells proprietary equipment to C&I customers that is utilized to provide the ongoing services that the Company delivers. Currently, this equipment has been determined to not have stand-alone value. As a result, the Company defers revenues associated with the equipment and the Company begins recognizing such revenue ratably over the expected C&I customer relationship period (generally three years), once the C&I customer is receiving the ongoing services from the Company. In addition, the Company capitalizes the associated direct and incremental costs, which primarily represent the equipment and third-party installation costs, and recognizes such costs over the expected C&I customer relationship period.

The Company follows the provisions of ASC Update No. 2009-13, Multiple-Deliverable Revenue Arrangements (ASU 2009-13). The Company typically determines the selling price of its services based on vendor specific objective evidence (VSOE). Consistent with its methodology under previous accounting guidance, the Company determines VSOE based on its normal pricing and discounting practices for the specific service when sold on a stand-alone basis. In determining VSOE, the Company’s policy is to require a substantial majority of selling prices for a product or service to be within a reasonably narrow range. The Company also considers the class of customer, method of distribution, and the geographies into which its products and services are sold when determining VSOE. The Company typically has had VSOE for its products and services.

In certain circumstances, the Company is not able to establish VSOE for all deliverables in a multiple element arrangement. This may be due to the infrequent occurrence of stand-alone sales for an element, a limited sales history for new services or pricing within a broader range than permissible by the Company’s policy to establish VSOE. In those circumstances, the Company proceeds to the alternative levels in the hierarchy of determining selling price. Third Party Evidence (TPE) of selling price is established by evaluating largely similar and interchangeable competitor products or services in stand-alone sales to similarly situated customers. The Company is typically not able to determine TPE and has not used this measure since the Company has been unable to reliably verify standalone prices of competitive solutions. Management’s best estimate of selling price (ESP) is established in those instances where neither VSOE nor TPE are available, by considering internal factors such as margin objectives, pricing practices and controls, customer segment pricing strategies and the product life cycle. Consideration is also given to market conditions such as competitor pricing information gathered from experience in customer negotiations, market research and information, recent technological trends, competitive landscape and geographies. Use of ESP is limited to a very small portion of the Company’s services, principally certain other EIS software and related solutions.

 

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Foreign Currency Translation

Foreign currency translation adjustments are recorded as a component of other comprehensive loss and included in accumulated other comprehensive loss within stockholders’ equity. Gains (losses) arising from transactions denominated in foreign currencies and the re-measurement of certain intercompany receivables and payables are included in other income (expense), net in the unaudited condensed consolidated statements of operations and were $247 and ($1,339) for the three month periods ended June 30, 2014 and 2013, respectively, and $634 and ($1,323) for the six month periods ended June 30, 2014 and 2013, respectively. Foreign currency exchange gains (losses) resulted primarily from foreign denominated intercompany receivables held by the Company from one of its Australian subsidiaries which mainly resulted from funding provided to complete the acquisition of Energy Response Holdings Pty Ltd (Energy Response) and fluctuations in the Australian dollar exchange rate, in addition to U.S. dollar denominated intercompany payables to the Company from one of its German subsidiaries and one of its UK subsidiaries which mainly resulted from funding provided to complete the acquisitions of Entelios and EnTech, respectively. During the three and six month periods ended June 30, 2014, $6,239 ($6,629 Australian) and $6,302 ($6,699 Australian), respectively, of the intercompany receivable from the Company’s Australian subsidiary was settled resulting in a realized loss of $657 and $659, respectively. During the three and six month periods ended June 30, 2013, $1,543 ($1,500 Australian) and $11,809 ($11,421 Australian), respectively, of the intercompany receivable from the Company’s Australian subsidiary was settled resulting in a realized loss of $68 and $348, respectively. During the three and six month periods ended June 30, 2014 and 2013, there were no other material realized gains (losses) incurred related to transactions denominated in foreign currencies.

As of June 30, 2014, the Company had an intercompany receivable from its Australian subsidiary that is denominated in Australian dollars and not deemed to be of a “long-term investment” nature totaling $3,696 at June 30, 2014 exchange rates ($3,926 Australian). Two of the Company’s German subsidiaries had an intercompany payable to the Company that is denominated in U.S. dollars and not deemed to be of a “long-term investment” nature totaling $19,293 at June 30, 2014; and two of its UK subsidiaries had an intercompany payable to the Company that is denominated in U.S. dollars and not deemed to be of a “long-term investment” nature totaling $3,156 at June 30, 2014.

In addition, a portion of the funding provided by the Company to one of its Australian subsidiaries to complete the acquisition of Energy Response was deemed to be of a “long-term investment nature” and therefore, the resulting translation adjustments are being recorded as a component of stockholders’ equity within accumulated other comprehensive loss. As of June 30, 2014, the intercompany funding that is denominated in Australian dollars and deemed to be of a “long-term investment” nature totaled $19,171 at June 30, 2014 exchange rates ($20,364 Australian) and during the three and six month periods ended June 30, 2014, the Company recorded translation adjustments of $342 and $996, respectively, related to this intercompany funding within accumulated other comprehensive loss.

Comprehensive (Loss) Income

Comprehensive (loss) income is defined as the change in equity of a business enterprise during a period resulting from transactions and other events and circumstances from non-owner sources. As of June 30, 2014 and December 31, 2013, accumulated other comprehensive loss was comprised solely of cumulative foreign currency translation adjustments. The Company presents its components of other comprehensive loss net of related tax effects, which have not been material to date.

Software Development Costs

Software development costs, including license fees and external consulting costs, of $1,743 and $1,681 for the three month periods ended June 30, 2014 and 2013, respectively, and $3,141 and $4,312 for the six month periods ended June 30, 2014 and 2013, respectively, have been capitalized in accordance with Accounting Standard Codification (ASC) 350-40, Internal-Use Software (ASC 350-40). The capitalized amount was included as software in property and equipment at June 30, 2014 and December 31, 2013. Amortization of capitalized internal use software costs was $1,496 and $1,444 for the three month periods ended June 30, 2014 and 2013, respectively, and $3,026 and $2,752 for the six month periods ended June 30, 2014 and 2013, respectively. Accumulated amortization of capitalized internal use software costs was $24,467 and $21,441 as of June 30, 2014 and December 31, 2013, respectively.

 

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Impairment of Property and Equipment

During the three and six month periods ended June 30, 2014, as a result of the removal of certain demand response equipment from service, the Company concluded that there were no expected future direct cash flows associated with this demand response equipment and therefore, an impairment indicator existed. The Company determined that the residual value of this demand response equipment was nominal and as a result, recorded an impairment charge during the three and six month periods ended June 30, 2014 of $257 and $352, respectively, to reduce the carrying value of such equipment to zero.

Industry Segment Information

The Company operates in the following major geographic areas as noted in the below chart. The “All other” designation includes Brazil, China, Germany, India, Japan, Ireland, New Zealand and the United Kingdom. Revenues are based upon customer location and internationally totaled $13,551 and $5,957 for the three month periods ended June 30, 2014 and 2013, respectively, and totaled $22,731 and $14,044 for the six month periods ended June 30, 2014 and 2013, respectively.

Revenues by geography as a percentage of total revenues are as follows:

 

     Three Months Ended June 30,     Six Months Ended June 30,  
     2014     2013     2014     2013  

United States

     69     84     76     80

Canada

     13       13       12       14  

Australia

     11       1       6       3  

All other

     7       2       6       3  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

     100     100     100     100
  

 

 

   

 

 

   

 

 

   

 

 

 

As of June 30, 2014 and December 31, 2013, the long-lived assets related to the Company’s international subsidiaries were not material to the accompanying unaudited condensed consolidated financial statements taken as a whole.

 

2. Acquisitions

Entech

On April 17, 2014, the Company and two of its subsidiaries completed acquisitions of all of the outstanding stock of Entech US and Entech UK, privately-held companies headquartered in the United States and the United Kingdom, respectively, that are leading providers of global utility bill management (UBM) software, which is currently deployed in over 100 countries, including many of the world’s fastest growing economies, such as China, India, and Brazil. In connection with the acquisition of Entech US, the Company acquired Entech US’s 50% ownership in a joint venture entity in India (Entech India), which performed development and data processing services principally for Entech US. On May 9, 2014, the Company completed the acquisition of the remaining 50% ownership Entech India. The Company collectively refers to the entities acquired as Entech. The Company believes that the combination of Entech’s software and technology, including real-time energy data, tariffs, and monthly utility bill data on the Company’s EIS platform will now enable real-time visibility and forecasting of energy costs and empower better energy management across global enterprises.

The Company concluded that these acquisitions represented business combinations under ASC 805, Business Combinations (ASC 805) but has concluded that they did not represent material business combinations and therefore, no pro forma financial information will be required. Subsequent to the acquisition dates, the Company’s results of operations include the results of operations of Entech.

Entech US and Entech UK were not entities under common control, however, the overall acquisitions were negotiated in contemplation of acquiring of all entities, including Entech India, and closing was contingent upon acquiring all entities. The Company did separately negotiate the allocation of the overall purchase price with the stockholders of each entity. The Company acquired Entech US for an aggregate purchase price of $6,796 all of which paid in cash at closing with $60 paid to the stockholders’ consultants to settle transactional fees due to these consultants. There is no earn-out or other additional contingent purchase price arrangements related to the acquisition of Entech US. The Company acquired Entech UK for an aggregate purchase price of $3,154 all

 

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of which was paid in cash at closing with $18 paid to the stockholders’ consultants to settle the stockholders’ fees due to these consultants. There is no earn-out or other additional contingent purchase price arrangements related to the acquisition of Entech UK. However, with respect to both of the acquisitions of Entech US and Entech UK, in accordance with the stock purchase agreement, there is a post closing adjustment to the purchase price that will be finalized within 120 days of the closing date to adjust the purchase price for net working capital or deficit as of the closing date. The Company has initially determined that both Entech US and Entech UK had working capital (defined as total assets less total liabilities in the stock purchase agreement) based on the preliminary consolidated balance sheets as of the closing date as of the acquisition close and therefore, has reflected additional purchase price for Entech US and Entech UK of $1,007 and $458, respectively, which is recorded in accrued expenses and other liabilities as of June 30, 2014 and is expected to be paid during the three month period ending September 30, 2014.

The Company acquired the remaining 50% ownership interest in Entech India for an aggregate purchase price of $1,201, all of which was paid in cash at closing. There were no contingent consideration arrangements or working capital adjustments.

The total initial purchase price related to the Company’s acquisition of Entech was $12,616.

Transaction costs related to this business combination have been expensed as incurred and are included in general and administrative expenses in the Company’s unaudited condensed consolidated statements of operations. Transaction costs incurred related to this transaction were approximately $311.

The Company is in the process of gathering information to complete its preliminary valuation of certain assets and liabilities in order to complete a preliminary purchase price allocation. The Company notes that the individual business combinations of Entech US, Entech UK and Entech India did not result in negative goodwill. Because these were business combinations of related businesses that were based on acquiring all related entities, the Company is presenting the purchase price allocation on an overall combined basis.

The components and preliminary allocation of the purchase price consist of the following approximate amounts:

 

Net tangible assets acquired

   $ 1,277  

Customer relationships

     3,900  

Non-compete agreements

     1,000  

Developed technology

     700  

Trade name

     260  

Deferred income tax liability

     (1,689

Goodwill

     7,168  
  

 

 

 

Total

   $ 12,616  
  

 

 

 

Included in net tangible assets acquired was Entech UK’s equity interest in a China joint venture accounted under the equity method of accounting in accordance of ASC 323, Investments—Equity Method and Joint Ventures . The fair value of this asset was not material given the nominal amount of net assets in this joint venture and its ongoing activities. The Company’s portion of income from this joint venture from the date of acquisition through June 30, 2014 was not material and is included in other income (expense), net in the accompanying condensed consolidated statements of operations. As of June 30, 2014, Entech UK had a payable to this China joint venture totaling $44 which is included in accrued expenses and other current liabilities. The deferred income tax liability recorded in connection with the preliminary allocation of purchase price relates to the book and tax basis difference related to the acquired definite-lived intangible assets for which the book amortization expense for such assets will not be deductible for tax purposes.

 

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Net tangible assets acquired in the acquisition of EnTech primarily related to the following:

 

Cash

   $ 530  

Accounts receivable

     1,606  

Property and equipment

     275  

Other assets

     242  

Accounts payable

     (138

Accrued payroll and related expenses

     (311

Accrued expenses and other liabilities

     (526

Deferred revenues

     (63

Deferred tax liability

     (10

Other long-term liabilities

     (328
  

 

 

 

Total

   $ 1,277  
  

 

 

 

Identifiable Intangible Assets

As part of the preliminary purchase price allocation, the Company determined that Entech’s separately identifiable intangible assets were its customer relationships, non-compete agreements, developed technology, and trade name. Developed technology represented internally developed software that supports utility bill management services. As of the date of acquisition, the Company determined that there was no in-process research and development as the ongoing research and development efforts were nominal and related to routine, on-going maintenance efforts.

The Company used the income approach to value the acquired customer relationships, developed technology, non-compete agreements, and trade name definite-lived intangible assets. This approach calculates fair value by discounting the after-tax cash flows back to a present value. The baseline data for this analysis was the cash flow estimates used to price the transaction. Cash flows were forecasted for each intangible asset then discounted based on an appropriate discount rate. The discount rate applied of 16% was benchmarked with reference to the implied rate of return from the transaction model, as well as an estimate of a market-participant’s weighted average cost of capital based on the capital asset pricing model. In addition, the Company applied the market approach concepts in determining the appropriate royalty rate for developed technology and trade name definite-lived intangible assets where such royalty rates were determined based on an independent study of comparable market rates resulting in a royalty rates utilized for the developed technology and trade name definite-lived intangible assets of 2.5% and 1.5%, respectively.

In estimating the useful life of the acquired assets, the Company considered ASC 350-30-35, General Intangibles Other Than Goodwill (ASC 350-30-35), which lists the pertinent factors to be considered when estimating the useful life of an intangible asset. These factors include a review of the expected use by the combined Company of the assets acquired, the expected useful life of another asset (or group of assets) related to the acquired assets, legal, regulatory or other contractual provisions that may limit the useful life of an acquired asset or may enable the extension of the useful life of an acquired asset without substantial cost, the effects of obsolescence, demand, competition and other economic factors, and the level of maintenance expenditures required to obtain the expected future cash flows from the asset. The Company amortizes its intangible assets over their estimated useful lives using a method that is based on estimated future cash flows, as the Company believes this will approximate the pattern in which the economic benefits of the assets will be utilized, or where the Company has concluded that the cash flows were not reliably determinable, on a straight-line basis.

The factors contributing to the recognition of goodwill were based upon the Company’s determination that several strategic and synergistic benefits are expected to be realized from the combination. None of the goodwill is expected to be currently deductible for tax purposes.

Entelios AG

On February13, 2014, the Company and one of its subsidiaries completed an acquisition of all of the outstanding stock of Entelios, a privately-held company headquartered in Germany that is a leading provider of demand response in Europe. This acquisition accelerates the Company’s entry into continental Europe with Entelios’ strong team and existing relationships with leading grid operators, utilities, retailers, and commercial, institutional, and industrial customers.

 

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The Company concluded that this acquisition represented a business combination under ASC 805 and has also concluded that it did not represent a material business combination. 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 Entelios.

The Company acquired Entelios for an aggregate purchase price, exclusive of potential contingent consideration, of $21,784 (16,000 Euros translated based on the exchange rate on the closing date of the acquisition), all of which was paid in cash. Of the consideration paid at closing, $6,884 (5,056 Euros) was paid as consideration to allow Entelios to settle its outstanding debt and related tax obligations. In addition to the amounts paid at closing, the Company may be obligated to pay additional contingent purchase price consideration related to an earn-out amount up to a maximum of $2,042 (1,500 Euros). The earn-out payment, if any, will be based on the achievement of certain minimum defined profit metrics for the years ending December 31, 2014 and 2015, respectively. Of the $2,042 (1,500 Euros) maximum earn-out payment, up to $817 (600 Euros) and $1,225 (900 Euros) relate to the achievement of the defined profit metrics for the years ending December 31, 2014 and 2015, respectively. If the minimum defined profit metrics are not achieved, there will be no partial payment, however, the amount of the earn-out payment can vary based on the amount that profits exceed the minimum defined profit metrics. The Company determined that the initial fair value of the earn-out payment as of the acquisition date was $95. This fair value was included as a component of the purchase price resulting in an aggregate purchase price of $21,879. Any changes in fair value will be recorded in the Company’s consolidated statements of operations. The Company recorded its estimate of the fair value of the contingent consideration based on the evaluation of the likelihood of the achievement of the contractual conditions that would result in the payment of the contingent consideration and weighted probability assumptions of these outcomes. This fair value measurement was determined utilizing a Monte Carlo simulation and was based on significant inputs not observable in the market and therefore, represented a Level 3 measurement as defined in ASC 820, Fair Value Measurements and Disclosures (ASC 820). Through June 30, 2014, there were no changes in the probability of the earn-out payment. This liability has been discounted to reflect the time value of money and therefore, as the milestone date approaches, the fair value of this liability will increase. This increase in fair value will be recorded to cost of revenues in the Company’s consolidated statements of operations. During the three and six month periods ended June 30, 2014, the change in fair value due to the accretion of the time value of money discount was not material. At June 30, 2014, the liability was recorded at $101 after adjusting for changes in exchange rates.

Transaction costs related to this business combination have been expensed as incurred and are included in general and administrative expenses in the Company’s unaudited condensed consolidated statements of operations. Transaction costs incurred related to this transaction were approximately $511.

The components and preliminary allocation of the purchase price consist of the following approximate amounts:

 

Net tangible liabilities assumed as of February 13, 2014

   $ (50

Customer relationships

     4,084  

Non-compete agreements

     204  

Developed technology

     1,770  

Trade name

     218  

Deferred income tax asset

     2,070  

Deferred income tax liability

     (2,070

Goodwill

     15,653  
  

 

 

 

Total

   $ 21,879  
  

 

 

 

The deferred income tax liability recorded in connection with the preliminary allocation of purchase price relates to the book and tax basis difference related to the acquired definite-lived intangible assets for which the book amortization expense for such assets will not be deductible for tax purposes. Due to the fact that this deferred income tax liability represents a potential source of income as defined in ASC 740, Income Taxes (ASC 740), the Company determined that it was more likely than not that a portion of the deferred tax assets acquired in the business combination, which relate to tax net operating loss carry forwards, were realizable. As a result, the Company recorded a corresponding deferred income tax asset that would be utilized to offset this potential source of taxable income. As the deferred income tax liability and deferred income tax asset are both long-term and relate to the same jurisdiction, these amounts are netted in the Company’s unaudited condensed consolidated balance sheet.

 

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Net tangible liabilities assumed in the acquisition of Entelios primarily related to the following:

 

Cash

   $ 1,564  

Accounts receivable

     19  

Capitalized incremental direct customer contract costs

     36  

Prepaid expenses and other current assets

     148  

Property and equipment

     377  

Other assets

     72  

Accounts payable

     (178

Accrued payroll and related expenses

     (970

Accrued expenses and other liabilities

     (1,098

Deferred revenues

     (20
  

 

 

 

Total

   $ (50
  

 

 

 

Identifiable Intangible Assets

As part of the preliminary purchase price allocation, the Company determined that Entelios’s separately identifiable intangible assets were its customer relationships, non-compete agreements, developed technology, and trade name. Developed technology represented internally developed software that supports the management of demand response dispatches, including fast-response dispatches, as well as, assists with the performance calculations and related settlements. As of the date of acquisition, the Company determined that there was no in-process research and development as the ongoing research and development efforts were nominal and related to routine, on-going maintenance efforts.

The Company used the income approach to value the acquired customer relationships, non-compete agreements, and trade name definite-lived intangible assets. This approach calculates fair value by discounting the after-tax cash flows back to a present value. The baseline data for this analysis was the cash flow estimates used to price the transaction. Cash flows were forecasted for each intangible asset then discounted based on an appropriate discount rate. The discount rates applied, which ranged between 12% and 17%, were benchmarked with reference to the implied rate of return from the transaction model, as well as an estimate of a market-participant’s weighted average cost of capital based on the capital asset pricing model.

The Company used the cost approach to value the acquired developed technology definite-lived intangible asset, as the Company determined that a market participant would be expected to have similar offerings and capabilities to build a replacement version of the software. Furthermore, it is expected that the software will be migrated over time or potentially replaced by the Company’s existing software platform and this expectation is consistent with that of a market participant. The cost approach determines fair value by calculating the reproduction cost of an exact replica of the subject intangible asset. The Company calculated the replacement cost based on the estimated hours and costs incurred to develop.

In estimating the useful life of the acquired assets, the Company considered ASC 350-30-35, which lists the pertinent factors to be considered when estimating the useful life of an intangible asset. These factors include a review of the expected use by the combined Company of the assets acquired, the expected useful life of another asset (or group of assets) related to the acquired assets, legal, regulatory or other contractual provisions that may limit the useful life of an acquired asset or may enable the extension of the useful life of an acquired asset without substantial cost, the effects of obsolescence, demand, competition and other economic factors, and the level of maintenance expenditures required to obtain the expected future cash flows from the asset. The Company amortizes its intangible assets over their estimated useful lives using a method that is based on estimated future cash flows, as the Company believes this will approximate the pattern in which the economic benefits of the assets will be utilized, or where the Company has concluded that the cash flows were not reliably determinable, on a straight-line basis.

The factors contributing to the recognition of goodwill were based upon the Company’s determination that several strategic and synergistic benefits are expected to be realized from the combination. None of the goodwill is expected to be currently deductible for tax purposes.

 

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Activation Energy DSU Limited

On February 13, 2014, the Company and one of its subsidiaries completed an acquisition of all of the outstanding stock of Activation, a privately-held company headquartered in Ireland that is the leading provider of demand response software and services in Ireland. This acquisition gives the Company an immediate presence in the Irish capacity market and further strengthens the Company’s ability to deliver its full suite of EIS and related solutions throughout Europe.

The Company concluded that this acquisition represented a business combination under ASC 805 and has also concluded that it did not represent a material business combination and therefore, no pro forma financial information will be required to be presented. Subsequent to the acquisition date, the Company’s results of operations include the results of operations of Activation.

The Company acquired Activation for an aggregate purchase price of $3,844 (2,823 Euros translated based on the exchange rate on the date of the acquisition close), plus an additional $732 (538 Euros) paid as working capital and other adjustments, all of which was paid in cash. In addition to the amounts paid at closing, the Company may be obligated to pay additional contingent purchase price consideration related to an earn-out amount up to a maximum of $1,398 (1,027 Euros). The earn-out payment, if any, will be based on the achievement of certain minimum defined MW enrollment, as well as, profit metrics for the years ending December 31, 2014 and 2015, respectively. Of the maximum earn-out payment, up to $350 (257 Euros) and $1,048 (770 Euros) relate to the achievement of the defined profit metrics for the years ending December 31, 2014 and 2015, respectively. If the minimum defined profit metrics are not achieved, there will be no partial payment, however, the amount of the earn-out payment can vary based on the amount that profits exceed the minimum defined profit metrics. The Company determined that the initial fair value of the earn-out payment as of the acquisition date was $300. This fair value was included as a component of the purchase price resulting in an aggregate purchase price of $4,876. Any changes in fair value will be recorded in the Company’s consolidated statements of operations. The Company recorded its estimate of the fair value of the contingent consideration based on the evaluation of the likelihood of the achievement of the contractual conditions that would result in the payment of the contingent consideration and weighted probability assumptions of these outcomes. This fair value measurement was determined utilizing a Monte Carlo simulation and was based on significant inputs not observable in the market and therefore, represented a Level 3 measurement as defined in ASC 820. Through June 30, 2014, there were no changes in the probability of the earn-out payment. This liability has been discounted to reflect the time value of money and therefore, as the milestone date approaches, the fair value of this liability will increase. This increase in fair value will be recorded to cost of revenues in the Company’s consolidated statements of operations. During the three and six month periods ended June 30, 2014, the change in fair value due to the accretion of the time value of money discount was not material. At June 30, 2014, the liability was recorded at $327 after adjusting for changes in exchange rates.

As a result of gathering information to update the Company’s valuation allocation during the three month period ended June 30, 2014, the Company determined that the estimated purchase price paid at the closing exceeded the final purchase price. The Company and the former stockholders of Activation reached an agreement to reduce the purchase price by $15 and this amount was released from escrow back to the Company prior to June 30, 2014. This reduction in purchase price reduced the goodwill acquired.

Transaction costs related to this business combination have been expensed as incurred and are included in general and administrative expenses in the Company’s unaudited condensed consolidated statements of operations. Transaction costs incurred related to this transaction were approximately $159.

The components and preliminary allocation of the purchase price consist of the following approximate amounts:

 

Net tangible assets acquired as of February 13, 2014

   $ 752  

Customer relationships

     2,042  

Non-compete agreements

     220  

Developed technology

     545  

Trade name

     82  

Deferred income tax liability

     (361

Goodwill

     1,581  
  

 

 

 

Total

   $ 4,861  
  

 

 

 

 

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The deferred income tax liability recorded in connection with the preliminary allocation of purchase price relates to the book and tax basis difference related to the acquired definite-lived intangible assets where the book amortization expense for such assets will not be deductible for tax purposes.

Net tangible assets acquired in the acquisition of Activation primarily related to the following:

 

Cash

   $ 711  

Accounts receivable

     472  

Prepaid expenses and other current assets

     27  

Property and equipment

     92  

Accounts payable

     (45

Accrued expenses and other current liabilities

     (55

Accrued capacity payments

     (450
  

 

 

 

Total

   $ 752  
  

 

 

 

Identifiable Intangible Assets

As part of the preliminary purchase price allocation, the Company determined that Activation’s separately identifiable intangible assets were its customer relationships, non-compete agreements, developed technology, and trade name. Developed technology represented internally developed software that facilitates customer transactions and provides analytical capabilities. As of the date of acquisition, the Company determined that there was no in-process research and development as the ongoing research and development efforts were nominal and related to routine, on-going maintenance efforts.

The Company used the income approach to value the acquired customer relationships, non-compete agreements, and trade name definite-lived intangible assets. This approach calculates fair value by discounting the after-tax cash flows back to a present value. The baseline data for this analysis was the cash flow estimates used to price the transaction. Cash flows were forecasted for each intangible asset then discounted based on an appropriate discount rate. The discount rates applied, which ranged between 17% and 20%, were benchmarked with reference to the implied rate of return from the transaction model, as well as an estimate of a market-participant’s weighted average cost of capital based on the capital asset pricing model.

The Company used the cost approach to value the acquired developed technology definite-lived intangible asset, as the Company determined that a market participant would be expected to have similar offerings and capabilities to build a replacement version of the software. Furthermore, it is expected that the software will be migrated over time or potentially replaced by the Company’s existing software platform and this expectation is consistent with that of a market participant. The cost approach determines fair value by calculating the reproduction cost of an exact replica of the subject intangible asset. The Company calculated the replacement cost based on the estimated hours and costs incurred to develop.

In estimating the useful life of the acquired assets, the Company considered ASC 350-30-35, which lists the pertinent factors to be considered when estimating the useful life of an intangible asset. These factors include a review of the expected use by the combined Company of the assets acquired, the expected useful life of another asset (or group of assets) related to the acquired assets, legal, regulatory or other contractual provisions that may limit the useful life of an acquired asset or may enable the extension of the useful life of an acquired asset without substantial cost, the effects of obsolescence, demand, competition and other economic factors, and the level of maintenance expenditures required to obtain the expected future cash flows from the asset. The Company amortizes its intangible assets over their estimated useful lives using a method that is based on estimated future cash flows, as the Company believes this will approximate the pattern in which the economic benefits of the assets will be utilized, or where the Company has concluded that the cash flows were not reliably determinable, on a straight-line basis.

The factors contributing to the recognition of goodwill were based upon the Company’s determination that several strategic and synergistic benefits are expected to be realized from the combination. None of the goodwill is expected to be currently deductible for tax purposes.

 

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Other Immaterial Acquisition

On April 2, 2014, one of the Company’s subsidiaries completed the acquisition of all of the outstanding stock of a privately-held company headquartered in a foreign market that provides demand response software and services in that market. The Company concluded that this acquisition represented a business combination and, therefore, has accounted for it as such. The Company believes that this acquisition gives it an immediate presence in this market and further strengthens its ability to deliver its full suite of EIS and related solutions throughout the region.

The Company concluded that this acquisition represented a business combination under ASC No. 805 but also concluded that it did not represent a material business combination and therefore, no pro forma financial information will be required.

The Company acquired this entity for an aggregate initial purchase price of $250, plus an additional $470 paid as working capital and other adjustments, all of which was paid in cash. Of the initial purchase price, $125 was retained by the Company as deferred acquisition consideration to cover general business representations and warranties. This amount will be paid 18 months after the closing date.

In addition to the amounts paid at closing, the Company may be obligated to pay additional contingent purchase price consideration related to certain earn-out amounts up to a maximum of $1,750. The earn-out payments, if any, will be based on the achievement of certain defined market legislation and certain operational metrics. With respect to a potential earn-out payment based on defined market legislation of $250, the Company concluded that this was probable of achievement and determined that the fair value as of the acquisition date of $175 represented a component of purchase price. The defined market legislation was finalized in May 2014 and the earn-out payment was deemed achieved. Therefore, the Company recorded an accretion expense between the initial fair value as of the date of acquisition and payment amount totaling $75 during the three month period ended June 30, 2014. The Company paid 50% of this earn-out payment during the three month period ended June 30, 2014 and the remaining 50% has been retained by the Company as deferred acquisition consideration to cover general business representations and warranties. This amount will be paid 18 months after the closing date. Because the remaining $1,500 of earn-out payments are only payable to those stockholders of the acquired entity who are employees as of the time of achievement, the Company has concluded that these earn-out payments should be accounted for as compensation arrangements and not as a component of purchase price. The Company will evaluate the probability of achievement and record expense ratably over the applicable estimated service period as compensation expense for the amount, if any, deemed probable of achievement. As of June 30, 2014, the Company has concluded that $500 of the potential $1,500 of earn-out payments were probable of achievement and is recording this amount ratably over the estimated service period. During the three month period ended June 30, 2014, the Company recorded $71 of expense related to this probable earn-out payment.

Based on information that existed as of the closing date, the working capital adjustment was reduced by $6. Therefore, the final purchase price was determined to be $889. Based on the Company’s evaluation of the assets and liabilities acquired, the Company determined that there were no separable identifiable intangible assets and as a result, $476 was ascribed to the fair value of net tangible assets acquired with the remaining $413 being recorded to goodwill.

The Company’s consolidated financial statements will reflect results of operations of this acquired entity from April 2, 2014 forward.

The factors contributing to the recognition of goodwill were based upon the Company’s determination that several strategic and synergistic benefits are expected to be realized from the combination. None of the goodwill is expected to be currently deductible for tax purposes.

 

3. Japan Joint Venture

On December 10, 2013, the Company entered into a joint venture with Marubeni Corporation to provide demand response applications and solutions in Japan. The new company was formed in January 2014 and named EnerNOC Japan K.K., which will have an exclusive license to market the Company’s demand response SaaS solution throughout Japan. The Company and Marubeni Corporation contributed initial capital funding in the form of common stock totaling $580 and $392, respectively. The Company is the majority-owner and owns 60% of EnerNOC Japan K.K. The Company has evaluated its accounting for its ownership interest in EnerNOC Japan K.K. in accordance with ASC 810, Consolidation (ASC 810) and has concluded that it is required to consolidate this entity. As a result, the Company has consolidated the results of this entity, which commenced during the three month period ended March 31, 2014. During the three and six month periods ended June 30, 2014, the revenues and pre-tax loss derived from EnerNOC Japan K.K. were not material to the Company’s consolidated results of operations.

 

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4. Equity Investment and License

In February 2014, the Company purchased Series A Preferred Stock (preferred stock) in a privately-held company that licenses its developed software technology for managing electricity tariff rates and related subject matters to allow third parties a central repository to obtain this information and to convert energy usage data into financial costs and savings for a purchase price of $1,000. Based on other recent financings completed by this privately-held company, the Company concluded that the $1,000 represented the fair value of its investment. The Company notes that its preferred stock investment has a substantive liquidation preference and therefore, does not represent in-substance common stock. As a result, the Company concluded that such investment should be accounted for as a cost method investment under ASC 325-20, Cost Method Investments (ASC 325-20). Under ASC 325-20, cost method investments are recorded as long-term assets initially at historical cost and are assessed for other-than-temporary impairments under the provisions of ASC 320 and are adjusted accordingly. Based on the Company’s assessment as of June 30, 2014, the Company did not identify any other-than-temporary impairment indicators. Since the inputs utilized for the Company’s periodic impairment assessment are not based on observable market data, this cost method investment is classified within Level 3 of the fair value hierarchy. To determine the fair value of this investment, the Company utilized available financial information related to the entity, including information based on recent or pending third-party equity investments in this entity. A cost method investment’s fair value is not estimated as there are no identified events or changes in circumstances that may have a significant adverse effect on the fair value of the investment and to do so would be impractical.

In addition to the above equity investment, the Company also entered into a license agreement to obtain a perpetual license to the developed software technology and other rights for $2,000. In accordance with the terms of the license agreement, the Company has a perpetual license to the developed software technology, including any future updates and enhancements, as well as, in certain instances the right to acquire ownership of the technology. The Company concluded that the $2,000 represents the fair value of the license obtained and has capitalized this amount as a component of property and equipment in its unaudited condensed consolidated balance sheets. The Company is depreciating this asset over its estimated useful life of three years with depreciation expense being recorded as a component of cost of revenues. For the three and six month periods ended June 30, 2014, the Company recorded depreciation expense of $167 and $278, respectively. The Company also has the ability to earn a royalty up to a maximum of $2,000 of certain future revenues that may be generated from the licensing of the developed software technology. The Company concluded that these potential royalties represent a potential contingent income stream and will record such royalties, if any, as a component of other income in its unaudited condensed consolidated statements of operations upon cash receipt. Through June 30, 2014, the Company had not received any such royalty payments.

 

5. Intangible Assets and Goodwill

Definite-Lived Intangible Assets

The following table provides the gross carrying amount and related accumulated amortization of intangible assets as of June 30, 2014 and December 31, 2013:

 

            As of June 30, 2014     As of December 31, 2013  
     Weighted Average
Amortization
Period (in years)
     Gross
Carrying
Amount
     Accumulated
Amortization
    Gross
Carrying
Amount
     Accumulated
Amortization
 

Customer relationships

     3.91      $ 39,784      $ (17,783   $ 29,663      $ (15,416
     

 

 

    

 

 

   

 

 

    

 

 

 

Customer contracts

     2.61      $ 5,004      $ (3,330   $ 4,887      $ (2,900

Employment agreements and non- compete agreements

     1.42        2,692        (1,546     1,676        (1,475

Software

     —          120        (120     120        (120

Developed Technology

     1.69        5,624        (2,510     2,277        (1,758

Trade name

     1.04        1,138        (599     575        (455

Patents

     5.64        180        (77     180        (68
     

 

 

    

 

 

   

 

 

    

 

 

 

Total other definite-lived intangible assets

        14,758        (8,182     9,715        (6,776
     

 

 

    

 

 

   

 

 

    

 

 

 

Total

      $ 54,542      $ (25,965   $ 39,378      $ (22,192
     

 

 

    

 

 

   

 

 

    

 

 

 

 

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The increase in the gross carrying amount of definite-lived intangible assets from December 31, 2013 to June 30, 2014 was primarily due to definite-lived intangible assets acquired in connection with the Company’s acquisitions of Entelios, Activation and Entech. In addition, the increase in the gross carrying amount of the definite-lived customer contract intangible assets was due to the acquisition of certain C&I contractual arrangements acquired during the three month period ended March 31, 2014 for a purchase price of $403 to help fulfill the Company’s contractual obligations and overall performance requirements in connection with one of its bilateral demand response arrangements with an utility. The acquisition of this intangible asset did not meet the definition of a business, as defined in ASC 805 , due to the fact that neither processes nor the additional inputs required to combine with this intangible asset in order to be capable of producing outputs were acquired. Therefore, the acquisition of this intangible asset was accounted for as an asset acquisition based on the principles described in ASC 805-50, and as there was only a single asset acquired, the entire purchase price was allocated to this single intangible asset. Based on the evaluation of the expected direct cash flows to be received from this acquired intangible asset, the Company determined that the cost exceeded the fair value and as a result, recorded impairment charges of $163 and $160 during the three month periods ended March 31, 2014 and June 30, 2014, respectively. As of June 30, 2014, the carrying value of this asset had been reduced to zero.

Amortization expense related to intangible assets amounted to $2,479 and $1,763 for the three month periods ended June 30, 2014 and 2013, respectively, and $4,362 and $3,557 for the six month periods ended June 30, 2014 and 2013, respectively. Amortization expense for developed technology, which was $616 and $139 for the three month periods ended June 30, 2014 and 2013, respectively, and $967 and $278 for the six month periods ended June 30, 2014 and 2013, respectively, is included in cost of revenues in the accompanying unaudited condensed consolidated statements of operations. Amortization expense for all other intangible assets is included as a component of operating expenses in the accompanying unaudited condensed consolidated statements of operations. The intangible asset lives range from one to ten years and the weighted average remaining life was 3.4 years at June 30, 2014. Estimated amortization is expected to be $5,038, $7,839, $5,854, $4,197, $1,645 and $4,004 for the six month period ending December 31, 2014, and years ending 2015, 2016, 2017, 2018 and thereafter, respectively.

Goodwill

In accordance with ASC 350, Intangibles—Goodwill and Other (ASC 350), the Company tests goodwill at the reporting unit level for impairment on an annual basis and between annual tests if events and circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying value. The Company’s annual impairment test date is November 30 (Impairment Test Date). During the three month period ended June 30, 2014, there were no potential impairment indicators identified that required an interim impairment test of goodwill. The Company’s market capitalization as of June 30, 2014 exceeded the book value of its consolidated net assets by more than 100%. In addition, as of November 30, 2013 (last Impairment Test Date), the fair value of both the Company’s consolidated Australian reporting unit and the Company’s all other operations reporting unit exceeded each of their respective carrying values by more than 50%.

The following table shows the change of the carrying amount of goodwill from December 31, 2013 to June 30, 2014:

 

Balance at December 31, 2013

   $ 77,104  

Acquisitions

     24,815  

Foreign currency translation

     736  
  

 

 

 

Balance at June 30, 2014

   $ 102,655  
  

 

 

 

 

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6. Net Loss Per Share

A reconciliation of basic and diluted share amounts for the three and six month periods ended June 30, 2014 and 2013 are as follows (shares in thousands):

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2014      2013      2014      2013  

Basic weighted average common shares outstanding

     28,461        27,852        28,226        27,611  

Weighted average common stock equivalents

     —          —          —          —    
  

 

 

    

 

 

    

 

 

    

 

 

 

Diluted weighted average common shares outstanding

     28,461        27,852        28,226        27,611  
  

 

 

    

 

 

    

 

 

    

 

 

 

Weighted average anti-dilutive shares related to:

           

Stock options

     833        1,184        864        1,217  

Nonvested restricted shares

     2,137        2,471        2,134        2,300  

Restricted stock units

     —          50        9        65  

Escrow shares

     —          64        —          64  

In reporting periods in which the Company reports a 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.

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 and restricted stock units that vest based on achievement of performance conditions, because performance conditions are considered contingencies under ASC 260, Earnings per Share (ASC 260) the criteria for contingent shares must first be applied before determining the dilutive effect of these types of share-based payments. Prior to the end of the contingency period (i.e., before the performance conditions have been satisfied), the number of contingently issuable common shares to be included in diluted weighted average common shares outstanding should be based on the number of common shares, if any, that would be issuable under the terms of the arrangement if the end of the reporting period were the end of the contingency period (e.g., the number of shares that would be issuable based on current performance criteria) assuming the result would be dilutive.

In connection with certain of the Company’s business combinations, the Company issued common shares that were held in escrow upon closing of the applicable business combination. The Company excludes shares held in escrow from the calculation of basic weighted average common shares outstanding where the release of such shares is contingent upon an event and not solely subject to the passage of time. As of June 30, 2014, the Company had no shares of common stock held in escrow.

The 254,654 shares related to a component of the deferred purchase price consideration from the acquisition of M2M Communications Corporation (M2M), which are not subject to adjustment as the issuance of such shares is not subject to any contingency, are included in both the basic and diluted weighted average common shares outstanding amounts.

7. Disclosure of Fair Value of Financial Instruments

The Company’s financial instruments mainly consist of cash and cash equivalents, restricted cash, accounts receivable and accounts payable. The carrying amounts of the Company’s cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair value due to the short-term nature of these instruments. At both June 30, 2014 and December 31, 2013, the Company had no outstanding debt obligations.

 

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8. Fair Value Measurements

The tables below present the balances of assets and liabilities measured at fair value on a recurring basis at June 30, 2014 and December 31, 2013:

 

     Fair Value Measurement at June 30, 2014 Using  
     Totals      Quoted Prices in
Active Markets
for Identical
Assets (Level 1)
     Significant
Other
Observable
Inputs (Level 2)
     Unobservable
Inputs (Level 3)
 

Assets:

           

Money market funds (1)

   $ 98,685      $ 98,685      $ —        $ —    

Liabilities:

           

Accrued contingent purchase price consideration (2)

   $ 427      $ —        $ —        $ 427  

Deferred acquisition consideration (2)

   $ 824      $ —        $ —        $ 824  

 

(1) Total of $98,505 included in cash and cash equivalents and $180 included in restricted cash in the accompanying unaudited condensed consolidated balance sheets and 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. The decrease from December 31, 2013 was primarily due to cash used in operations and cash utilized for the Company’s acquisitions during the six month period ended June 30, 2014.
(2) Accrued contingent purchase price consideration, which resulted from the Company’s acquisitions of Entelios and Activation and deferred acquisition consideration, which is a result of the Company’s other immaterial acquisition completed in April 2014 and the Company’s acquisition of M2M in January 2011, represent the only assets or liabilities that the Company measures and records at fair value on a recurring basis using significant unobservable inputs (Level 3). The aggregate increase in fair value of liabilities for the six month period ended June 30, 2014 was due to the increase in the liabilities as a result of a change in the fair value of the amortization of the applicable discounts related to the time value of money of $45 and changes in exchange rates. In addition, as a result of the achievement of a certain earn-out related to the Company’s other immaterial acquisition completed in April 2014, there was an increase in fair value of this earn-out of $75 recorded during the three month period ended June 30, 2014. Refer to Note 2 for further discussion. There were no other changes to the probability or timing of payment during the six month period ended June 30, 2014.

With respect to assets measured at fair value on a non-recurring basis, these represent impaired long-lived assets (refer to Note 1 for discussion of the determination of fair value of these assets), impaired definite-lived intangible assets (refer to Note 2 for discussion of the determination of fair value of these assets) and cost method investments (refer to Note 4 for discussion of the determination of fair value of these assets).

The table below presents the balances of assets and liabilities measured at fair value on a recurring basis at December 31, 2013:

 

     Fair Value Measurement at December 31, 2013 Using  
     Totals      Quoted Prices in
Active Markets
for Identical
Assets (Level 1)
     Significant
Other
Observable
Inputs (Level 2)
     Unobservable
Inputs (Level 3)
 

Assets:

           

Money market funds (1)

   $ 146,626      $ 146,626      $ —        $ —    

Liabilities:

           

Deferred acquisition consideration (2)

   $ 566      $ —        $ —        $ 566  

 

(1) Total of $145,076 included in cash and cash equivalents and $1,550 included in restricted cash in the accompanying unaudited condensed consolidated balance sheets and represents the only assets 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) Deferred acquisition consideration which is a liability and was the result of the Company’s acquisition of M2M represents the only liability that the Company measures and records at fair value on a recurring basis using significant unobservable inputs (Level 3). The aggregate increase in fair value of this liability for the year ended December 31, 2013 of $33 was due to the increase in the liability as a result of the amortization of the discount related to the time value of money. There were no changes with respect to the timing of payment subsequent to December 31, 2013.

9. Financing Arrangements

In March 2012, the Company and one of its subsidiaries entered into a $50,000 credit facility with Silicon Valley Bank (SVB), which was subsequently amended in June 2012 and April 2013 (the 2012 credit facility). On April 12, 2013, the Company, one its subsidiaries and SVB entered into an amendment to the 2012 credit facility to extend the termination date from April 15, 2013 to April 30, 2013. On April 18, 2013, the Company, one of its subsidiaries and SVB terminated the 2012 credit facility.

 

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On April 18, 2013, the Company entered into a $70,000 senior secured revolving credit facility with several lenders from time to time party thereto and SVB, as administrative agent, swingline lender, issuing lender, lead arranger and book manager (SVB and together with other lenders, and referred to herein as the lenders), which was subsequently amended in August 2013, December 2013 and January 2014 (2013 credit facility). The 2013 credit facility replaced the 2012 credit facility.

The 2013 credit facility provides for a two year revolving line of credit in the aggregate amount of $70,000, subject to increase from time to time up to an aggregate amount of $100,000 with an additional commitment from the lenders or new commitments from new financial institutions.

Subject to continued compliance with the covenants contained in the 2013 credit facility, the full amount of the 2013 credit facility may be available for issuances of letters of credit and up to $5,000 may be available for swing line loans. The interest on revolving loans under the 2013 credit facility will accrue, at the Company’s election, at either (i) the Eurodollar Rate with respect to the relevant interest period plus 2.00% per annum or (ii) the ABR (defined as the highest of (x) the “prime rate” as quoted in the Wall Street Journal , and (y) the Federal Funds Effective Rate plus 0.50%) plus 1.00% per annum. The letter of credit fee charged under the 2013 credit facility is 2.00% per annum. The Company expenses the interest and letter of credit fees under the 2013 credit facility, as applicable, in the period incurred. The obligations under the 2013 credit facility are secured by all domestic assets of the Company and several of its domestic subsidiaries. The 2013 credit facility terminates on April 18, 2015 and all amounts outstanding thereunder will become due and payable in full and the Company would be required to collateralize with cash any outstanding letters of credit under the 2013 credit facility up to 105% of the amounts outstanding. In connection with the 2013 credit facility and related amendments, the Company incurred financing costs of approximately $859 which have been deferred and are being amortized to interest expense over the term of the 2013 credit facility, or through April 18, 2015.

The 2013 credit facility contains customary terms and conditions for credit facilities of this type, including, among other things, restrictions on the ability of the Company and its subsidiaries to incur additional indebtedness, create liens, enter into transactions with affiliates, transfer assets, make certain acquisitions, pay dividends or make distributions on, or repurchase, the Company’s common stock, consolidate or merge with other entities, or undergo a change in control. In addition and as described above, the Company is required to meet certain monthly and quarterly financial covenants customary for this type of credit facility, including maintaining a minimum specified level of free cash flow, a minimum specified unrestricted cash balance and a minimum specified ratio of current assets to current liabilities.

The 2013 credit facility contains customary events of default, including payment defaults, breaches of representations, breaches of affirmative or negative covenants, cross defaults to other material indebtedness, bankruptcy and failure to discharge certain judgments. If a default occurs and is not cured within any applicable cure period or is not waived, SVB may accelerate the Company’s obligations under the 2013 credit facility. If the Company is determined to be in default then any amounts outstanding under the 2013 credit facility would become immediately due and payable and the Company would be required to collateralize with cash any outstanding letters of credit up to 105% of the amounts outstanding.

As of June 30, 2014, the Company was in compliance with all of its covenants under the 2013 credit facility. The Company believes that it is reasonably assured that it will comply with the covenants of the 2013 credit facility for the foreseeable future.

As of June 30, 2014, the Company had no borrowings, but had outstanding letters of credit totaling $16,974, under the 2013 credit facility. The decrease in the amount of outstanding letters of credit from December 31, 2013 to June 30, 2014 is primarily the result of a reduction in the collateral requirements for demand response arrangements and obligations. As of June 30, 2014, the Company had $53,026 available under the 2013 credit facility for future borrowings or issuances of additional letters of credit. Subsequent to June 30, 2014, the outstanding letters of credit has decreased as a result of a cancellation of a letter of credit totaling $4,900 due to a reduction in collateral requirements under an open market demand response program partially offset by the issuance of an additional letter of credit totaling $3,100 as collateral under a new demand response arrangement with an utility.

In May 2014, the Company was required to provide incremental financial assurance in connection with its capacity bid in a certain open market bidding program. The Company has provided this financial assurance utilizing a $22,000 letter of credit issued under the 2013 credit facility and additionally, utilized $4,500 of its available unrestricted cash on hand. During the three month period ended June 30, 2014, based on the capacity that the Company cleared in the above open market bidding program and the required post-auction financial assurance requirements, the Company recovered all of its available cash that it had provided as financial assurance prior to the auction and $17,000 of the letter of credit was cancelled.

 

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10. Commitments and Contingencies

In July 2012, the Company entered into a lease for its principal executive offices at One Marina Park Drive, Floors 4-6, Boston, Massachusetts. The lease term is through July 2020 and the lease contains both a rent holiday period and escalating rental payments over the lease term. The lease requires payments for additional expenses such as taxes, maintenance, and utilities and contains a fair value renewal option. The Company began occupying the space during the second quarter of fiscal 2013. In accordance with the terms of the lease, the landlord provided certain lease incentives with respect to the leasehold improvements. In accordance with ASC 840, Leases (ASC 840), the Company recorded the incentives as deferred rent and will reflect these amounts as reductions of lease expense over the lease term. Although lease payments under this arrangement did not commence until August 2013, as the Company had the right to use and controlled physical access to the space, it determined that the lease term commenced in July 2012 and, as a result, began recording rent expense on this lease arrangement at that time on a straight-line basis. The lease also contains certain provisions requiring the Company to restore certain aspects of the leased space to its initial condition. The Company has determined that these provisions represent asset retirement obligations and recorded the estimated fair value of these obligations as the related leasehold improvements were incurred. The Company will accrete the liability to fair value over the life of the lease as a component of operating expenses. As of June 30, 2014, the Company recorded an asset retirement obligation of $413.

In March 2014, the Company entered into a lease for its California operations. The lease term runs through September 2019 and the lease contains both a rent holiday period and escalating rental payments over the lease term. The lease requires payments for additional expenses such as taxes, maintenance, and utilities and contains a fair value renewal option. The lease commenced on April 1, 2014.

In connection with the Company’s acquisitions completed during the six month period ended June 30, 2014, the Company acquired certain facility operating lease arrangements which were all considered to contain current market terms and rates. These leases have original lease terms between one and ten years and expire through March 2020. Certain of the leases require payments for additional expenses such as taxes, maintenance, and utilities and contain fair value renewal options. There were no ongoing rent holidays or escalating rent payments over the remaining lease terms as of the dates of acquisition.

As of June 30, 2014, future minimum lease payments for operating leases with non-cancelable terms of more than one year were as follows:

 

     Operating Leases  

Remainder of 2014

   $ 3,108   

2015

     6,397   

2016

     6,116   

2017

     5,933   

2018

     6,074   

Thereafter

     8,031   
  

 

 

 

Total minimum lease payments (not reduced by sublease rentals of $176)

   $ 35,659   
  

 

 

 

As of June 30, 2014 and December 31, 2013, the Company had a deferred rent liability representing rent expense recorded on a straight-line basis in excess of contractual lease payments of $7,271 and $7,629, respectively, which is included in other liabilities in the accompanying unaudited condensed consolidated balance sheets.

As of June 30, 2014, the Company was contingently liable under outstanding letters of credit for $16,974. As of June 30, 2014 and December 31, 2013, the Company had restricted cash balances of $916 and $1,834, respectively, which primarily related to cash utilized to collateralize certain demand response programs.

The Company is subject to performance guarantee requirements under certain utility and electric power grid operator customer contracts and open market bidding program participation rules, which may be secured by cash or letters of credit. Performance guarantees as of June 30, 2014 were $17,296 and included deposits held by certain customers of $142 and certain restricted cash utilized to collateralize certain demand response programs of $180 at June 30, 2014. These amounts primarily

 

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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 June 30, 2014, the Company had $2,539 in deferred fees for these arrangements which were included in deferred revenues as of June 30, 2014. As of June 30, 2014, 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 $9,125.

As of June 30, 2014 and December 31, 2013, the Company accrued in the accompanying unaudited condensed consolidated balance sheets $420 and $1,720, respectively, of performance adjustments related to fees received for its participation in a certain demand response programs. The decrease in the accrual from December 31, 2013 was the result of the Company repaying $1,488 to the electric power grid operator during the six month period ended June 30, 2014 since the Company did not deliver all of its MW obligations under this demand response program, offset by an increase in additional performance adjustments. The Company believes that it is probable that these performance adjustments will need to be re-paid to the electric power grid operator and since the electric power grid operator has the right to require repayment at any point at its discretion, the amounts have been classified as a current liability.

The Company typically grants customers a limited warranty that guarantees that its hardware will substantially conform to current specifications for one year from the delivery date. Based on the Company’s operating history, the liability associated with product warranties has been determined to be nominal.

In connection with the Company’s agreement for its employee health insurance plan, the Company could be subject to an additional payment if the agreement is terminated. The Company has not elected to terminate this agreement nor does the Company believe that termination is probable for the foreseeable future. As a result, the Company has determined that it is not probable that a loss is likely to occur and no amounts have been accrued related to this potential payment upon termination. As of June 30, 2014, the payment due upon termination would be $1,026.

On March 15 2011, the Federal Energy Regulatory Commission (FERC) issued Order 745, Demand Response Compensation in Organized Wholesale Energy Markets, which was effective April 25, 2011. Under Order 745, the FERC amended its regulations under the Federal Power Act to ensure that when a demand response resource participating in an organized wholesale energy market administered by a Regional Transmission Organization (RTO) or Independent System Operator (ISO) has the capability to balance supply and demand as an alternative to a generation resource and when dispatch of that demand response resource is cost-effective as determined by the net benefits test described in this rule, that demand response resource must be compensated for the service it provides to the energy market at the market price for energy, referred to as the locational marginal price (LMP). This approach for compensating demand response resources helped to ensure the competitiveness of organized wholesale energy markets and remove barriers to the participation of demand response resources, thus ensuring just and reasonable wholesale rates. As a result, Order 745 impacted the energy rates that the Company received in two open market economic demand response programs.

On May 23, 2014, the United States Court of Appeals for the District of Columbia Circuit issued two orders ( EPSA v. FERC) related to FERC Order 745, a ruling relating to demand response compensation in FERC administered wholesale markets. In a 2-1 decision of a panel of the D.C. Circuit, the Court vacated Order 745 on the grounds that FERC lacked jurisdiction over demand response. The Court further stayed its own order until seven days following disposition of any timely petition for rehearing. Order 745 relates exclusively to compensation in FERC jurisdictional wholesale energy markets, and by its terms does not apply to FERC jurisdictional capacity markets. Also on June 11, 2014, the FERC announced that it would be seeking rehearing en banc of the 2-1 decision vacating Order 745. At the present time, Order 745 remains in effect, per the Court’s stay, and is likely to remain in effect through the disposition of FERC and other rehearing petitions.

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 the 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

 

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concluded that the historical revenue recognition was appropriate and that the potential risk of refund as a result of the May 23, 2014 Court ruling on Order 745 should be evaluated as a potential contingent loss as a result of this event in accordance with ASC 450, Contingencies . Based on the Company’s assessment of this matter, it has determined that a loss is not currently probable. As a result, no loss accrual is currently recorded under ASC 450. Based on the Company’s assessment, it concluded that it is reasonably possible that the Company may incur a loss and the potential loss would be capped at the fees received under the program, which is approximately $20,100.

Subsequent to May 23, 2014, the Company has determined that due to the potential risk of refund, all fees received prospectively from continued participation, if any, in these programs 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 June 30, 2014, the Company has not received any fees related to these programs.

11. Stockholders’ Equity

2014 Long-Term Incentive Plan

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

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

If a stock award granted under the 2014 Plan expires or otherwise terminates without all of the shares covered by such stock award having been issued, or is settled in cash, such expiration, termination or settlement will not reduce the number of shares of common stock that may be available for issuance under the 2014 Plan, and the unissued shares subject to such stock award will again become available for issuance under the 2014 Plan. If any shares of common stock issued pursuant to a stock award are forfeited back to or repurchased by the Company because of the failure to meet a contingency or condition required to vest such shares, then the shares that are forfeited or repurchased will again become available for issuance under the 2014 Plan. In addition, any shares of common stock reacquired or withheld (or not issued) by the Company in satisfaction of tax withholding obligations on a stock award or as consideration for the exercise or purchase price of a stock award will again become available for issuance under the 2014 Plan. During the period of the effective date of the 2014 Plan through June 30, 2014, the Company repurchased 16,908 shares to satisfy employee tax withholdings that became available for future grant under the 2014 Plan.

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

As of June 30, 2014, 1,675,749 shares were available for future grant under the 2014 Plan.

Share Repurchase Program

On August 6, 2013, the Company’s Board of Directors authorized the repurchase of up to $30,000 of the Company’s common stock during the period from August 6, 2013 through August 6, 2014, unless earlier terminated by the Board of Directors. The share repurchase program expired on August 6, 2014. During the three and six month periods ended June 30, 2014, there were no repurchases of the Company’s common stock pursuant to its publicly announced share repurchase program, and as of June 30, 2014, $20,545 was available for repurchase under the Plan. The Company repurchased 65,624 and 234,800 shares of its common stock during the three and six month periods ended June 30, 2014, respectively, to cover employee minimum statutory income tax withholding obligations in connection with the vesting of restricted stock under its equity incentive plans, which the Company pays in cash to the appropriate taxing authorities on behalf of its employees. All shares were retired upon repurchase.

 

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Stock-Based Compensation

During the six month periods ended June 30, 2014 and 2013, the Company issued 6,632 shares and 8,920 shares of its common stock, respectively, to certain executives to satisfy a portion of the Company’s bonus obligation to these individuals.

The fair value of options granted was estimated at the date of grant using the following weighted average assumptions:

 

     Six Months Ended June 30,  
     2014     2013  

Risk-free interest rate

     2.53     1.80

Vesting term, in years

     2.22       2.22  

Expected annual volatility

     70     75

Expected dividend yield

     —       —  

Exit rate pre-vesting

     7.8     7.7

Exit rate post-vesting

     14.06     14.06

The risk-free interest rate is the rate available as of the option date on zero-coupon United States government issues with a term equal to the expected life of the option. Volatility measures the amount that a stock price has fluctuated or is expected to fluctuate during a period. The Company calculates volatility using a component of implied volatility and historical volatility to determine the value of share-based payments. The Company has not paid dividends on its common stock in the past and does not plan to pay any dividends in the foreseeable future. In addition, the terms of the 2013 credit facility preclude the Company from paying dividends. During the three and six month periods ended June 30, 2014, the Company updated its estimated pre-vesting and post-vesting exit rates applied to options, restricted stock and restricted stock units based on an evaluation of demographics of its employee groups and historical forfeitures for these groups in order to determine its option valuations as well as its stock-based compensation expense noting no change in the exit-rate post vesting and no material changes in the expected annual volatility or exit rate pre-vesting. The changes in estimates of the volatility and exit rate pre-vesting did not have a material impact on the Company’s stock-based compensation expense recorded in the accompanying unaudited condensed consolidated statements of operations for the three and six month periods ended June 30, 2014.

The components of stock based compensation expense are disclosed below:

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2014     2013      2014     2013  

Stock options

   $ 71     $ 349      $ 257     $ 748  

Restricted stock and restricted stock units

     3,728  (1)      2,958        7,769  (1)      7,263  
  

 

 

   

 

 

    

 

 

   

 

 

 

Total

   $ 3,799     $ 3,307      $ 8,026     $ 8,011  
  

 

 

   

 

 

    

 

 

   

 

 

 

 

(1) Due to the fact that the Company’s chief executive officer is required to receive his 2014 performance based bonus, if achieved, in shares of common stock of the Company determined based on the cash value of such bonus divided by the fair market value of the Company’s common stock on the date that the Company’s Compensation Committee validates the achievement of the performance bonus metrics, in accordance with the Company’s policy, the Company is recording this amount as stock-based compensation expense ratably over the applicable performance and service period in accordance with ASC 718, Stock Compensation (ASC 718). During the three and six month periods ended June 30, 2014, the Company recorded $128 and $253, respectively, of stock-based compensation expense.

Stock based compensation is recorded in the accompanying unaudited condensed consolidated statements of operations, as follows:

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2014      2013      2014      2013  

Selling and marketing expenses

   $ 1,372      $ 1,456      $ 2,565      $ 2,846  

General and administrative expenses

     2,108        1,520        4,804        4,472  

Research and development expenses

     319        331        657        693  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 3,799      $ 3,307      $ 8,026      $ 8,011  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

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The Company recognized no material income tax benefit from share-based compensation arrangements during the three and six month periods ended June 30, 2014 and 2013. In addition, no material compensation cost was capitalized during the three and six month periods ended June 30, 2014 and 2013.

The following is a summary of the Company’s stock option activity during the six month period ended June 30, 2014:

 

     Six Months Ended June 30, 2014  
     Number of
Shares
Underlying
Options
    Exercise
Price Per
Share
     Weighted-
Average
Exercise Price
Per Share
     Aggregate
Intrinsic
Value
 

Outstanding at December 31, 2013

     960,742     $ 0.17 - $48.06       $ 17.87      $ 4,691  (2) 

Granted

     2,809          20.25     

Exercised

     (60,279        10.29      $ 666  (3) 

Cancelled

     (80,782        29.12     
  

 

 

         

Outstanding at June 30, 2014

     822,490     $ 0.35 - $48.06         17.33      $ 5,044  (4) 
  

 

 

   

 

 

    

 

 

    

 

 

 

Weighted average remaining contractual life in years: 2.9

          

Exercisable at end of period

     807,481     $ 0.35 - $48.06       $ 17.33      $ 4,991  (4) 
  

 

 

   

 

 

    

 

 

    

 

 

 

Weighted average remaining contractual life in years: 2.8

          

Vested or expected to vest at June 30, 2014 (1)

     821,548     $ 0.35 - $48.06       $ 17.33      $ 5,040  (4) 
  

 

 

   

 

 

    

 

 

    

 

 

 

 

(1) This represents the number of vested options as of June 30, 2014 plus the number of unvested options expected to vest as of June 30, 2014 based on the unvested options outstanding at June 30, 2014, adjusted for the estimated forfeiture rate of 7.8%.
(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, 2013 of $17.21 and the exercise price of the underlying options.
(3) The aggregate intrinsic value was calculated based on the positive difference between the fair value of the Company’s common stock on the applicable exercise dates and the exercise price of the underlying options.
(4) The aggregate intrinsic value was calculated based on the positive difference between the estimated fair value of the Company’s common stock on June 30, 2014 of $18.95 and the exercise price of the underlying options.

Additional Information About Stock Options

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2014      2013      2014      2013  
     In thousands, except share and
per share amounts
     In thousands, except share and
per share amounts
 

Total number of options granted during the period

     1,000        2,500        2,809        3,500  

Weighted-average fair value per share of options granted

   $ 10.76      $ 10.19      $ 11.35      $ 10.15  

Total intrinsic value of options exercised (1)

   $ 75      $ 498      $ 666      $ 1,051  

 

(1) Represents the difference between the market price at exercise and the price paid to exercise the options.

 

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Of the stock options outstanding as of June 30, 2014, 813,997 options were held by employees and directors of the Company and 8,493 options were held by non-employees. For outstanding unvested stock options related to employees and directors of the Company as of June 30, 2014, the Company had $120 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 1.5 years. There were no unvested non-employee stock options as of June 30, 2014.

Restricted Stock and Restricted Stock Units

For non-vested restricted stock subject to service-based vesting conditions outstanding as of June 30, 2014, the Company had $20,911 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 3.0 years. For non-vested restricted stock subject to performance-based vesting conditions outstanding that were probable of vesting as of June 30, 2014, the Company had $8,710 of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 1.9 years. As of June 30, 2014, the Company had no non-vested restricted stock units that were subject to service-based vesting conditions outstanding and had no non-vested restricted stock units subject to performance-based vesting conditions that were probable of vesting. For non-vested restricted stock units subject to outstanding performance-based vesting conditions that were not probable of vesting at June 30, 2014, the Company had $5,035 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.

Restricted Stock

The following table summarizes the Company’s restricted stock activity during the six month period ended June 30, 2014:

 

     Number of
Shares
    Weighted Average
Grant Date Fair
Value Per Share
 

Nonvested at December 31, 2013

     2,395,322     $ 13.48  

Granted

     968,149       20.05  

Vested

     (902,919     15.14  

Cancelled

     (137,305     11.04  
  

 

 

   

Nonvested at June 30, 2014

     2,323,247     $ 16.69  
  

 

 

   

 

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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 25% cliff vesting after one year and the remaining 75% vesting ratably quarterly thereafter, with certain exceptions. Included in the above table are 7,000 shares of restricted stock granted to certain non-executive employees and 31,365 shares of restricted stock granted to members of the Company’s board of directors during the six month period ended June 30, 2014 that immediately vested. Also included in the table above are shares of restricted stock granted to non-employee advisory board members. In fiscal 2013, the Company granted 33,000 shares of restricted stock to non-employee advisory board members. Of the 33,000 shares of restricted stock granted, 22,000 shares vest ratably on a quarterly basis over four years and 11,000 shares of restricted stock vest in equal annual tranches on July 1, 2014 and July 1, 2015, as long as the individuals continue to serve as advisory board members through the date of the applicable vesting. The Company will account for these share-based awards in accordance with ASC 505-50, Equity Based Payments to Non-Employees (ASC 505-50), which will result in the Company continuing to re-measure the fair value of the share-based awards until such time as the awards vest. During the three and six month periods ended June 30, 2014, the Company recorded stock-based compensation expense related to these awards of $27 and $115, respectively. As of June 30, 2014, 27,500 shares were unvested and had a fair value of $521.

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. During the six month period ended June 30, 2014, the Company granted 388,034 shares of nonvested restricted stock to certain executives that contain performance-based vesting conditions. Of these shares, 25% vest in 2015 if the performance criteria related to certain 2014 operating results are achieved and the executive is still employed as of the vesting date and the remaining 75% of the shares vest quarterly over a three year period thereafter as long as the executive is still employed as of the vesting date. If the performance criteria related to certain 2014 operating results are not achieved, 100% of the shares are forfeited.

During the three and six month periods ended June 30, 2014, there were no changes to probabilities of vesting of performance-based stock awards which had a material impact on stock-based compensation expense or amounts expected to be recognized.

Additional Information about Restricted Stock

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2014      2013      2014      2013  
    

in thousands, except share and per

share amounts

 

Total number of shares of restricted stock granted during the period

     476,250        428,725        968,149        1,410,566  

Weighted average fair value per share of restricted stock granted

   $ 19.09      $ 15.13      $ 20.05      $ 16.51  

Total number of shares of restricted stock vested during the period

     208,518        117,946        902,919        695,239  

Total fair value of shares of restricted stock vested during the period

   $ 4,402      $ 1,216      $ 19,360      $ 7,335  

Restricted Stock Units

The following table summarizes the Company’s restricted stock unit activity during the six month period ended June 30, 2014:

 

     Number of
Shares
    Weighted Average
Grant Date Fair
Value Per Share
 

Nonvested at December 31, 2013

     34,250     $ 28.59  

Granted

     250,382       20.11  

Vested

     (34,250     28.59  

Cancelled

     —         —    
  

 

 

   

Nonvested at June 30, 2014

     250,382     $ 20.11  
  

 

 

   

 

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During the three month period ended June 30, 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. Of these shares, up to 10% vest in 2015 if the performance criteria related to certain 2014 operating results are achieved and the employee is still employed as of the vesting date, up to 20% vest in 2016 if the performance criteria related to certain 2015 operating results are achieved and the employee is still employed as of the vesting date, and up to the remaining 70% of the shares vest in 2017 if the performance criteria related to certain 2016 operating results are achieved and the employee is still employed as of the vesting date. If the performance criteria related to certain 2014, 2015 and 2016 operating results are not achieved, 100% of the shares are forfeited. As of June 30, 2014, the awards have not been deemed probable of vesting.

Additional Information about Restricted Stock Units

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 
     2014      2013      2014      2013  
    

in thousands, except share and per

share amounts

 

Total number of shares of restricted stock units vested during the period

     —          3,125        34,250        56,603  

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

   $ —        $ 38      $ 772      $ 948  

12. Income Taxes

The Company has provided a $264 worldwide tax provision and ($161) worldwide tax benefit for the three months and six months ended June 30, 2014, respectively. The tax provision consists of a tax benefit on its foreign loss for the quarter and a U.S. tax expense related to tax deductible goodwill that generates a deferred tax liability that cannot be used as a source of income against which deferred tax assets may be realized. The provision for income taxes for the three months ended June 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 and a $1,450 provision for deferred income taxes in connection with the sale of Utility Solution Consulting.

ASC 740 also provides criteria for the recognition, measurement, presentation and disclosures of uncertain tax positions. A tax benefit from an uncertain tax position may be recognized if it is “more likely than not” that the position is sustainable based solely on its technical merits. During the three and six month periods ended June 30, 2014, there were other material changes in the Company’s uncertain tax positions.

Each interim period is considered an integral part of the annual period and tax expense is measured using an estimated annual effective tax rate. An enterprise is required, at the end of each interim reporting period, to make its best estimate of the effective tax rate for the full fiscal year and use that rate to provide for income taxes on a current year-to-date basis. However, if an enterprise is unable to make a reliable estimate of its annual effective tax rate, the actual effective tax rate for the year-to-date period may be the best estimate of the annual effective tax rate. The Company is able to reliably estimate the annual effective tax rate on its foreign earnings, but is unable to reliably estimate the annual effective tax rate on its U.S. earnings.

If the Company is able to make a reliable estimate of its U.S. annual effective tax rate as of September 30, 2014, the Company is expected to utilize that rate to provide for income taxes on a current year-to-date basis. The Company may potentially record a significant provision for income taxes during the three month period ending September 30, 2014 since the majority of the forecasted U.S. income will be realized during the three month period ending September 30, 2014 and may potentially record a significant benefit from income taxes being recorded during the three month period ending December 31, 2014.

The Company reviews all available evidence to evaluate the recovery of deferred tax assets, including the recent history of losses in all tax jurisdictions, as well as its ability to generate income in future periods. As of June 30, 2014, due to the uncertainty related to the ultimate use of certain deferred income tax assets, the Company has recorded a valuation allowance on certain of its U.S., Australia, Germany, Japan, Korea, New Zealand, and UK deferred tax assets.

 

13. Concentrations of Credit Risk

The following table presents the Company’s significant customers. PJM Interconnection (PJM) and ISO-New England, Inc. (ISO-NE) are regional electric power grid operator customers in the mid-Atlantic and New England regions, respectively, that are comprised of multiple utilities and were formed to control the operation of the regional power system, coordinate the supply of

 

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electricity, and establish fair and efficient markets. Independent Market Operator (IMO) is an entity that was established to administer and operate the Western Australia (WA) wholesale electricity market. The main objectives of the IMO are to coordinate the supply of electricity, encourage competition in the market, establish fair and efficient markets, and ensure economic supply of electricity to customers in WA. No other customers comprised more than 10% of consolidated revenues during the three or six month periods ended June 30, 2014 and 2013.

 

     Three Months Ended June 30,  
     2014     2013  
     Revenues     % of Total
Revenues
    Revenues     % of Total
Revenues
 

ISO-NE

   $ 4,306       10   $ 4,666       13

IMO

   $ 4,397       10                  

PJM

                                    

 

     Six Months Ended June 30,  
     2014     2013  
     Revenues     % of Total
Revenues
    Revenues     % of Total
Revenues
 

PJM

   $ 21,212       22                  

ISO-NE

                     $ 9,427       14

IMO

                                    

 

* Represented less than 10% of consolidated revenues.

Electric Reliability Council of Texas (ERCOT) was the only customer that comprised 10% or more of the Company’s accounts receivable balance at June 30, 2014, representing 13% of the balance. PJM and Southern California Edison Company were the only customers that each comprised 10% or more of the Company’s accounts receivable balance at December 31, 2013, representing 39% and 18%, respectively, of such balance.

Unbilled revenue related to PJM was $0 and $64,643 at June 30, 2014 and December 31, 2013, respectively. There was also no significant unbilled revenue for any other customers at June 30, 2014 and December 31, 2013.

Deposits and restricted cash include 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 $142 and $128 at June 30, 2014 and December 31, 2013, respectively.

14. Legal Proceedings

The Company is subject to legal proceedings, claims and litigation arising in the ordinary course of business. The Company does not expect the ultimate costs to resolve these matters to have a material adverse effect on its consolidated financial condition, results of operations or cash flows.

On May 3, 2013, a purported shareholder of the Company (the Plaintiff) filed a derivative and class action complaint in the United States District Court for the District of Delaware (the Court) against certain of the Company’s officers and directors as well as the Company as a nominal defendant (the Defendants). The complaint asserts derivative claims, purportedly brought on behalf of the Company, for breach of fiduciary duty, waste of corporate assets, and unjust enrichment in connection with certain equity grants (awarded in 2010, 2012, and 2013) that allegedly exceeded an annual limit on per-employee equity grants purported to be contained in the 2007 Plan. The complaint also asserts a direct claim, brought on behalf of the Plaintiff and a proposed class of the Company’s shareholders, alleging the Company’s proxy statement filed on April 26, 2013 was false and misleading because it failed to disclose that the equity grants were improper. The plaintiff seeks, among other relief, rescission of the equity grants, unspecified damages, injunctive relief, disgorgement, attorneys’ fees, and such other relief as the Court may deem proper.

 

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Defendants filed a motion to dismiss on August 30, 2013. Plaintiff responded to the motion on October 18, 2013 and Defendants replied on November 22, 2013. No hearing date has been set.

On June 27, 2014, the parties engaged in mediation and reached agreement in principle on the terms of a potential settlement. Pursuant to the settlement, defendant members of the Company’s Board of Directors would cause their insurer to make a cash payment of $500 to the Company, and cause the Company to undertake certain reforms in connection with equity granting practices. However, the settlement remains subject to numerous contingencies, including finalization of settlement documentation and court approval. Additionally, the Company’s management believes that the defendants have substantial legal and factual defenses to the claims in the complaint, and intends to pursue these defenses vigorously. There can be no assurance, however, that such efforts will be successful. However, as a result of this agreement in principle on the terms of a potential settlement, the Company has determined that it is probable that it will incur a loss related to this matter principally related to the remaining amount of its insurance deductible, which was not material and has been accrued for as of June 30, 2014. With respect to the $500 payment to the Company that would result under the terms of this settlement, this amount represents a contingent gain and will be recorded as other income, if and when, the amount is realized. In addition, regardless of the outcome of this matter, the matter may divert financial and management resources and result in general business disruption, including that the Company may suffer from adverse publicity that could harm its reputation and negatively impact its stock price.

Indemnification Provisions

The Company includes indemnification provisions in certain of its contracts. These indemnification provisions include provisions indemnifying the customer against losses, expenses, and liabilities from damages that could be awarded against the customer in the event that the Company’s services and related enterprise software platforms are found to infringe upon a patent or copyright of a third party. The Company believes that its internal business practices and policies and the ownership of information limits the Company’s risk in paying out any claims under these indemnification provisions.

15. Gain on Sale of Service Line

During the three month period ended December 31, 2013, the Company committed to a plan to sell a component of the business that the Company acquired in connection with its acquisition of Global Energy Partners, Inc. (Global Energy) in January 2011 related to consulting and engineering support services to the global electric utility industry, with a particular focus on providing consulting services to utilities (Utility Solutions Consulting). The Company engaged a third party consultant to assist the Company in actively marketing this service line for sale and identify a buyer. Based on the Company’s evaluation of the assets held for sale criteria under ASC 360-10, Impairment and Disposal of Long-Lived Assets , it concluded all of the criteria were met and that the assets and liabilities of Utility Solutions Consulting that are expected to be sold should be classified as held for sale. The assets held for sale relate to separately identifiable intangible assets, including customer relationships and certain non-compete agreements that were acquired in connection with the Global Energy acquisition and specifically relate to Utility Solutions Consulting. Due to the fact that the Company has concluded that Utility Solutions Consulting meets the definition of a business in accordance with ASC 805, it has included in assets held for sale the goodwill of the Company’s All Other reporting unit which has been allocated to Utility Solutions Consulting, which is a component of this reporting unit. The amount of goodwill allocated to Utility Solutions Consulting was based on the relative fair values of this business and the portion of the reporting unit that will be retained. On April 16, 2014, the Company entered into an agreement with a third party to sell the Utility Solutions Consulting services line for up to $4,750 subject to satisfaction of certain conditions and representations. The transaction closed on May 30, 2014.

The following table summarizes the assets sold in connection with this transaction:

 

     June 30, 2014  

Customer relationship intangible assets, net

   $ 153  

Other definite-lived intangible assets, net

     39  

Goodwill

     489  
  

 

 

 

Total Assets Sold

     681  
  

 

 

 

 

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In accordance with the agreement, the Company received $4,275 at closing and $475 is being 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 were not assigned was $364 as of June 30, 2014 and the Company has deferred recognition of this portion of the purchase price as the Company has deemed this amount to be contingent upon the assignment of these contracts. As a result, the Company recognized a gain from the sale of Utility Solutions Consulting totaling $3,378, net of direct transaction costs and other expenses totaling $327. 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 has determined that the operations of Utility Solutions Consulting are 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 six month periods ended June 30, 2014 and 2013. As a result, the gain has been reflected as a separate component within loss from operations with the corresponding discrete tax charge of $1,450 related to the increase in 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 three month period ended June 30, 2014.

16. Gain on Sale of Assets

On April 22, 2014, the Company entered into an agreement with a third party who is a C&I customer of the Company to sell its remaining two contractual demand response capacity resources related to an open market demand response program to that third party allowing that third party the ability 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 in full. The aggregate payment of $5,740 was allocated between each demand response capacity 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 based on each resource’s relative fair value as determined by the potential future cash flows from each resource. As a mechanism to pay the consideration due for the purchase of these demand response capacity resources, the third party has agreed to allow the Company to withhold all payments that would be due and payable to this third party under its C&I contractual arrangements and in the event that the payments withheld through March 31, 2015 are not sufficient to cover the purchase price of these demand response capacity resources then the third party is required to pay the remaining amount in cash or otherwise would be in default under the agreement. Upon an event of default, the Company would retain ownership of any resource where the full purchase price had not been paid, as well as, retain $517 of fees received toward the purchase of that unpaid demand response capacity resource. The third party fully paid the purchase price for the first demand response capacity resource during the three month period ended June 30, 2014 and as a result, the sale of this resource was completed. As a result of the sale, the Company recognized a gain on the sale of this asset equal to the purchase price of $2,171 during the three month period ended June 30, 2014. In addition, the Company is recognizing the guaranteed fees of $517 ratably through the end of the potential contractual period of March 31, 2015 to the extent that sufficient cash has been received. During the three month period ended June 30, 2014, the Company has recognized $52 of these fees which is recorded in other income (expense), net in the accompanying consolidated statements of operations. As of June 30, 2014, the third party had not made sufficient payments related to the second demand capacity resource and therefore, the sale of this resource has not yet been completed and is not expected to be completed until 2015.

17. Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (FASB) issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (ASU 2014-08). ASU 2014-08 amends the definition of discontinued operations under ASC 205-20 to only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements. This guidance is effective for all disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. The Company has early adopted this guidance as of January 1, 2014. The adoption of this guidance had no impact on the Company’s consolidated financial statements.

 

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In May 2014, FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 provides guidance for revenue recognition and the standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The new guidance is effective for annual and interim periods beginning after December 15, 2016, with no early adoption permitted. Therefore, ASU No 2015-09 will be effective for the Company beginning in the first quarter of fiscal year 2018, and allows for full retrospective adoption applied to all periods presented or retrospective adoption with the cumulative effect of initially applying this update recognized at the date of initial application. The Company has not yet determined the method of adoption and is currently in the process of evaluating the impact of adoption of this ASU on its consolidated financial position and results of operations.

 

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion should be read in conjunction with our unaudited condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report on Form 10-Q, as well as our audited financial statements and notes thereto and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013, as filed with the Securities and Exchange Commission, or the SEC, on March 7, 2014, or our 2013 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 2013 Form 10-K and Quarterly Report for the quarterly period ended March 31, 2014 as filed with the SEC on May 9, 2014, or our 2013 First Quarter 10-Q. You should carefully review those factors and also carefully review the risks outlined in other documents that we file from time to time with the SEC.

Overview

We are a leading provider of energy intelligence software, or EIS, and related solutions. We unlock the full value of energy management for commercial, institutional and industrial end-users of energy, which we refer to as our C&I or enterprise customers, as well as our electric power grid operator and utility customers by delivering a comprehensive suite of demand-side management solutions. Our EIS and related solutions help our customers buy energy better, use less energy and be more strategic about when they consume energy in order to reduce overall energy spend and maximize productivity of that spend.

Our EIS and related solutions provide technology-enabled demand response, demand management, utility bill management, supply management, visibility and reporting, facility optimization, and project management applications and services for our enterprise, electric power grid operator and utility customers. Demand response is an alternative to traditional electric power generation and transmission infrastructure projects that enables electric power grid operators and utilities to reduce the likelihood of service disruptions, such as brownouts and blackouts, during periods of peak electricity demand, and otherwise manage the electric power grid during short-term imbalances of supply and demand or during periods when energy prices are high. Our solutions for utilities and grid operators include EnerNOC Demand Resource™, a turnkey demand response resource with a firm capacity commitment, and EnerNOC Demand Manager™, a Software-as-a-Service, or SaaS application that provides utilities and energy retailers with the underlying technology to manage their demand response programs and secure reliable demand-side resources. When we enter into an EnerNOC Demand Resource contract, we match obligation, in the form of megawatts, or MW, that we agree to deliver to our utility and electric power grid operator customers, with supply, in the form of MW that we are able to curtail from the electric power grid through our arrangements with our enterprise customers. When we are called upon by our utility or electric power grid operator customers to deliver our contracted capacity, we use our Network Operations Center, or NOC, to remotely manage and reduce electricity consumption across our growing network of enterprise customer sites, making demand response capacity available to electric power grid operators and utilities on demand while helping enterprise customers achieve energy savings, improve financial results and realize environmental benefits. We receive recurring payments from electric power grid operators and utilities for providing our EnerNOC Demand Resource and we share these recurring payments with our enterprise customers in exchange for those enterprise customers reducing their power consumption when called upon by us to do so. We occasionally reallocate and realign our capacity supply and obligation through open market bidding programs, supplemental demand response programs, auctions or other similar capacity arrangements and bilateral contracts to account for changes in supply and demand forecasts, as well as changes in programs and market rules in order to achieve more favorable pricing opportunities. We refer to the above activities as managing our portfolio of demand response capacity. Our EnerNOC Demand Manager product consists of long-term contracts with a utility customer for a SaaS solution that allows utilities to manage demand response capacity in utility-sponsored demand response programs. Our EnerNOC Demand Manager provides our utility customers with real-time load monitoring, dispatching applications, customizable reports, measurement and verification, and other professional services.

We build on our position as the world’s leading demand response provider by using our EIS to provide our enterprise customers with the ability to:

 

    manage energy supplier selection, procurement and implementation;

 

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    manage energy budget forecasting;

 

    manage utility bills and payment; and

 

    measure, track, analyze, report and manage greenhouse gas emissions.

Our EIS and related solutions provide our enterprise customers with the visibility they need to prioritize resources against the activities that will deliver the highest return on investment.

During the third quarter of year ended December 31, 2014, or fiscal 2014, we began to offer our EIS and related solutions at three subscription levels: basic, standard, and professional. We deliver our SaaS solutions on all of major Internet browsers and on leading mobile device operating systems. In addition to our EIS packages, we sell a data-driven energy efficiency suite of premium consulting and custom training services, including technology integration services, supply consulting, energy efficiency planning, audits, assessments, commissioning and retro-commissioning services, which are available for an hourly or fixed fee. Our target customers for our EIS and related solutions are enterprises that spend approximately $100,000/year per site or more on energy, and we sell to these customers primarily through our direct salesforce.

Since inception, our business has grown substantially. We began by providing our demand response solutions in one state in the United States in 2003 and have expanded to providing our EIS and related services in several regions throughout the United States, as well as internationally in Australia, Brazil, China, Germany, India, Ireland, Japan, New Zealand and the United Kingdom.

Significant Recent Developments

At our 2014 Annual Meeting of Stockholders held on May 29, 2014, our stockholders approved the EnerNOC, Inc. 2014 Long-Term Incentive Plan, or the 2014 Plan. The 2014 Plan provides for the grant of incentive stock options, non-statutory stock options, stock appreciation rights, restricted stock awards, restricted stock unit awards, other stock awards, and performance awards that may be settled in cash, stock, or other property.

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 is not utilized to either manage the business or make resource allocation decisions, and therefore 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 our operations and therefore, we believe the utilization of such data can provide insights into certain aspects of our business, such as market share and penetration and customer composition and depth.

The following table outlines certain non-financial business and operational data utilized as of June 30, 2014 and December 31, 2013 (amounts rounded to nearest hundred):

 

     June 30, 2014      December 31, 2013  

Utility Customers (1)

     46         36   

Grid Operator Customers (2)

     14         8   

C&I Customers Participating in Demand Response (3)

     6,100         5,800   

C&I Customer Sites Participating in Demand Response (3)

     15,000         13,900   

C&I Customers with Enterprise Revenue (4)

     1,000         600   

C&I Sites with Enterprise Revenue (4)

     33,300         2,800   

 

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(1) The term “Utility Customers” describes the number of our electric utility customers that have a contract with us for demand response or energy services. We enter into contractual commitments with certain of these utility customers through bilateral contractual arrangements for the express purpose of reducing load on their grid when called upon, or dispatched, to do so. For certain of these utility customers we provide energy efficiency and consulting services. This measure does not have any direct correlation to our financial performance but may provide observations as to the progress of our sales and marketing efforts aimed at utility customers and our ability to recruit and maintain such customers with a need to curtail demand for electricity
(2) The term “Grid Operator Customers” describes the number of our grid operator customers that have a contract with us and actively rely on our demand response programs to manage load on their grid. We enter into contractual commitments with these grid operator customers through participation in open market auctions, as well as, bilateral contractual arrangements for the express purpose of optimizing load on their grid when called upon, or dispatched, to do so. This measure does not have any direct correlation to our financial performance but may provide observations as to the progress of our sales and marketing efforts aimed at grid operator customers and our ability to recruit and maintain such customers with a need to curtail demand for electricity.
(3) The term “C&I Customers Participating in Demand Response” describes the number of our C&I customers under contract to actively participate in our demand response programs. By extension, the term “C&I Sites Participating in Demand Response” describes the number of sites across our C&I customer base under contract to actively participate in our demand response programs. Certain of these customers and sites may additionally use our EIS and related solutions to gain control of how and when they consume electricity. These two measures do not have any direct correlation to our financial performance but may provide observations as to the progress of our sales and marketing efforts and our ability to recruit and maintain customers with curtailable demand for electricity.
(4) The term “C&I Customers with Enterprise Revenue” describes the number of our C&I customers that separately purchase our EIS and related solutions to gain control of how and when they consume electricity. By extension, the term “C&I Sites with Enterprise Revenue” describes the number of sites across our C&I customer base that separately purchase our EIS and solutions. These two measures do not have any direct correlation to our financial performance but may provide observations as the progress of our sales and marketing efforts and our ability to recruit and maintain enterprise customers.

The number of utility customers that have contracts with us and actively rely on our demand response solutions or energy services at June 30, 2014 was 46 compared to 36 at December 31, 2013. The number of utility customers that have contracts with us and actively rely on our demand response solutions or energy services is one measure of the relative success that our utility selling team has in signing up new utility customers. We generally receive recurring cash payments from each utility customer actively relying on our demand response solutions in exchange for the capacity we commit to reduce for them. In addition, we receive additional cash payments in the form of energy payments from utility customers actively relying on our demand response solutions when we are actually called upon to reduce load and subsequently deliver on that commitment. The increase in the number of utility customers that have contracts with us and actively rely on our demand response solutions or energy services at June 30, 2014 as compared to December 31, 2013 primarily reflects the addition of new customers from our recent acquisitions of Entelios AG, or Entelios, and Activation Energy DSU Ltd, or Activation, as well as the addition of new customers that have contracts for our energy services. In general, we expect that the number of utility customers that have contracts with us and actively rely on our demand response solutions or energy services will increase over time.

The number of grid operator customers that have contracts with us and actively rely on our demand response solutions to reduce the load on their grid at June 30, 2014 was 14 compared to eight at December 31, 2013. The number of grid operator customers that have contracts with us and actively rely on our market development team has been increasing as we enter into new markets run by grid operators. We generally receive recurring cash payments from each grid operator customer in exchange for the capacity we commit to reduce for them. In addition, we receive additional cash payments in the form of energy payments from grid operator customers when we are actually called upon to reduce load and subsequently deliver on that commitment. The increase in the number of grid operator customers that have contracts with us and actively rely on our demand response solutions to reduce the load on their grid at June 30, 2014 as compared to December 31, 2013 primarily reflects the addition of new customers from our recent acquisitions of Entelios and Activation. In general, we expect that the number of grid operator customers that have contracts with us and actively rely on our demand response solutions to reduce the load on their grid will increase over time.

The number of C&I customers participating in demand response was approximately 6,100 at June 30, 2014 compared to 5,800 at December 31, 2013. The number of C&I customers participating in demand response is one measure of the relative success that our C&I selling team has in signing up new customers to whom we deliver recurring cash payments in exchange for the capacity they commit to make available in support of the commitments that we enter into with electric power grid operators and utilities. The number of C&I customer sites participating in demand response at June 30, 2014 was approximately 15,000 as compared to approximately 13,900 at December 31, 2013. In general, we expect that the number of C&I customers participating in demand

 

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response to increase or decrease in tandem with the number of C&I sites participating in demand response. Exceptions to this expected trend may occur if we are successful in further penetrating existing C&I customers so as to add additional sites without adding additional customers. The number of C&I customers participating in demand response programs and the number of C&I customer sites participating in demand response programs 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.

The number of C&I Customers with Enterprise Revenue that have deployed our EIS and related solutions at June 30, 2014 was approximately 1,000 compared to approximately 600 at December 31, 2013. This increase of approximately 400 reflects our acquisition of EnTech Utility Service Bureau, Inc. or Entech US, EnTech Utility Service Bureau Ltd. or Entech UK and EnTech USB Private Limited or Entech India, which we collectively refer to as Entech. The increase is also due to our increased 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, and the growing need for our solutions with enterprise customers who are increasingly turning to EIS and related solutions to make strategic decisions about the how and when they use energy. The number of C&I Sites with Enterprise Revenue that are under the management of our enterprise EIS and related solutions at June 30, 2014 was approximately 33,300 compared to approximately 2,800 at December 31, 2013. The number of C&I Sites with Enterprise Revenue that are under the management of our EIS and related solutions has increased in tandem with the increase in C&I Customers with Enterprise Revenue, with most of the increase coming from our acquisition of Entech. We expect that the number of C&I Customers with Enterprise Revenue and C&I Sites with Enterprise Revenue that use or are managed by our EIS and related solutions will continue to increase in the future as the market for these solutions continues to grow.

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 such data and information may change over time.

Revenues and Expense Components

Revenues

We derive recurring revenues from the sale of our EIS and related solutions. We do not recognize any revenues until persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and we deem collection to be reasonably assured. Our customers include grid operators, utilities and enterprises.

Our grid operator revenues and utility revenues primarily reflect the sale of our demand response solutions. The revenues primarily consist of capacity and energy payments, including ancillary services payments, as well as payments derived from the effective management of our portfolio, including our participation in capacity auctions and bilateral contracts and ongoing fixed fees for the overall management of utility-sponsored demand response programs. We derive revenues from our EnerNOC Demand Resource solution by making demand response capacity available in open market programs and pursuant to contracts that we enter into with electric power grid operators and utilities. In certain markets, we enter into contracts with electric power grid operators and utilities, generally ranging from three to ten years in duration, to deploy our EnerNOC Demand Resource solution. We refer to these contracts as utility contracts.

Where we operate in open market programs, our revenues from demand response capacity payments may vary month-to-month based upon our enrolled capacity and the market payment rate. Where we have a utility contract, we receive periodic capacity payments, which may vary monthly or seasonally based upon enrolled capacity and predetermined payment rates. Under both open market programs and utility contracts, we receive capacity payments regardless of whether we are called upon to reduce demand for electricity from the electric power grid; and we recognize revenue over the applicable delivery period, even when payments are made over a different period. We generally demonstrate our capacity either through a demand response event or a measurement and verification test. This demonstrated capacity is typically used to calculate the continuing periodic capacity payments to be made to us until the next demand response event or measurement and verification test establishes a new demonstrated capacity amount. In most cases, we also receive an additional payment for the amount of energy usage that we actually curtail from the grid during a demand response event. We refer to this as energy event revenues.

As program rules may differ for each open market program in which we participate and for each utility contract, we assess whether or not we have met the specific service requirements under the program rules and recognize or defer revenues related to our EnerNOC Demand Resource solution, as necessary. We recognize demand response capacity revenues when we have provided verification to the electric power grid operator or utility of our ability to deliver the committed capacity under the open market program or utility contract. Committed capacity is verified through the results of an actual demand response event or a measurement and verification test. Once the capacity amount has been verified, the revenues are recognized and future revenues become fixed or determinable and are recognized monthly over the performance period until the next demand response event or measurement and verification test. In subsequent demand response events or measurement and verification tests, if our verified capacity is below the

 

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previously verified amount, the electric power grid operator or utility customer will reduce future payments based on the adjusted verified capacity amounts. Under certain utility contracts and open market program participation rules, our performance and related fees are measured and determined over a period of time. If we can reliably estimate our performance for the applicable performance period, we will reserve the entire amount of estimated penalties that will be incurred, if any, as a result of estimated underperformance prior to the commencement of revenue recognition. If we are unable to reliably estimate the performance and any related penalties, we defer the recognition of revenues related to our EnerNOC Demand Resource solution until the fee is fixed or determinable. Any changes to our original estimates of net revenues are recognized as a change in accounting estimate in the earliest reporting period that such a change is determined.

We generally begin earning revenues from our MW within approximately one to three months from the date on which we enable the MW, or the date on which we can reduce the MW from the electricity grid if called upon to do so. The most significant exception is the PJM Interconnection, or PJM, forward capacity market, which is a market from which we derive a substantial portion of our revenues. Because the PJM summer-only open market program operates on a June to May program-year basis, a MW that we enable after June of each year may not begin earning revenue until June of the following year. Certain other markets in which we currently participate, such as the Western Australia market, or may choose to participate in the future, operate or may operate in a manner that could create a delay in recognizing revenue from the MW that we enable in those markets.

In the PJM summer-only open market program in which we participate, the program year operates on a June to May basis and performance is measured based on the aggregate performance during the months of June through September. As a result, fees received for the month of June could potentially be subject to adjustment or refund based on performance during the months of July through September. Based on changes to certain PJM program rules during the year ended December 31, 2012, we concluded that we no longer had the ability to reliably estimate the amount of fees potentially subject to adjustment or refund until the performance period ends on September 30 th of each year. Therefore, commencing in fiscal 2012, all demand response capacity revenues related to our participation in the PJM summer-only open market program are being recognized at the end of the performance period, or during the three month period ended September 30 th of each year. As a result of the fact that the period during which we are required to perform (June through September) is shorter than the period over which we receive payments under the program (June through May), a portion of the revenues that have been earned will be recorded and accrued as unbilled revenue.

Our revenues have historically been higher in the second and third quarters of our fiscal year due to seasonality related to the demand response market. We expect, based on the fact that we generally recognize substantially all of our demand response capacity revenue related to our participation in the PJM open market program and the Western Australia, or WA, demand response program governed by the Independent Market Organization, or IMO, which we refer to as the WA demand response program, during the three month period ended September 30 th of each year, that our revenues will typically be higher in the third quarter as compared to any other quarter in our fiscal year.

Demand response capacity revenues related to our participation in the WA demand response program are potentially subject to refund and therefore, are deferred until a portion of such capacity revenues are fixed which occurs upon an emergency event dispatch or until the end of the program period on September 30 th . Historically all capacity revenues have been recognized during the three month period ended September 30 th as there have previously been no emergency event dispatches. During the three month period ended June 30, 2014, there was an emergency event dispatch in this open market program and as a result, a portion of the capacity revenues were fixed and no longer subject to adjustment resulting in the recognition of $4.3 million of capacity revenues and $2.0 million of related cost of revenues.

The introduction in the PJM market of the extended-summer and annual demand response products beginning in the 2014/2015 delivery year could adversely impact our ability to successfully manage our portfolio of demand response capacity in that program and could negatively impact our results of operations and financial condition. For the 2014/2015 delivery year, we have no material capacity revenue related to the PJM extended-summer and annual demand response products.

Fees received from the reallocation or realignment of our capacity supply and obligation through auctions or other similar capacity arrangements and bilateral contracts are recognized as revenues as they become due and payable and are recorded as a component of DemandSMART revenues.

Under certain utility contracts and open market programs, such as PJM’s Emergency Load Response Program, the period during which we are required to perform may be shorter than the period over which we receive payments under that contract or program. In these cases, we record revenue, net of reserves for estimated penalties related to potential delivered capacity shortfalls, over the mandatory performance obligation period, and a portion of the revenues that have been earned is recorded and accrued as unbilled revenue. Due to the fact the demand response capacity revenues related to the PJM Emergency Load Response Program are not recognized until the three month period ended September 30 th of each year, there were no unbilled revenues related to this program as of June 30, 2014.

 

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Revenues generated from ISO New England, Inc., or ISO-NE, and IMO both accounted for 10% of our total revenues for the three month period ended June 30, 2014. Revenues from ISO-NE and IMO accounted for less than 10%, respectively, of our total revenues for the six month period ended June 30, 2014. Revenues generated from PJM accounted for less than 10% of our total revenues and approximately 22% of our total revenues for the three and six month periods ended June 30, 2014, respectively. Revenues generated from open market sales to ISO-NE accounted for approximately 13% and 14% of our total revenues for the three and six month periods ended June 30, 2013. Other than PJM, ISO-NE and IMO, no individual electric power grid operator or utility customer accounted for more than 10% of our total revenues for the three or six month periods ended June 30, 2014 and 2013. If we choose to participate in additional or different markets in the future, the contribution of our current electric power grid operator and utility customers to total revenues will change.

With respect to EnerNOC Demand Manager, we generally receive an ongoing fee for overall management of the utility demand response program based on enrolled capacity or enrolled C&I customers, which is not subject to adjustment based on performance during a demand response dispatch. We recognize revenues from these fees ratably over the applicable service delivery period commencing upon when the C&I customers have been enrolled and the contracted services have been delivered. In addition, under this offering, we may receive additional fees for program start-up, as well as, for C&I customer installations. We have determined that these fees do not have stand-alone value due to the fact that such services do not have value without the ongoing services related to the overall management of the utility demand response program and therefore, we recognize these fees over the estimated customer relationship period, which is generally the greater of three years or the contract period, commencing upon the enrollment of the C&I customers and delivery of the contracted services.

Our enterprise revenues reflect the sales of our EIS and related solutions to large C&I customers that seek to gain control of how and when they consume electricity. Enterprise revenue primarily reflects the sale of EIS applications and solutions and generally represents ongoing arrangements where the revenues are recognized ratably over the service period commencing upon delivery of the contracted solutions to the customer. Under certain of our arrangements, a portion of the fees received may be subject to adjustment or refund based on the validation of the energy savings delivered after the implementation is complete. As a result, we defer the portion of the fees that are subject to adjustment or refund until such time as the right of adjustment or refund lapses, which is generally upon completion and validation of the implementation. In addition, under certain of our other arrangements, in particular those arrangements entered into by our wholly-owned subsidiary, M2M Communications, or M2M, we sell proprietary equipment to customers that is utilized to provide the ongoing solutions that we deliver. Currently, this equipment has been determined to not have stand-alone value. As a result, we defer the fees associated with the equipment and begin recognizing those fees ratably over the expected customer relationship period (generally three years), once the customer is receiving from us the ongoing services. In addition, we capitalize the associated direct and incremental costs, which primarily represent the equipment and third-party installation costs, and recognize such costs over the expected customer relationship period.

Cost of Revenues

Cost of revenues for our demand response services primarily consists of amounts owed to our C&I customers for their participation in our demand response network and are generally recognized over the same performance period as the corresponding revenue. We enter into contracts with our C&I customers under which we deliver recurring cash payments to them for the capacity they commit to make available on demand. We also generally make an energy payment when a C&I customer reduces consumption of energy from the electric power grid during a demand response event. The equipment and installation costs for our devices located at our C&I customer sites, which monitor energy usage, communicate with C&I customer sites and, in certain instances, remotely control energy usage to achieve committed capacity, are capitalized and depreciated over the lesser of the remaining estimated customer relationship period or the estimated useful life of the equipment, and this depreciation is reflected in cost of revenues. We also include in cost of revenues our amortization of acquired developed technology, amortization of capitalized internal-use software costs related to our EIS and related solutions, the monthly telecommunications and data costs we incur as a result of being connected to C&I customer sites, services and products, third-party services, equipment costs, equipment depreciation, our internal payroll and related costs allocated to a C&I customer site and our internal payroll, the wages and associated benefits that we pay to our project managers for the performance of their services, and related costs of related to the delivery of services of our utility bill management solution, which we acquired in our acquisition of Entech. Certain costs, such as equipment depreciation and telecommunications and data costs, are fixed and do not vary based on revenues recognized. These fixed costs could impact our gross margin trends during interim periods as described elsewhere in this Quarterly Report on Form 10-Q.

We defer incremental direct costs related to the acquisition or origination of a utility contract or open market program in a transaction that results in the deferral or delay of revenue recognition. As of June 30, 2014 and December 31, 2013, we had no deferred incremental direct costs related to the acquisition or origination of a utility contract or open market program and during the

 

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three and six month periods ended June 30, 2014 and 2013, no contract origination costs were deferred. In addition, we defer incremental direct costs incurred related to customer contracts where the associated revenues have been deferred as long as the deferred incremental direct costs are deemed realizable. During the three month periods ended June 30, 2014 and 2013, we deferred $28.6 million and $10.9 million, respectively, of incremental direct costs associated with customer contracts. During the six month periods ended June 30, 2014 and 2013, we deferred $36.5 million and $17.2 million, respectively, of incremental direct costs associated with customer contracts. These deferred expenses will be expensed in proportion to the related revenue being recognized. During the three month periods ended June 30, 2014 and 2013, we expensed $0.9 million and $1.4 million, respectively, of deferred incremental direct costs to cost of revenues. During the six month periods ended June 30, 2014 and 2013, we expensed $2.2 million and $2.5 million, respectively, of deferred incremental direct costs to cost of revenues. As of June 30, 2014, there were no material realizability issues related to deferred incremental direct costs. We also capitalize the costs of our production and generation equipment utilized in the delivery of our demand response services and expense this equipment over the lesser of its estimated useful life or the term of the contractual arrangement. During the three month periods ended June 30, 2014 and 2013, we capitalized $3.5 million and $5.2 million, respectively, of production and generation equipment costs. During the six month periods ended June 30, 2014 and 2013, we capitalized $5.3 million and $7.6 million, respectively, of production and generation equipment costs. We believe that the above accounting treatments appropriately match expenses with the associated revenues.

Gross Profit and Gross Margin

Gross profit consists of our total revenues less our cost of revenues. Our gross profit has been, and will continue to be, affected by many factors, including (a) the demand for our energy management applications, services and products, (b) the selling price of our energy management applications, services and products, (c) our cost of revenues, (d) the way in which we manage, or are permitted to manage by the relevant electric power grid operator or utility, our portfolio of demand response capacity, (e) the introduction of new energy management applications, services and products, (f) our demand response event performance and (g) our ability to open and enter new markets and regions and expand deeper into markets we already serve. The effective management of our portfolio of demand response capacity, including our outcomes in negotiating favorable contracts with our customers and our participation in capacity auctions and bilateral contracts, and our demand response event performance, are the primary determinants of our gross profit and gross margin.

Operating Expenses

Operating expenses consist of selling and marketing, general and administrative, and research and development expenses. Personnel-related costs are the most significant component of each of these expense categories. We grew from 744 full-time employees at June 30, 2013 to 991 full-time employees at June 30, 2014 primarily as a result of our overall growth and expansion into new markets over the past year. As noted above under “Cost of Revenues”, a portion of our headcount and associated payroll and related expenses are included within cost of revenues. We expect to continue to hire employees to support our growth for the foreseeable future. In addition, we incur significant up-front costs associated with the expansion of the number of contractual MW, which we expect to continue for the foreseeable future. We expect our overall operating expenses to increase marginally in absolute dollar terms for the foreseeable future as we continue to enable new C&I customer sites and expand the development of our energy management applications, services and products. In addition, possible future acquisitions and associated amortization expense of intangible assets acquired could potentially increase our operating expenses in future periods.

Selling and Marketing

Selling and marketing expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our sales and marketing organization, (b) commissions, (c) travel and other out-of-pocket expenses, (d) marketing programs such as trade shows and (e) other related overhead. Commissions are recorded as an expense when earned by the employee. We expect an increase in selling and marketing expenses in absolute dollar terms through at least the end of fiscal 2014 as we invest in infrastructure to support our continued growth; however, we expect that selling and marketing expenses as a percentage of revenues will be consistent with the year ended December, 31, 2013, or fiscal 2013, primarily due to the additional expenses that result from our recently completed acquisitions and ongoing market expansion.

General and Administrative

General and administrative expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards and bonuses, related to our executive, finance, human resource, information technology and operations organizations, (b) facilities expenses, (c) accounting and legal professional fees, (d) depreciation and amortization and (e) other related overhead. We expect an increase in general and administrative expenses in absolute dollar terms through at least the end of fiscal 2014 as we invest in infrastructure to support our continued growth; however, we expect that general and administrative expenses as a percentage of revenues will be consistent with fiscal 2013 primarily due to the additional expenses that result from our recently completed acquisitions and ongoing market expansion.

 

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Research and Development

Research and development expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our research and development organization, (b) payments to suppliers for design and consulting services, (c) costs relating to the design and development of new energy management applications, solutions and products and enhancement of existing energy management applications, solutions and products, (d) quality assurance and testing and (e) other related overhead. During the three and six month periods ended June 30, 2014, we capitalized software development costs, including software license fees and external consulting costs, of $1.7 million and $3.1 million, respectively. During the three and six month periods ended June 30, 2013, we capitalized software development costs, including software license fees and external consulting costs, of $1.7 million and $4.3 million, respectively, which are included as software in property and equipment at June 30, 2014. We expect an increase in research and development expenses in absolute dollar terms through at least the end of fiscal 2014 as we develop new technologies and enhance our existing technologies to support our continued growth; however, we expect that research and development expenses as a percentage of revenues will be consistent with fiscal 2013 primarily due to the additional expenses that result from our recently completed acquisitions and ongoing market expansion.

Stock-Based Compensation

We account for stock-based compensation in accordance with Accounting Standards Codification, or ASC, 718 Stock Compensation (ASC 718). As such, all share-based payments to employees, including grants of stock options, restricted stock and restricted stock units, are recognized in the statement of operations based on their fair values as of the date of grant.

During the six month period ended June 30, 2014, we granted 388,034 shares of non-vested restricted stock to certain executives that contain performance-based vesting conditions. Of these shares, 25% vest in 2015 if the performance criteria related to certain 2014 operating results are achieved and the executive is still employed as of the vesting date and the remaining 75% of the shares vest quarterly over a three year period thereafter as long as the executive is still employed as of the vesting date. If the performance criteria related to certain 2014 operating results are not achieved, 100% of the shares are forfeited.

During the three month period ended June 30, 2014, we 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 our acquisition of Entelios. Of these shares, up to 10% vest in 2015 if the performance criteria related to certain 2014 operating results are achieved and the employee is still employed as of the vesting date, up to 20% vest in 2016 if the performance criteria related to certain 2015 operating results are achieved and the employee is still employed as of the vesting date, and up to the remaining 70% of the shares vest in 2017 if the performance criteria related to certain 2016 operating results are achieved and the employee is still employed as of the vesting date. If the performance criteria related to certain 2014, 2015 and 2016 operating results are not achieved, 100% of the shares are forfeited. As of June 30, the awards have not been deemed probable of vesting.

As a result of these grants of non-vested restricted stock and restricted stock units, additional stock grants related to our expanding employee base and the overall increase in our stock price, we anticipate that, on a per employee basis, stock-based compensation expense will increase for the year ending December 31, 2014 as compared to the year ended December 31, 2013.

For the three month periods ended June 30, 2014 and 2013, we recorded expenses of approximately $3.8 million and $3.3 million, respectively, in connection with share-based payment awards to employees and non-employees. For both the six month periods ended June 30, 2014 and 2013, we recorded expense of approximately $8.0 million in connection with share-based payment awards to employees and non-employees. With respect to stock option grants through June 30, 2014, a future expense of non-vested stock options of approximately $0.1 million is expected to be recognized over a weighted average period of 1.5 years. For non-vested restricted stock subject to service-based vesting conditions outstanding as of June 30, 2014, we had $20.9 million of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 3.0 years. For non-vested restricted stock subject to performance-based vesting conditions outstanding that were probable of vesting as of June 30, 2014, we had $8.7 million of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 1.9 years. As of June 30, 2014, we had no non-vested restricted stock units that were subject to service-based vesting conditions outstanding and had no non-vested restricted stock units subject to performance-based vesting conditions that were probable of vesting. For non-vested restricted stock units subject to outstanding performance-based vesting conditions that were not probable of vesting at June 30, 2014, we had $5.0 million of unrecognized stock-based compensation expense. If and when any additional portion of these non-vested restricted stock units are deemed probable to vest, we will reflect the effect of the change in estimate in the period of change by recording a cumulative catch-up adjustment to retroactively apply the new estimate.

 

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Interest Expense and Other Income (Expense), Net

In March 2012, we entered into a $50.0 million credit facility with Silicon Valley Bank, or SVB, which was subsequently amended in June 2012 and April 2013, which we refer to as the 2012 credit facility. In April 2013, we entered into a $70.0 million senior secured revolving credit facility with the several lenders from time to time party thereto and SVB, as administrative agent, swingline lender, issuing lender, lead arranger and book manager, which was subsequently amended in August 2013, December 2013 and January 2014, which we refer to as the 2013 credit facility. The 2013 credit facility replaced the 2012 credit facility. Interest expense primarily consists of fees associated with the 2012 credit facility and the 2013 credit facility. Interest expense also consists of fees associated with issuing letters of credit and other financial assurances. Other income and expense consist primarily of gains or losses on transactions denominated in currencies other than our or our subsidiaries’ functional currency, interest income earned on cash balances, and other non-operating income and expense.

Consolidated Results of Operations

Three and Six Month Periods Ended June 30, 2014 Compared to the Three and Six Month Periods Ended June 30, 2013

Revenues

The following table summarizes our revenues for the three and six month periods ended June 30, 2014 and 2013 (dollars in thousands):

 

     Three Months Ended June 30,      Dollar     Percentage  
     2014      2013      Change     Change  

Revenues:

          

Grid operator

   $ 22,974      $ 15,080      $ 7,894       52.3

Utility

     11,961        13,397        (1,436     (10.7 )% 

Enterprise

     9,120        7,676        1,444       18.8
  

 

 

    

 

 

    

 

 

   

Total

   $ 44,055      $ 36,153      $ 7,902       21.9
  

 

 

    

 

 

    

 

 

   
     Six Months Ended June 30,      Dollar     Percentage  
     2014      2013      Change     Change  

Revenues:

          

Grid operator

   $ 58,744      $ 30,143      $ 28,601       94.9

Utility

     22,270        25,166        (2,896     (11.5 )% 

Enterprise

     15,549        13,694        1,855       13.5
  

 

 

    

 

 

    

 

 

   

Total

   $ 96,563      $ 69,003      $ 27,560       39.9
  

 

 

    

 

 

    

 

 

   

For the three month period ended June 30, 2014, our revenues from grid operators increased by $7.9 million, or 52.3% as compared to the three month period ended June 30, 2013. For the six month period ended June 30, 2014, our revenues from grid operators increased by $28.6 million, or 94.9% as compared to the six month period ended June 30, 2013. The increase in our revenues from grid operators was primarily attributable to changes in the following operating areas (dollars in thousands):

 

     Increase  
     Three Months Ended
June 30, 2013 to
June 30, 2014
     Six Months Ended
June 30, 2013 to
June 30, 2014
 

Western Australia

   $ 4,397        4,397  

PJM

     1,942        19,336  

Alberta, Canada

     1,256        2,926  

Other (1)

     299        1,942  
  

 

 

    

 

 

 

Total increased grid operator revenues

   $ 7,894        28,601  
  

 

 

    

 

 

 

 

(1) The amounts included in this category relate to various demand response programs, none of which are individually material.

 

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The increase in revenues from grid operators during the three and six month periods ended June 30, 2014 as compared to the same periods in 2013 was due to the recognition of $4.3 million of deferred revenues related to the Western Australia demand response program as a result of these fees becoming fixed upon an emergency event dispatch during the three month period ended June 30, 2014. We had no emergency event dispatches in Western Australia during the three and six month periods ended June 30, 2013 and as a result, all revenues under this program were deferred and recognized at the end of that program year or September 30 th . The increase in revenues from grid operators during the three and six month periods ended June 30, 2014 as compared to the same periods in 2013 was also due to an increase in PJM energy revenues that resulted from a significant number of demand response event dispatches and overall MW dispatched as compared to the same periods in 2013. The increase in revenues from grid operators during the three and six month periods ended June 30, 2014 as compared to the same periods in 2013 was also a result of revenues recognized from our participation in certain demand response programs in Alberta, Canada, including ancillary demand responses programs that we did not start participating in until the three month period ended September 30, 2013 and an increase in enrolled MW in these programs. Additionally, this increase was also attributable to an increase in our MW delivery for other demand response programs and more favorable pricing, and revenues recognized from our acquisition of Activation, which occurred during the three month period ended March 31, 2014.

For the three month period ended June 30, 2014, our revenues from utilities decreased by $1.4 million, or 10.7% as compared to the three month period ended June 30, 2013. For the six month period ended June 30, 2014, our revenues from utilities decreased by $2.9 million, or 11.5% as compared to the six month period ended June 30, 2013. The decrease in our revenues from utilities was primarily attributable to changes in the following operating areas (dollars in thousands):

 

     Increase (Decrease)  
     Three Months Ended
June 30, 2013 to
June 30, 2014
    Six Months Ended
June 30, 2013 to
June 30, 2014
 

Southern California Edison (SCE)

   $ (1,213     (1,240

Tennessee Valley Authority (TVA)

     (525     (1,039

Pacific Gas and Electric (PG&E)

     731       1,133  

National Electricity Market (NEM) - Australia

     102       (907

Other (1)

     (531     (843
  

 

 

   

 

 

 

Total decreased utility revenues

   $ (1,436     (2,896
  

 

 

   

 

 

 

 

(1) The amounts included in this category relate to various demand response programs, none of which are individually material.

The decrease in revenues from utilities during the three and six month periods ended June 30, 2014 as compared to the same periods in 2013 was primarily due to a decrease in revenues from SCE and Xcel as a result of a temporary decrease in enrolled MW due to underperformance during demand response events during the three month period ended June 30, 2014. The decrease in revenues from utilities during the six month period ended June 30, 2014 was also attributable to our NEM demand response programs in Australia, largely due to a certain program which ended during the three month period ended June 30, 2013 and was not renewed. The decreases in revenues from utilities for the three and six month periods ended June 30, 2014 as compared to the same periods in 2013 were partially offset by an increase in revenues from PG&E, as demand response revenues related to this program were deferred in the comparable periods in 2013.

For the three and six month periods ended June 30, 2014, our revenues from enterprise customers increased by $1.4 million and $1.9 million, respectively, or 18.8% and 13.5%, respectively, as compared to the same periods in 2013. The increase in revenues from enterprise customers was primarily due to revenues recognized during the three month period ended June 30, 2014 related to our utility bill management services, which were acquired as part of our acquisition of Entech, as well as, an increase in both the number of enterprise customers and overall consulting engagements.

 

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Gross Profit and Gross Margin

The following table summarizes our gross profit and gross margin percentages for our energy management applications, solutions and products for the three and six month periods ended June 30, 2014 and 2013 (dollars in thousands):

 

Three Months Ended June 30,  
2014     2013  
Gross Profit     Gross Margin     Gross Profit     Gross Margin  
$ 16,253       36.9   $ 12,280       34.0

 

 

     

 

 

   
Six Months Ended June 30,  
2014     2013  
Gross Profit     Gross Margin     Gross Profit     Gross Margin  
$ 32,622       33.8   $ 22,933       33.2

 

 

     

 

 

   

The increase in gross profit during the three and six month periods ended June 30, 2014 as compared to the same periods in 2013 was due to the recognition of $4.3 million of deferred revenues related to the Western Australia demand response program as a result of these fees becoming fixed upon an emergency event dispatch during the three month period ended June 30, 2014 partially offset by the expensing of the corresponding portion of capitalized incremental direct customer contract costs totalling $2.0 million. The increase in gross profit for the three and six month periods ended June 30, 2014 as compared to the same periods in 2013 was also due to the increase in PJM demand response energy event revenues that resulted from a significant number of demand response event dispatches and overall MW dispatched as compared to the same periods in 2013. In addition, the increase in gross profits for the three and six month periods ended June 30, 2014 as compared to the same periods in 2013 was due to an increase in enrolled MW during the three and six month periods ended June 30, 2014 in an ancillary demand response program in which we participate in PJM as compared to the same periods in 2013. The increase in gross profit for the three and six month periods ended June 30, 2014 as compared to the same periods in 2013 was also due to an increase in revenues resulting from increased participation in our international demand response programs in Alberta, Canada. Additionally, this increase in gross profit for the three and six month period ended June 30, 2014 was also attributable to an increase in revenues from our New York ISO demand response program as a result of an increase in our MW delivery and more favorable pricing, as well as revenues recognized from our acquisition of Activation during the three and six month periods ended June 30, 2014. The increase in gross profit during the three and six month periods ended June 30, 2014 compared to the same periods in 2013 was partially offset by a decrease in revenues from utilities due to a decrease in revenues from a demand response program in Australia that ended during the three month period ended June 30, 2013 and was not renewed, as well as, a decrease in revenues during the three and six month periods ended June 30, 2014 from our demand response programs in California due to a decrease in event performance in these programs as compared to the same periods in 2013.

Our gross margin increased during the three and six month periods ended June 30, 2014, as compared to the same periods in 2013, primarily due to the increase in revenues related to our participation in international demand response programs, which are typically higher margin demand response programs, improved management of our portfolio of demand response capacity in certain programs and lower installed costs associated with our C&I contracts. The increase in our gross margin for the six month period ended June 30, 2014 as compared to the same period in 2013 was partially offset by a significant increase in PJM energy event revenues which historically yield a lower gross margin.

We continue to expect our gross margins for the year ending December 31, 2014, or fiscal 2014, to return to more historic levels in the mid 40% range. The expected decrease in gross margin compared to fiscal 2013 is expected to result primarily from continued changes in fiscal 2014 in the management of our portfolio of demand response capacity in the PJM demand response program, including an expected decrease in the percentage of higher margin revenues recognized as a result of the adjustment of our zonal capacity obligations through our participation in the PJM incremental auctions and bilateral contracts. In addition, this expected decrease in gross margin in fiscal 2014 as compared to fiscal 2013 is expected to result from an increase in lower margin energy revenues resulting from a potential increase in both the number of demand response event dispatches and number of MW expected to be dispatched in fiscal 2014 as compared to fiscal 2013 based on current trends. This decrease will be partially offset by an expected increase in gross margins associated with an increase in revenues from enterprise customers.

 

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Operating Expenses and Income

The following table summarizes our operating expenses and income for the three and six month periods ended June 30, 2014 and 2013 (dollars in thousands):

 

     Three Months Ended June 30,      Percentage  
     2014     2013      Change  

Operating expenses and income:

       

Selling and marketing

   $ 19,526     $ 19,030        2.6

General and administrative

     24,191       21,005        15.2

Research and development

     4,997       4,770        4.8

Gain on sale of service line

     (3,378     —          N/A   

Gain on sale of assets

     (2,171     —          N/A   
  

 

 

   

 

 

    

Total

   $ 43,165     $ 44,805        (3.7 )% 
  

 

 

   

 

 

    
     Six Months Ended June 30,      Percentage  
     2014     2013      Change  

Operating expenses and income:

       

Selling and marketing

   $ 38,025     $ 34,683        9.6

General and administrative

     47,868       41,126        16.4

Research and development

     10,172       9,590        6.1

Gain on sale of service line

     (3,378     —          N/A   

Gain on sale of assets

     (2,171     —          N/A   
  

 

 

   

 

 

    

Total

   $ 90,516     $ 85,399        6.0
  

 

 

   

 

 

    

In certain forward capacity markets in which we participate, such as PJM, we may install our equipment at a C&I customer site to allow for the curtailment of MW from the electric power grid, which we refer to as enablement, up to twelve months in advance of enrolling the C&I customer in a particular program. As a result, there has been a trend of incurring operating expenses at the time of enablement, including salaries and related personnel costs, associated with enabling certain of our C&I customers in advance of recognizing the corresponding revenues.

Selling and Marketing Expenses

 

     Three Months Ended June 30,      Percentage  
     2014      2013      Change  

Payroll and related costs

   $ 12,311      $ 12,000        2.6

Stock-based compensation

     1,372        1,456        (5.8 )% 

Other

     5,843        5,574        4.8
  

 

 

    

 

 

    

Total

   $ 19,526      $ 19,030        2.6
  

 

 

    

 

 

    
     Six Months Ended June 30,      Percentage  
     2014      2013      Change  

Payroll and related costs

   $ 24,418      $ 21,598        13.1

Stock-based compensation

     2,565        2,846        (9.9 )% 

Other

     11,042        10,239        7.8
  

 

 

    

 

 

    

Total

   $ 38,025      $ 34,683        9.6
  

 

 

    

 

 

    

Payroll and other employee related costs for the three month period ended June 30, 2014 compared to the same period in 2013 were essentially unchanged and increased approximately 13.1% for the six month period ended June 30, 2014 compared to the same period in 2013. This change was primarily due to an increase in the number of selling and marketing full-time employees from 235 at

 

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June 30, 2013 to 263 at June 30, 2014, most of which arose from the acquisitions that we completed during the quarter ended June 30, 2014. Payroll and other employee related costs were also impacted by higher bonus expense for the three and six month periods ended June 30, 2014, as a portion of the fiscal 2013 bonuses were settled in shares of our common stock and therefore recorded in stock-based compensation expense during fiscal 2013. These increases in payroll and other employee related costs for the three month period ended June 30, 2014 were largely offset by a decrease in commissions, and were offset to a lesser extent for the six month period ended June 30, 2014.

The decrease in stock-based compensation for the three and six month periods ended June 30, 2014 compared to the same periods in 2013 primarily resulted from the settlement of a portion of the fiscal 2013 bonuses in shares of our common stock and therefore recorded in stock-based compensation expense. This decrease was partially offset by an increase in the grant date fair value of stock-based awards granted subsequent to June 30, 2013.

The increase in other selling and marketing expenses for the three and six month periods ended June 30, 2014 as compared to the same periods in 2013 was primarily due to higher professional fees and related costs of $0.1 million and $0.3 million, respectively, higher amortization expense associated with acquired intangible assets of $0.3 million and $0.2 million, respectively, and higher costs incurred for a variety of marketing initiatives of $0.2 million and $0.6 million, respectively. These increases in other selling and marketing expenses for the three and six month periods ended June 30, 2014 as compared to the same periods in 2013 were partially offset by decreases of $0.1 million and $0.1 million, respectively, in the allocation of company-wide overhead costs, decreases in software license fees of $0.1 million and $0.1 million, respectively, and a decrease in training costs of $0.1 million and $0.1 million, respectively.

General and Administrative Expenses

 

     Three Months Ended June 30,      Percentage  
     2014      2013      Change  

Payroll and related costs

   $ 13,639      $ 11,946        14.2

Stock-based compensation

     2,108        1,520        38.7

Other

     8,444        7,539        12.0
  

 

 

    

 

 

    

Total

   $ 24,191      $ 21,005        15.2
  

 

 

    

 

 

    
     Six Months Ended June 30,      Percentage  
     2014      2013      Change  

Payroll and related costs

   $ 27,085      $ 22,988        17.8

Stock-based compensation

     4,804        4,472        7.4

Other

     15,979        13,666        16.9
  

 

 

    

 

 

    

Total

   $ 47,868      $ 41,126        16.4
  

 

 

    

 

 

    

The increase in payroll and related costs for the three and six month periods ended June 30, 2014 compared to the same periods in 2013 was primarily attributable to an increase in the number of general and administrative full-time employees from 404 at June 30, 2013 to 418 at June 30, 2014, most of which arose from the acquisitions that we completed during the quarter ended June 30, 2014 and, to a lesser extent, increases in overall salary rates and expected bonuses per full-time employee. In addition, the increase in payroll and related costs is due to the recognition of higher bonus expense during the three and six month periods ended June 30, 2014, as a portion of the fiscal 2013 bonuses were settled in shares of our common stock and therefore recorded in stock-based compensation expense.

The increase in stock-based compensation expense for the three month period ended June 30, 2014 compared to the same period in 2013 was primarily due to an increase in the number of stock based awards granted, as well as, an increase in the grant date fair value of stock-based awards granted subsequent to June 30, 2013 as a result of the increase in our stock price. The increase was also due to the reversal of stock-based compensation expense during the three month period ended June 30, 2013 related to the forfeiture upon the termination of employment of our former Executive Vice President of stock-based awards that were granted to him. There was no similar material reversal of stock-based compensation expense during the three month period ended June 30, 2014. This increase was partially offset by a greater percentage of stock-based compensation expense being recognized in fiscal 2013 as compared to 2014 related to fiscal 2013 bonuses, as a portion of these bonuses were settled in shares of our common stock and therefore recorded in stock-based compensation expense.

 

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The increase in stock-based compensation expense for the six month period ended June 30, 2014 compared to the same period in 2013 was primarily due an increase in the number of stock based awards granted, as well as, an increase in the grant date fair value of stock-based awards granted subsequent to June 30, 2013 as a result of the increase in our stock price, which includes fully-vested awards that were granted to our board of directors during the six month period ended June 30, 2014. This increase was partially offset by a greater percentage of stock-based compensation expense being recognized in fiscal 2013 as compared to 2014 related to fiscal 2013 bonuses, as a portion of these bonuses were settled in shares of our common stock and therefore recorded in stock-based compensation expense.

The increase in other general and administrative expenses for the three month period ended June 30, 2014 compared to the same period in 2013 was primarily attributable to higher professional fees of $1.0 million due to higher accounting, consulting and legal fees incurred as a result of our recent acquisitions and other matters, including the ongoing derivative and class action complaint, higher software license fees of $0.1 million primarily driven by our increase in headcount, and higher depreciation expense of $0.1 million as a result of the capital expenditures we incurred to build-out the new lease for our principal executive offices. The increase in other general and administrative expenses for the three month period ended June 30, 2014 compared to the same period in 2013 was partially offset by a $0.3 million decrease in facilities expenses, primarily due to lower rent expense, as during the three month period ended June 30, 2013 we incurred rent expense for both our prior and current principal executive offices.

The increase in other general and administrative expenses for the six month period ended June 30, 2014 compared to the same period in 2013 was primarily attributable to higher professional fees of $2.4 million due to the increased accounting, consulting and legal fees incurred related to our recent acquisitions and other matters, including the ongoing derivative and class action complaint, and $0.7 million of higher software license fees which was partially the result of our increase in headcount. This increase was also attributable to higher depreciation expense of $0.6 million due to the capital expenditures we incurred to build-out the new lease for our principal executive offices. The increase in other general and administrative expenses for the six month period ended June 30, 2014 compared to the same period in 2013 was partially offset by a $1.1 million decrease in facilities expenses, primarily due to lower rent expense, as during the six month period ended June 30, 2013 we incurred rent expense for both our prior and current principal executive offices and $0.3 million of lower information technology costs.

Research and Development Expenses

 

     Three Months Ended June 30,      Percentage  
     2014      2013      Change  

Payroll and related costs

   $ 3,056      $ 2,607        17.2

Stock-based compensation

     319        331        (3.6 )% 

Other

     1,622        1,832        (11.5 )% 
  

 

 

    

 

 

    

Total

   $ 4,997      $ 4,770        4.8
  

 

 

    

 

 

    
     Six Months Ended June 30,      Percentage  
     2014      2013      Change  

Payroll and related costs

   $ 6,206      $ 5,074        22.3

Stock-based compensation

     657        693        (5.2 )% 

Other

     3,309        3,823        (13.4 )% 
  

 

 

    

 

 

    

Total

   $ 10,172      $ 9,590        6.1
  

 

 

    

 

 

    

The increase in payroll and other employee related costs for the three and six month periods ended June 30, 2014 compared to the same periods in 2013 was primarily driven by an increase in the number of research and development full-time employees from 105 at June 30, 2013 to 143 at June 30, 2014, a portion of which resulted from the acquisitions that we completed during the quarter ended June 30, 2014, as well as an increase in salary rates per full-time employee. The increase in payroll and other employee related costs for the six month period ended June 30, 2014 compared to the same period in 2013 was also attributable to a portion of the fiscal 2013 bonuses that were settled in shares of our common stock and therefore recorded in stock-based compensation expense. These increases were partially offset by an increase in capitalized application development costs related to our energy intelligence software.

The decrease in stock-based compensation expense for the three and six month periods ended June 30, 2014 as compared to the same periods in 2013 primarily resulted from a greater percentage of stock-based compensation expense being recognized in fiscal

 

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2013 as compared to 2014 as a result of a portion of the fiscal 2013 bonuses being settled in shares of our common stock and therefore recorded in stock-based compensation expense. The decrease in stock-based compensation expense for the three and six month periods ended June 30, 2014 was partially offset by an increase in the grant date fair value of stock-based awards granted subsequent to June 30, 2013 due to the increase in our stock price.

The decrease in other research and development expenses for the three month period ended June 30, 2014 compared to the same period in 2013 was primarily due to a decrease in the allocation of company-wide overhead costs of $0.1 million and a decrease in software license fees used in the development of our energy management application services and products of $0.1 million.

The decrease in other research and development expenses or the six month period ended June 30, 2014 compared to the same period in 2013 was primarily attributable to decreases of $0.4 million and $0.3 million, respectively, in professional fees and temporary labor, and software licenses and fees used in the development of our energy management application services and products. The decrease in other research and development expenses for the six month period ended June 30, 2014 compared to the same period in 2013 was partially offset by a $0.2 million increase in technology expenses primarily due to data storage.

Gain on Sale of Service Line

During the three month period ended June 30, 2014, we completed the sale of our business related to providing consulting services to utilities, which we acquired in connection with our acquisition of Global Energy Partners, Inc. in January 2011, or Utility Solutions Consulting. The total sales price was $4.8 million and we sold net assets with a carrying value of $0.7 million in connection with this sale.

In accordance with the agreement, we received $4.3 million at closing and $0.5 million is being 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 were not assigned is $0.4 million as of June 30, 2014 and we have deferred recognition of this portion of the purchase price as we have deemed this amount to be contingent upon the assignment of these contracts. As a result, we recognized a gain from the sale of Utility Solutions Consulting totaling $3.4 million, net of direct transaction costs and other expenses totaling $0.3 million. The gain has been reflected as a separate component within loss from operations with the corresponding discrete tax charge of $1.5 million related to the increase in deferred tax liability as a result of the increased book and tax basis difference in goodwill being recorded as a component of our provision for income taxes during the three month period ended June 30, 2014.

Gain on Sale of Assets

During the three month period ended June 30, 2014, we entered into an agreement with a third party who is a C&I customer to sell our remaining 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. Under the terms of the agreement, we 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 in full. The aggregate payment of $5.7 million was allocated between each demand response capacity resource with $2.2 million being allocated to the first demand response capacity resource and $3.5 million being allocated to the second demand response capacity resource based on each resource’s relative fair value as determined by the potential future cash flows from each resource. As a mechanism to pay the consideration due for the purchase of these demand response capacity resources, the third party has agreed to allow us to withhold all payments that would be due and payable to this third party under its C&I contractual arrangements and in the event that the payments withheld through March 31, 2015 are not sufficient to cover the purchase price of these demand response capacity resources then the third party is required to pay the remaining amount in cash or otherwise would be in default under the agreement. Upon an event of default, we would retain ownership of any resource where the full purchase price had not been paid, as well as, retain $0.5 million of fees received toward the purchase of that unpaid demand response capacity resource. The third party had fully paid the purchase price for the first demand response capacity resource during the three month period ended June 30, 2014 and as a result, the sale of this resource was completed resulting in the recognition a gain on the sale of this asset equal to the purchase price of $2.2 million. As of June 30, 2014, the third party had not made sufficient payments related to the second demand capacity resource and therefore, the sale of this resource has not yet been completed and is not expected to be completed until 2015.

Interest Expense and Other Income (Expense), Net

Interest expense for the three month period ended June 30, 2014 increased by $0.2 million or 34.6% compared to the same period in 2013 and interest expense for the six month period ended June 30, 2014 increased by $0.3 million or 38.4% compared to the

 

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same period in 2013. The increase in interest expense for the three and six months period ended June 30, 2014 compared to the same periods in 2013 was due to increased amortization of deferred financing costs that resulted from our 2013 credit facility, as well as, a higher average outstanding letter of credit balance.

Other income (expense), net for the three month period ended June 30, 2014 was $0.4 million compared to ($1.2) million for the three month period ended June 30, 2013. Other income (expense), net for the six month period ended June 30, 2014 was $0.9 million compared to ($1.1) million for the six month period ended June 30, 2013. Other income (expense), net was comprised primarily of net foreign currency gains (losses) due to fluctuations in the Australian dollar, British Pound and Euro and a nominal amount of other income. Foreign currency exchange gains (losses) resulted primarily from foreign denominated intercompany receivables that we held from one of our Australian subsidiaries which mainly resulted from funding provided to complete the acquisition of Energy Response Holdings Pty Ltd (Energy Response) and fluctuations in the Australian dollar exchange rate, in addition to U.S. dollar denominated intercompany payables to us from one of our German subsidiaries and one of our UK subsidiaries which mainly resulted from funding provided to complete the acquisitions of Entelios and Entech, respectively. During the three and six month periods ended June 30, 2014, $6.2 million ($6.6 million Australian) and $6.3 million ($6.7 million Australian), respectively, of the intercompany receivable from our Australian subsidiary was settled resulting in a realized loss of $0.7 million and $0.7 million, respectively. During the three and six month periods ended June 30, 2013, $1.5 million ($1.5 million Australian) and $11.8 million ($11.4 million Australian), respectively, of the intercompany receivable from our Australian subsidiary was settled resulting in a realized loss of $0.1 million and $0.3 million, respectively. During the three and six month periods ended June 30, 2014 and 2013, there were no other material realized gains (losses) incurred related to transactions denominated in foreign currencies. We currently do not hedge any of our foreign currency transactions.

Income Taxes

For the three and six month periods ended June 30, 2014, we recorded a $0.3 million provision for income taxes and ($0.2) million benefit from income taxes, respectively. The tax provision consists of a tax benefit on its foreign loss for the quarter and a U.S. tax expense related to tax deductible goodwill that generates a deferred tax liability that cannot be used as a source of income against which deferred tax assets may be realized. The provision for income taxes for the three months ended June 30, 2014 includes a $1.1 million benefit from income taxes due to the release of a portion of the U.S. valuation allowance in connection with the Entech acquisition and a $1.5 million provision for deferred income taxes in connection with the sale of Utility Solutions Consulting.

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. We are able to reliably estimate the annual effective tax rate on our foreign earnings, but are unable to reliably estimate the annual effective tax rate on U.S. earnings. As a result, we have provided a $0.2 million worldwide tax benefit for the six months ended June 30, 2014.

We review all available evidence to evaluate the recovery of deferred tax assets, including the recent history of losses in all tax jurisdictions, as well as our ability to generate income in future periods. As of June 30, 2014, due to the uncertainty related to the ultimate use of certain deferred income tax assets, we have provided a valuation allowance on certain of our U.S., Australia, Germany, Japan, Korea, New Zealand, and UK deferred tax assets.

For the three and six month periods ended June 30, 2013, due to the fact that we could not make a reliable estimate of our annual effective rate at June 30, 2013, we recorded an income tax provision of $0.2 million and $0.5 million, respectively, based on the estimated foreign taxes resulting from guaranteed profit allocable to our foreign subsidiaries, which were determined to be limited-risk service providers acting on behalf of the U.S. parent for tax purposes, for which there were no tax net operating loss carryforwards, and amortization of tax deductible goodwill, which generated a deferred tax liability that could not be offset by net operating losses or other deferred tax assets since its reversal is considered indefinite in nature.

Liquidity and Capital Resources

Overview

We have generated significant cumulative losses since inception. As of June 30, 2014, we had an accumulated deficit of $139.2 million. As of June 30, 2014, our principal sources of liquidity were cash and cash equivalents totaling $108.9 million, a decrease of $40.3 million from our December 31, 2013 balance of $149.2 million, and amounts available under the 2013 credit facility. At June 30, 2014 and December 31, 2013, our excess cash was primarily invested in money market funds.

We believe our existing cash and cash equivalents at June 30, 2014, amounts available under the 2013 credit facility and our anticipated net cash flows from operating activities will be sufficient to meet our anticipated cash needs, including investing activities,

 

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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 energy management applications, solutions and products to 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 new energy management applications, services and products, the expansion of our sales and marketing and research and development activities, and the geographic expansion of our business operations. To the extent that our cash and cash equivalents, amounts available under the 2013 credit facility and our anticipated cash flows from operating activities are insufficient to fund our future activities or planned future acquisitions, we may be required to raise additional funds through bank credit arrangements or public or private equity or debt financings. We also may raise additional funds in the event we determine in the future to effect one or more acquisitions of businesses, technologies or products. In addition, we may elect to raise additional funds even before we need them if the conditions for raising capital are favorable. Any equity or equity-linked financing could be dilutive to existing stockholders. In the event we require additional cash resources we may not be able to obtain bank credit arrangements or complete any equity or debt financing on terms acceptable to us or at all.

Cash Flows

The following table summarizes our cash flows for the six months ended June 30, 2014 and 2013 (dollars in thousands):

 

     Six Months Ended June 30,  
     2014     2013  

Cash flows provided by operating activities

   $ 5,726     $ 12,164  

Cash flows used in investing activities

     (41,864     (25,353

Cash flows (used in) provided by financing activities

     (4,448     791  

Effects of exchange rate changes on cash

     300       (1,067
  

 

 

   

 

 

 

Net change in cash and cash equivalents

   $ (40,286   $ (13,465
  

 

 

   

 

 

 

Cash Flows Provided by Operating Activities

Cash provided by operating activities primarily consists of net loss adjusted for certain non-cash items including depreciation and amortization, stock-based compensation expenses, and the effect of changes in working capital and other activities.

Cash provided by operating activities for the six month period ended June 30, 2014 was $5.7 million and consisted of a net loss of $57.8 million and gains of $5.5 million on the sales of service line and assets, which are included as a component of net loss but represent investing activities, offset by $24.7 million of non-cash items, and $44.3 million of net cash provided by working capital and other activities. The noncash items consisted primarily of depreciation and amortization, stock-based compensation charges, equipment charges, unrealized foreign exchange transaction losses due to the strengthening of the U.S. dollar and deferred taxes. Cash provided by working capital and other activities consisted of a decrease of $12.6 million in accounts receivable due to the timing of cash receipts under the demand response programs in which we participate, a decrease of $65.6 million in unbilled revenues, most of which related to the PJM demand response market, an increase of $29.9 million in deferred revenue primarily related to the Western Australia demand response program, an increase of $0.6 million in accrued payroll and related expenses, and an increase of $12.3 million in accounts payable, accrued performance adjustments and accrued expenses primarily due to the timing of payments. These amounts were offset by cash used in working capital and other activities consisting of an increase in prepaid expenses and other assets of $3.8 million, an increase in capitalized incremental direct customer contract costs of $33.7 million, a decrease of other noncurrent liabilities of $0.5 million and a decrease of $38.7 million in accrued capacity payments.

Cash provided by operating activities for the six month period ended June 30, 2013 was $12.2 million and consisted of a net loss of $64.9 million offset by $24.4 million of non-cash items and $52.7 million of net cash provided by working capital and other activities. The noncash items consisted primarily of depreciation and amortization, stock-based compensation charges, equipment charges, unrealized foreign exchange transaction losses due to the strengthening of the U.S. dollar and deferred taxes. Cash provided by working capital and other activities consisted of a decrease of $9.5 million in accounts receivable due to the timing of cash receipts under the demand response programs in which we participate, a decrease of $44.4 million in unbilled revenues, most of which related to the PJM demand response market, an increase of $5.9 million in other noncurrent liabilities, an increase of $29.3 million in deferred revenue primarily related to the Western Australia demand response program, an increase of $0.3 million in accrued payroll and related expenses, and an increase of $1.3 million in accounts payable, accrued performance adjustments and accrued expenses primarily due to the timing of payments. These amounts were offset by cash used in working capital and other activities consisting of an increase in prepaid expenses and other assets of $4.5 million, an increase in capitalized incremental direct customer contract costs of $14.7 million, an increase in other assets of $0.5 million and a decrease of $18.3 million in accrued capacity payments.

 

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Cash Flows Used in Investing Activities

Cash used in investing activities was $41.9 million for the six month period ended June 30, 2014. During the six month period ended June 30, 2014, we made payments, net of cash acquired, of $3.9 million, $20.2 million, $10.6 million and $0.3 million for the acquisitions of Activation, Entelios, Entech, and another immaterial acquisition of a foreign entity, respectively. In addition, during the six month period ended June 30, 2014, we made a payment of $1.0 million to acquire a cost method investment and a payment of $0.4 million for the acquisition of a customer contract. We also made $12.6 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 six month period ended June 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. In addition, during the six month period ended June 30, 2014, our restricted cash and deposits decreased by $0.6 million due to a decrease in deposits principally related to the financial assurance requirements for the demand response programs in which we participate.

Cash used in investing activities was $25.4 million for the six month period ended June 30, 2013. During the six month period ended June 30, 2013, we incurred $27.2 million in capital expenditures primarily related to capital expenditures for our new corporate headquarters, demand response equipment, as well as capitalized internal use software costs as we continued our investment to further develop and enhance our software. In addition, during the six month period ended June 30, 2013, our restricted cash and deposits decreased by $1.8 million due to a decrease in deposits principally related to the financial assurance requirements for demand response programs in which we participated, as these deposits were replaced with letters of credit.

Cash Flows (Used In) Provided by Financing Activities

Cash used in financing activities was $4.4 million for the six month period ended June 30, 2014 and consisted primarily of payments made for employee restricted stock minimum tax withholdings, partially offset by proceeds that we received from the exercise of options to purchase shares of our common stock.

Cash provided by financing activities was $0.8 million for the six month period ended June 30, 2013 and consisted primarily of proceeds that we received from exercises of options to purchase shares of our common stock.

Credit Facility Borrowings

In March 2012, we and one of our subsidiaries entered into the 2012 credit facility. On April 12, 2013, we, one of our subsidiaries and SVB entered into an amendment to the 2012 credit facility to extend the termination date from April 15, 2013 to April 30, 2013. On April 18, 2013, we entered into the 2013 credit facility. The 2013 credit facility replaced the 2012 credit facility.

The 2013 credit facility provides for a two year revolving line of credit in the aggregate amount of $70 million, subject to increase from time to time up to an aggregate amount of $100 million with an additional commitment from the lenders or new commitments from new financial institutions.

Subject to continued compliance with the covenants contained in the 2013 credit facility, the full amount of the 2013 credit facility may be available for issuances of letters of credit and up to $5 million may be available for swing line loans. The interest on revolving loans under the 2013 credit facility will accrue, at our election, at either (i) the Eurodollar Rate with respect to the relevant interest period plus 2.00% or (ii) the ABR (defined as the highest of (x) the “prime rate” as quoted in the Wall Street Journal , and (y) the Federal Funds Effective Rate plus 0.50%) plus 1.00%. The letter of credit fee charged under the 2013 credit facility is consistent with the 2012 credit facility letter of credit fee of 2.00%. We expense the interest and letter of credit fees under the 2013 credit facility, as applicable, in the period incurred. The obligations under the 2013 credit facility are secured by all of our domestic assets and the assets of several of our domestic subsidiaries. The 2013 credit facility terminates on April 18, 2015 and all amounts outstanding thereunder will become due and payable in full and we would be required to collateralize with cash any outstanding letter of credit under the 2013 credit facility up to 105% of the amounts outstanding. In connection with the 2013 credit facility and related amendments we incurred financing costs of approximately $0.9 million which were deferred and are being amortized to interest expense over the term of the 2013 credit facility, or through April 18, 2015.

 

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The 2013 credit facility contains customary terms and conditions for credit facilities of this type, including, among other things, restrictions on our and our subsidiaries ability to incur additional indebtedness, create liens, enter into transactions with affiliates, transfer assets, make certain acquisitions, pay dividends or make distributions on, or repurchase, our common stock, consolidate or merge with other entities, or undergo a change in control. In addition, we are required to meet certain monthly and quarterly financial covenants customary with this type of credit facility, as described above, including maintaining a minimum specified level of free cash flow, a minimum specified unrestricted cash balance and a minimum specified ratio of current assets to current liabilities.

The 2013 credit facility contains customary events of default, including payment defaults, breaches of representations, breaches of affirmative or negative covenants, cross defaults to other material indebtedness, bankruptcy and failure to discharge certain judgments. If a default occurs and is not cured within any applicable cure period or is not waived, SVB may accelerate our obligations under the 2013 credit facility. If we are determined to be in default then any amounts outstanding under the 2013 credit facility would become immediately due and payable and we would be required to collateralize with cash any outstanding letters of credit up to 105% of the amounts outstanding.

As of June 30, 2014, we were in compliance with all of our covenants under the 2013 credit facility. We believe that it is reasonably assured that we will comply with the covenants of the 2013 credit facility for the foreseeable future.

As of June 30, 2014, we had no borrowings, but had outstanding letters of credit totaling $17.0 million under the 2013 credit facility. The decrease in the amount of outstanding letters of credit from December 31, 2013 to June 30, 2014 is primarily the result of a reduction in the outstanding letters of credit resulting from a in the collateral requirements for demand response arrangements and obligations. As of June 30, 2014, we had $53.0 million available under the 2013 credit facility for future borrowings or issuances of additional letters of credit. Subsequent to June 30, 2014, the outstanding letters of credit has decreased as a result of a cancellation of a letter of credit totaling $4.9 million due to a reduction in collateral requirements under an open market demand response program partially offset by the issuance of an additional letter of credit totaling $3.1 million as collateral under a new demand response arrangement with an utility.

In May 2014, we were required to provide financial assurance in connection with our capacity bid in a certain open market bidding program. We have provided this financial assurance utilizing a $22.0 million letter of credit issued under the 2013 credit facility and additionally, utilized $4.5 million of our available unrestricted cash on hand. During the three month period ended June 30, 2014, based on the capacity that we cleared in the above open market bidding program and the required post-auction financial assurance requirements, we recovered all of our available cash that we had provided as financial assurance prior to the auction and $17.0 million of the letter of credit was cancelled.

Contingent Earn-Out Payments

As discussed in Note 2 to our unaudited condensed consolidated financial statements contained herein, in connection with our acquisitions of Entelios, Activation and another immaterial acquisition, we may be obligated to pay additional contingent purchase price consideration related to earn-out payments.

The earn-out payment for Entelios, if any, will be based on the achievement of certain minimum defined profit metrics for the years ending December 31, 2014 and 2015, respectively. Of the $2.0 million (1.5 million Euros) maximum earn-out payment, up to $0.8 million (0.6 million Euros) and $1.2 million (0.9 million Euros) relate to the achievement of the defined profit metrics for the years ending December 31, 2014 and 2015, respectively. If the minimum defined profit metrics are not achieved, there will be no partial payment, however, the amount of the earn-out payment can vary based on the amount that profits exceed the minimum defined profit metrics. We determined that the initial fair value of the earn-out payment as of the acquisition date was $0.1 million. We recorded our estimate of the fair value of the contingent consideration based on the evaluation of the likelihood of the achievement of the contractual conditions that would result in the payment of the contingent consideration and weighted probability assumptions of these outcomes. This fair value measurement was determined utilizing a Monte Carlo simulation and was based on significant inputs not observable in the market and therefore, represented a Level 3 measurement as defined in ASC 820. Any changes in fair value will be recorded in our consolidated statements of operations. As of June 30, 2014, there were no changes in the probability of the earn-out payment. This liability has been discounted to reflect the time value of money and therefore, as the milestone date approaches, the fair value of this liability will increase. This increase in fair value is recorded to cost of revenues in our accompanying unaudited condensed consolidated statements of operations. During the three month and six month periods ended June 30, 2014, the change in fair value that resulted from the accretion of the time value of money discount was not material. At June 30, 2014, the liability was recorded at $0.1 million after adjusting for changes in exchange rates.

The earn-out payment for Activation, if any, will be based on the achievement of certain minimum defined MW enrollment, as well as, profit metrics for the years ending December 31, 2014 and 2015, respectively. Of the $1.4 million (1.0 million Euros)

 

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maximum earn-out payment, up to $0.4 million (0.3 million Euros) and $1.0 million (0.7 million Euros) relate to the achievement of the defined profit metrics for the years ending December 31, 2014 and 2015, respectively. If the minimum defined profit metrics are not achieved, there will be no partial payment, however, the amount of the earn-out payment can vary based on the amount that profits exceed the minimum defined profit metrics. We determined that the initial fair value of the earn-out payment as of the acquisition date was $0.3 million. We recorded our estimate of the fair value of the contingent consideration based on the evaluation of the likelihood of the achievement of the contractual conditions that would result in the payment of the contingent consideration and weighted probability assumptions of these outcomes. This fair value measurement was determined utilizing a Monte Carlo simulation and was based on significant inputs not observable in the market and therefore, represented a Level 3 measurement as defined in ASC 820. Any changes in fair value will be recorded in our consolidated statements of operations. As of June 30, 2014, there were no changes in the probability of the earn-out payment. This liability has been discounted to reflect the time value of money and therefore, as the milestone date approaches, the fair value of this liability will increase. This increase in fair value is recorded to cost of revenues in our accompanying unaudited condensed consolidated statements of operations. During the three and six month periods ended June 30, 2014, the change in fair value that resulted from the accretion of the time value of money discount was not material. At June, 2014, the liability was recorded at $0.3 million after adjusting for changes in exchange rates.

In connection with our acquisition of a foreign entity in April 2014, we may be obligated to pay additional contingent purchase price consideration related to certain earn-out amounts up to a maximum of $1.8 million. The earn-out payments, if any, will be based on the achievement of certain defined market legislation and certain operational metrics. Up to $1.5 million of the earn-out payments are also only payable to those stockholders of the acquired entity who are employees as of the time of achievement. Therefore, we have concluded that these earn-out payments should be accounted for as compensation arrangements and not a component of purchase price and we will evaluate the probability of achievement and record expense ratably over the applicable estimated service period as compensation expense for the amount, if any, deemed probable of achievement. The remaining earn-out payment of $0.3 million was achieved during the three month period June 30, 2014.

Capital Spending

We have made capital expenditures of approximately $5.1 million related to software additions, including capitalized software, to further expand the functionality of our software and solutions, as well as, increased demand response equipment related to an increased installed base. Our capital expenditures totaled $12.6 million and $27.2 million during the six month periods ended June 30, 2014 and 2013, respectively. We expect capital expenditures to decrease for fiscal 2014 as compared to fiscal 2013 due to the capital expenditures we incurred in 2013 to build-out and furnish our new corporate headquarters.

Contractual Obligations

As of June 30, 2014, the contractual obligations disclosure contained in our 2013 Form 10-K has not materially changed except as disclosed above related to contingent earn-out payments and as disclosed below:

In March 2014, we entered into a lease for our California operations. The lease term is through September 2019 and the lease contains both a rent holiday period and escalating rental payments over the lease term. The lease requires payments for additional expenses such as taxes, maintenance, and utilities and contains a fair value renewal option. The lease commenced on April 1, 2014. In addition, in connection with the acquisitions we completed during the six month period ended June 30, 2014, we acquired certain facility operating lease arrangements which were all considered to contain current market terms and rates. These leases have terms that range from one to ten years and expire through March 2020. Certain of the leases require payments for additional expenses such as taxes, maintenance, and utilities and contain fair value renewal options. There were no ongoing rent holidays or escalating rent payments over the remaining lease terms as of the dates of acquisition.

Information regarding our significant contractual obligations is set forth in the following table and includes the operating lease arrangement described above. Payments due by period have been presented based on payments due subsequent to June 30, 2014. For example, the payments due in less than one year represent contractual obligations that will be settled by June 30, 2015.

 

     Payments Due By Period (in thousands)  

Contractual Obligations

   Total      Less
than
1 Year
     1 - 3 Years      3 - 5 Years      More
than
5 Years
 

Operating lease obligations (not reduced by sublease rentals of $191)

   $ 35,659       $ 6,333       $ 12,196       $ 12,134       $ 4,996   

Total

   $ 35,659       $ 6,333       $ 12,196       $ 12,134       $ 4,996   

 

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In connection with our acquisition of a foreign entity in April 2014, $0.3 million has been retained by us as deferred purchase price consideration to cover general business representations and warranties. This amount will be paid in October 2015.

Off-Balance Sheet Arrangements

As of June 30, 2014, 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 June 30, 2014, we had outstanding letters of credit totaling $17.0 million under the 2013 credit facility. For information on these commitments and contingent obligations, see “Liquidity and Capital Resources – Credit Facility Borrowings” above and Note 9 to our unaudited condensed consolidated financial statements contained herein.

Critical Accounting Policies and Use of Estimates

The discussion and analysis of our financial condition and results of operations are based upon our interim unaudited condensed consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these consolidated financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to revenue recognition for multiple element arrangements, allowance for doubtful accounts, valuations and purchase price allocations related to business combinations, expected future cash flows including growth rates, discount rates, terminal values and other assumptions and estimates used to evaluate the recoverability of long-lived assets and goodwill, estimated fair values of intangible assets and goodwill, amortization methods and periods, certain accrued expenses and other related charges, stock-based compensation, contingent liabilities, tax reserves and recoverability of our net deferred tax assets and related valuation allowance. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates if past experience or other assumptions do not turn out to be substantially accurate. Any differences may have a material impact on our financial condition and results of operations.

The critical accounting estimates used in the preparation of our financial statements that we believe affect our more significant judgments and estimates used in the preparation of our interim unaudited condensed consolidated financial statements presented in this Quarterly Report on Form 10-Q are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in the notes to the consolidated financial statements included in our 2013 Form 10-K. Except as disclosed herein, there have been no material changes to our critical accounting policies or estimates during the three and six month periods ended June 30, 2014.

Revenue Recognition

We recognize revenues in accordance with Accounting Standards Codification 605, Revenue Recognition (ASC 605). In all of our arrangements, we do not recognize any revenues until it is determined that persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and collection is deemed to be reasonably assured. In making these judgments, we evaluate the following criteria:

 

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

 

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

 

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    Fees are fixed or determinable . We consider the fee to be fixed or determinable unless the fee is subject to refund or adjustment or is not payable within normal payment terms. If the fee is subject to refund or adjustment and we cannot reliably estimate this amount, we recognize revenues when the right to a refund or adjustment lapses. If we offer payment terms significantly in excess of our normal terms, we recognize revenues as the amounts become due and payable or upon the receipt of cash.

 

    Collection is reasonably assured. We conduct a credit review at the inception of an arrangement to determine the creditworthiness of the customer. Collection is reasonably assured if, based upon evaluation, we expect that the customer will be able to pay amounts under the arrangement as payments become due. If we determine that collection is not reasonably assured, revenues are deferred and recognized upon the receipt of cash.

We maintain a reserve for customer adjustments and allowances as a reduction in revenues. In determining our revenue reserve estimate, and in accordance with company policy, we rely on historical data and known performance adjustments. These factors, and unanticipated changes in the economic and industry environment, could cause our reserve estimates to differ from actual results. We record a provision for estimated customer adjustments and allowances in the same period as the related revenues are recorded. These estimates are based on the specific facts and circumstances of a particular program, analysis of credit memo data, historical customer adjustments, and other known factors. If the data we use to calculate these estimates does not properly reflect reserve requirements, then a change in the allowances would be made in the period in which such a determination is made and revenues in that period could be affected. As of both June 30, 2014 and December 31, 2013, our revenue reserves were $0.5 million.

Revenues from grid operators and revenues from utilities principally represent demand response revenues. During the three month period ended June 30, 2014, revenues from grid operators and utilities were comprised of $33.3 million of demand response revenues and $1.6 million of enterprise EIS and related solutions revenues. During the three month period ended June 30, 2013, revenues from grid operators and utilities were comprised of $26.5 million of demand response revenues and $1.9 million of enterprise EIS and related solutions revenues. During the six month period ended June 30, 2014, revenues from grid operators and utilities were comprised of $77.4 million of demand response revenues and $3.6 million of enterprise EIS and related solutions revenues. During the six month period ended June 30, 2013, revenues from grid operators and utilities were comprised of $51.0 million of demand response revenues and $4.3 million of enterprise EIS and related solutions revenues.

All revenues from enterprise customers for the three and six month periods ended June 30, 2014 and 2013 were derived from enterprise EIS and related solutions.

Demand Response Revenues

We enter into contracts and open market bidding programs with utilities and electric power grid operators to provide demand response applications and services. Currently we have two principal service offerings under which we provide demand response applications and services: (1) full-service turnkey offering to utilities under which we manage all aspects of demand response program delivery to deliver a firm capacity resource, or Demand Resource and (2) utility partnership offering under which utilities can utilize software through a software as a service offering, integrated metering hardware, and professional services to support their tariff-based C&I demand response programs on a service-level agreement basis, or Demand Manager.

We have evaluated the factors within ASC 605 regarding gross versus net revenue reporting for our demand response revenues and our payments to C&I customers. Based on the evaluation of the factors within ASC 605, we have determined that all of the applicable indicators of gross revenue reporting were met. The applicable indicators of gross revenue reporting included, but were not limited to, the following:

 

    We are the primary obligor in our arrangements with electric power grid operators and utility customers because we provide our demand response services directly to electric power grid operators and utilities under long-term contracts or pursuant to open market programs and contracts separately with C&I customers to deliver such services. We manage all interactions with the electric power grid operators and utilities, while C&I customers do not interact with the electric power grid operators and utilities. In addition, we assume the entire performance risk under our arrangements with electric power grid operators and utility customers, including the posting of financial assurance to assure timely delivery of committed capacity with no corresponding financial assurance received from our C&I customers. In the event of a shortfall in delivered committed capacity, we are responsible for all penalties assessed by the electric power grid operators and utilities without regard for any recourse we may have with our C&I customers.

 

    We have latitude in establishing pricing, as the pricing under our arrangements with electric power grid operators and utilities is negotiated through a contract proposal and contracting process or determined through a capacity auction. We then separately negotiate payment to C&I customers and have complete discretion in the contracting process with the C&I customers.

 

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    We have complete discretion in determining which C&I customers will provide the demand response services, provided that the C&I customer is located in the same region as the applicable electric power grid operator or utility.

 

    We are involved in both the determination of service specifications and perform part of the services, including the installation of metering and other equipment for the monitoring, data gathering and measurement of performance, as well as, in certain circumstances, the remote control of C&I customer loads.

As a result, we determined that we earn revenue (as a principal) from the delivery of demand response services to electric power grid operators and utility customers and record the amounts billed to the electric power grid operators and utility customers as gross demand response revenues and the amounts paid to C&I customers as cost of revenues.

EnerNOC Demand Resource Solution

The majority of our demand response revenues are generated from the EnerNOC Demand Resource solution. Demand response revenues consist of two elements: revenue earned based on our ability to deliver committed capacity to our electric power grid operator and utility customers, which we refer to as capacity revenue; and revenue earned based on additional payments made to us for the amount of energy usage actually curtailed from the grid during a demand response event, which we refer to as energy event revenue.

We recognize demand response revenue when we have provided verification to the electric power grid operator or utility of our ability to deliver the committed capacity which entitles us to payments under the contract or open market program. Committed capacity is generally verified through the results of an actual demand response event or a measurement and verification test. Once the capacity amount has been verified, the revenue is recognized and future revenue becomes fixed or determinable and is recognized monthly until the next demand response event or test. In subsequent verification events, if our verified capacity is below the previously verified amount, the electric power grid operator or utility customer will reduce future payments based on the adjusted verified capacity amounts. Ongoing demand response revenue recognized between demand response events or tests that are not subject to penalty or customer refund are recognized in revenue. If the revenue is subject to refund and the amount of refund cannot be reliably estimated, the revenue is deferred until the right of refund lapses.

All demand response capacity revenues related to our participation in the PJM summer-only open market program are being recognized at the end of the four-month delivery period of June through September, or during the three month period ended September 30 th of each year. Because the period during which we are required to perform (June through September) is shorter than the period over which payments are received under the program (June through May), a portion of the revenues that have been earned are recorded and accrued as unbilled revenue. Substantially all revenues related to the PJM open market program year ended September 30, 2013 were recognized during the three month period ended September 30, 2013 and as a result of the billing period not coinciding with the revenue recognition period, we had $64.6 million in unbilled revenues from PJM at December 31, 2013. Due to the fact the demand response capacity revenues related to the PJM summer-only open market program are not recognized until the three months ended September 30 th of each year, there were no material unbilled revenues as of June 30, 2014.

With respect to the PJM open market program, we commenced participation in a new service offering within this program on June 1, 2014. Under this new service delivery offering, which we refer to as the PJM Extended demand response program, the delivery period is from June through October and then May in the subsequent calendar year. The revenues and any associated penalties, if any, for underperformance related to participation in the PJM Extended demand response program are separate and distinct from our participation in other offerings within the PJM open market program. Under the PJM Extended demand response program, penalties incurred as a result of underperformance for a demand response event dispatched during the months of June through September and for a demand response test event are the same as the historical service offering in which we have participated, which we refer to as the PJM summer only demand response program. However, penalties incurred as a result of underperformance for an event dispatched during the month of October or the month of May are 1/52 multiplied by the number of the shortfall amount (committed capacity less actual delivered capacity) times the applicable capacity rate. Consistent with the PJM summer only demand response program, the fees could potentially be subject to adjustment or refund based on performance during the applicable performance period. Therefore, we are currently evaluating whether we have the ability to reliably estimate the amount of fees potentially subject to adjustment or refund as of the end of September or whether revenues related to our participation in this program will be recognized at the end of the performance period, or during the three month period ended June 30 th of the following calendar year. For the PJM Extended demand response program period that commenced on June 1, 2014 and ends on May 31, 2015, the potential fees that could be earned are not material.

Demand response capacity revenues related to our participation in the WA demand response program are potentially subject to refund and therefore, are deferred until a portion of such capacity revenues are fixed which occurs upon an emergency event

 

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dispatch or until the end of the program period on September 30 th . Historically all capacity revenues have been recognized during the three month period ended September 30 th as there have been previously no emergency event dispatches. During the three month period ended June 30, 2014, there was an emergency event dispatch in this open market program and as a result, a portion of the capacity revenues were fixed and no longer subject to adjustments resulting in the recognition of $4.3 million of capacity revenues and $2.0 million of related cost of revenues.

Energy event revenues are recognized when earned. Energy event revenue is deemed to be substantive and represents the culmination of a separate earnings process and is recognized when the energy event is initiated by the electric power grid operator or utility customer and we have responded under the terms of the contract or open market program. During the three month periods ended June 30, 2014 and 2013, we recognized $4.2 million and $2.2 million, respectively, of energy event revenues. During the six month periods ended June 30, 2014 and 2013, we recognized $24.8 million and $4.2 million, respectively, of energy event revenues.

In 2012, we decided to net settle a portion of our future contractual delivery obligations in a certain open market bidding program. As of June 30, 2014, we entered into transactions to net settle a significant portion of our future delivery obligations and these transactions have been approved by the customer. As a result, as long as the other criteria for revenue recognition are met, we recognize these fees from the net settlement transactions as revenues as they become due and payable with such fees being recorded as a component of our grid operator revenues. During the three and six month periods ended June 30, 2014, we recognized revenues of $4.0 million and $7.8 million, respectively, related to these net settlement transactions.

We have evaluated the forward capacity programs in which we participate and have determined that our contractual obligations in these programs do not currently meet the definition of derivative contracts under ASC 815, Derivatives and Hedging (ASC 815).

EnerNOC Demand Manager Solution

Under our EnerNOC Demand Manager solution, we generally receive an ongoing fee for overall management of the utility demand response program based on enrolled capacity or enrolled C&I customers, which is not subject to adjustment based on performance during a demand response dispatch. We recognize revenues from these fees ratably over the applicable service delivery period commencing upon when the C&I customers have been enrolled and the contracted services have been delivered. In addition, under this offering, we may receive additional fees for program start-up, as well as, for C&I customer installations. We have determined that these fees do not have stand-alone value due to that such services do not have value without the ongoing services related to the overall management of the utility demand response program and therefore, we recognize these fees over the estimated customer relationship period, which is generally the greater of three years or the contract period, commencing upon the enrollment of the C&I customers and delivery of the contracted services. Through June 30, 2014, revenues from EnerNOC Demand Manager have not been material to our consolidated results of operations.

Enterprise EIS and Related Solutions

Our enterprise EIS and related solutions revenues generally represent ongoing service arrangements under which the revenues are recognized ratably over the service period commencing upon delivery of the contracted service with the customer. Under certain of our arrangements, a portion of the fees received may be subject to adjustment or refund based on the validation of the energy savings delivered after the implementation is complete. As a result, we defer the portion of the fees that are subject to adjustment or refund until such time as the right of adjustment or refund lapses, which is generally upon completion and validation of the implementation. In addition, under certain other of our arrangements, we sell proprietary equipment to C&I customers that is utilized to provide the ongoing services that we deliver. Currently, this equipment has been determined to not have stand-alone value. As a result, we defer revenues associated with the equipment and we begin recognizing such revenue ratably over the expected C&I customer relationship period (generally three years), once the C&I customer is receiving the ongoing services from us. In addition, we capitalize the associated direct and incremental costs, which primarily represent the equipment and third-party installation costs, and recognize such costs over the expected C&I customer relationship period.

We follow the provisions of ASC Update No. 2009-13, Multiple-Deliverable Revenue Arrangements (ASU 2009-13). We typically determine the selling price of our services based on vendor specific objective evidence (VSOE). Consistent with our methodology under previous accounting guidance, we determine VSOE based on our normal pricing and discounting practices for the specific service when sold on a stand-alone basis. In determining VSOE, our policy is to require a substantial majority of selling prices for a product or service to be within a reasonably narrow range. We also consider the class of customer, method of distribution, and the geographies into which our products and services are sold when determining VSOE. We typically have had VSOE for our products and services.

 

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In certain circumstances, we are not able to establish VSOE for all deliverables in a multiple element arrangement. This may be due to the infrequent occurrence of stand-alone sales for an element, a limited sales history for new services or pricing within a broader range than permissible by our policy to establish VSOE. In those circumstances, we proceed to the alternative levels in the hierarchy of determining selling price. Third Party Evidence (TPE) of selling price is established by evaluating largely similar and interchangeable competitor products or services in stand-alone sales to similarly situated customers. We are typically not able to determine TPE and have not used this measure since we have been unable to reliably verify standalone prices of competitive solutions. Our best estimate of selling price (ESP) is established in those instances where neither VSOE nor TPE are available, considering internal factors such as margin objectives, pricing practices and controls, customer segment pricing strategies and the product life cycle. Consideration is also given to market conditions such as competitor pricing information gathered from experience in customer negotiations, market research and information, recent technological trends, competitive landscape and geographies. Use of ESP is limited to a very small portion of our services, principally certain other EIS software and related solutions.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (FASB) issued ASU No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (ASU 2014-08). ASU 2014-08 amends the definition of discontinued operations under ASC 205-20 to only those disposals of components of an entity that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results will be reported as discontinued operations in the financial statements. This guidance is effective for all disposals (or classifications as held for sale) of components of an entity that occur within annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted, but only for disposals (or classifications as held for sale) that have not been reported in financial statements previously issued or available for issuance. We have early adopted this guidance as of January 1, 2014. The adoption of this guidance had no impact on our consolidated financial statements.

In May 2014, the Financial Accounting Standards Board (FASB) issued ASU No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 provides guidance for revenue recognition and the standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The new guidance is effective for annual and interim periods beginning after December 15, 2016, with no early adoption permitted. Therefore, ASU No 2015-09 will be effective for us beginning in the first quarter of fiscal year 2018, and allows for full retrospective adoption applied to all periods presented or retrospective adoption with the cumulative effect of initially applying this update recognized at the date of initial application. The method of adoption has not been determined yet by us. We are currently in the process of evaluating the impact of adoption of this ASU on our financial position and results of operations.

Additional Information

Non-GAAP Financial Measures

To supplement our consolidated financial statements presented on a GAAP basis, we disclose certain non-GAAP measures that exclude certain amounts, including non-GAAP net loss attributable to EnerNOC, Inc., non-GAAP net loss per share attributable to EnerNOC, Inc., adjusted EBITDA and free cash flow. These non-GAAP measures are not in accordance with, or an alternative for, generally accepted accounting principles in the United States.

The GAAP measure most comparable to non-GAAP net loss attributable to EnerNOC, Inc. is GAAP net loss attributable to EnerNOC, Inc.; the GAAP measure most comparable to non-GAAP net loss per share attributable to EnerNOC, Inc. is GAAP net loss per share attributable to EnerNOC, Inc.; the GAAP measure most comparable to adjusted EBITDA is GAAP net loss attributable to EnerNOC, Inc.; and the GAAP measure most comparable to free cash flow is cash flows (used in) provided by 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 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.

 

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The following is an explanation of the non-GAAP measures that we utilize, including the adjustments that management excluded as part of the non-GAAP measures for the three and six month periods ended June 30, 2014 and 2013, respectively, as well as reasons for excluding these individual items:

 

    Management defines non-GAAP net income (loss) attributable to EnerNOC, Inc. as net income (loss) attributable to EnerNOC, Inc. before expenses related to stock-based compensation and amortization expenses related to acquisition-related intangible assets, net of related tax effects. Non-GAAP net income (loss) attributable to EnerNOC, Inc. includes gains or losses resulting from either the sale of certain assets or disposals of components of an entity that do not represent a strategic shift that has (or would be expected to have) a major effect on an entity’s operations and financial results, net of any related tax effects, or that represents potential ongoing operational trends or are not material. When evaluating the materiality of a gain (or loss) on the sale of assets, management evaluates such gain (or loss) in the context of the Company’s estimated full year financial results, and considers the judgment of a reasonable person relying on the evaluation and whether or not such judgment would have been changed or influenced by the inclusion or exclusion of the gain (or loss).

 

    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, interest, income taxes and other income (expense). Adjusted EBITDA includes gains or losses resulting from either the sale of certain assets or disposals of components of an entity that do not represent a strategic shift that has (or would be expected to have) a major effect on an entity’s operations and financial results, net of any related tax effects, or that represent potential ongoing operational trends or are not material. When evaluating the materiality of a gain (or loss) on the sale of assets, management evaluates such gain (or loss) in the context of the Company’s estimated full year financial results, and considers the judgment of a reasonable person relying on the evaluation and whether or not such judgment would have been changed or influenced by the inclusion or exclusion of the gain (or loss). Adjusted EBITDA eliminates items that are either not part of our core operations or do not require a cash outlay, such as stock-based compensation. Adjusted EBITDA also excludes depreciation and amortization expense, which is based on our estimate of the useful life of tangible and intangible assets. These estimates could vary from actual performance of the asset, are based on historical cost incurred to build out our deployed network and may not be indicative of current or future capital expenditures.

 

    Management defines free cash flow as net cash provided by (used in) operating activities less capital expenditures. 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.

 

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Non-GAAP Net Loss attributable to EnerNOC, Inc. and Non-GAAP Net Loss per Share attributable to EnerNOC, Inc.

Net loss attributable to EnerNOC, Inc. for the three month period ended June 30, 2014 was $27.4 million, or $0.96 per basic and diluted share, compared to a net loss attributable to EnerNOC, Inc. of $34.4 million, or $1.23 per basic and diluted share, for the three month period ended June 30, 2013. Net loss attributable to EnerNOC, Inc. for the six month period ended June 30, 2014 was $57.8 million, or $2.05 per basic and diluted share, compared to a net loss attributable to EnerNOC, Inc. of $64.9 million, or $2.35 per basic and diluted share, for the six month period ended June 30, 2013. Excluding stock-based compensation charges and amortization expense related to acquisition-related assets, net of tax effects, non-GAAP net loss attributable to EnerNOC, Inc. for the three month period ended June 30, 2014 was $21.1 million, or $0.74 per basic and diluted share, compared to a non-GAAP net loss attributable to EnerNOC, Inc. of $29.3 million, or $1.05 per basic and diluted share, for the three month period ended June 30, 2013. Excluding stock-based compensation charges and amortization expense related to acquisition-related assets, net of tax effects, non-GAAP net loss attributable to EnerNOC, Inc. for the six month period ended June 30, 2014 was $45.4 million, or $1.61 per basic and diluted share, compared to a non-GAAP net loss attributable to EnerNOC, Inc. of $53.3 million, or $1.93 per basic and diluted share, for the six month period ended June 30, 2013. The reconciliation of GAAP net loss attributable to EnerNOC, Inc. to non-GAAP net loss attributable to EnerNOC, Inc. is set forth below:

 

     Three Months Ended June 30,  
     2014     2013  
     (In thousands, except share and per share data)  

GAAP net loss attributable to EnerNOC, Inc.

   $ (27,385   $ (34,351

ADD: Stock-based compensation (1)

     3,799       3,307  

ADD: Amortization expense of acquired intangible assets (1)

     2,479       1,763  
  

 

 

   

 

 

 

Non-GAAP net loss attributable to EnerNOC, Inc.

   $ (21,107   $ (29,281
  

 

 

   

 

 

 

GAAP net loss per basic and diluted share attributable to EnerNOC, Inc.

   $ (0.96   $ (1.23

ADD: Stock-based compensation (1)

     0.13       0.12  

ADD: Amortization expense of acquired intangible assets (1)

     0.09       0.06  
  

 

 

   

 

 

 

Non-GAAP net loss per basic and diluted share attributable to EnerNOC, Inc.

   $ (0.74   $ (1.05
  

 

 

   

 

 

 

Weighted average number of common shares outstanding

    

Basic

     28,461,111       27,852,298  
  

 

 

   

 

 

 

Diluted

     28,461,111       27,852,298  
  

 

 

   

 

 

 

 

     Six Months Ended June 30,  
     2014     2013  
     (In thousands, except share and per share data)  

GAAP net loss attributable to EnerNOC, Inc.

   $ (57,798   $ (64,888

ADD: Stock-based compensation (1)

     8,026       8,011  

ADD: Amortization expense of acquired intangible assets (1)

     4,362       3,557  
  

 

 

   

 

 

 

Non-GAAP net loss attributable to EnerNOC, Inc.

   $ (45,410   $ (53,320
  

 

 

   

 

 

 

GAAP net loss per basic and diluted share attributable to EnerNOC, Inc.

   $ (2.05   $ (2.35

ADD: Stock-based compensation (1)

     0.29       0.29  

ADD: Amortization expense of acquired intangible assets (1)

     0.15       0.13  
  

 

 

   

 

 

 

Non-GAAP net loss per basic and diluted share attributable to EnerNOC, Inc.

   $ (1.61   $ (1.93
  

 

 

   

 

 

 

Weighted average number of common shares outstanding

    

Basic

     28,225,518       27,610,797  
  

 

 

   

 

 

 

Diluted

     28,225,518       27,610,797  
  

 

 

   

 

 

 

 

(1) The non-GAAP adjustments would have no impact on the provision for income taxes recorded for the three or six month periods ended June 30, 2014 or 2013, respectively.

Adjusted EBITDA

Adjusted EBITDA was negative $16.3 million and negative $22.4 million for the three month periods ended June 30, 2014 and 2013, respectively. Adjusted EBITDA was negative $34.7 million and negative $40.9 million for the six month periods ended June 30, 2014 and 2013, respectively.

 

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The reconciliation of net loss to adjusted EBITDA is set forth below (in thousands):

 

     Three Months Ended June 30,     Six Months Ended June 30,  
     2014     2013     2014     2013  

Net loss attributable to EnerNOC, Inc.

   $ (27,385   $ (34,351   $ (57,798   $ (64,888

Add back:

        

Depreciation and amortization

     7,842       6,831       15,207       13,561  

Stock-based compensation expense

     3,799       3,307       8,026       8,011  

Direct and incremental expenses related to acquisitions or divestitures

     413       —         1,359       —    

Other (income) expense

     (374     1,184       (948     1,117  

Interest expense

     603       448       1,053       761  

Provision for (benefit from) income tax

     (1,186 ) (1)      194       (1,611 ) (1)      544  
  

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ (16,288   $ (22,387   $ (34,712   $ (40,894
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Excludes discrete tax provision of $1,450 recorded during the three and six month periods ended June 30, 2014 related to the sale of the USC business component.

 

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Free Cash Flow

Cash flows provided by operating activities were $17.3 million and $5.7 million for the three and six month periods ended June 30, 2014, respectively. Cash flows provided by operating activities were $5.4 million and $12.2 million for the three and six month periods ended June 30, 2013, respectively. We had free cash flow of $10.8 million for the three month period ended June 30, 2014 compared to negative $12.9 million for the three month period ended June 30, 2013. We had negative free cash flow of $6.9 million and $15.0 million for the six month periods ended June 30, 2014 and 2013, respectively. The reconciliation of cash flows from operating activities to free cash flow is set forth below (in thousands):

 

     Three Months Ended June 30,     Six Months Ended June 30,  
     2014     2013     2014     2013  

Net cash provided by operating activities

   $ 17,292     $ 5,384     $ 5,726     $ 12,164  

Subtract:

        

Purchases of property and equipment

     (6,473     (18,248     (12,586     (27,186
  

 

 

   

 

 

   

 

 

   

 

 

 

Free cash flow

   $ 10,819     $ (12,864   $ (6,860   $ (15,022
  

 

 

   

 

 

   

 

 

   

 

 

 

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Except as disclosed herein, there have been no material changes during the three or six month periods ended June 30, 2014 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 2013 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 substantial majority of our foreign expense and sales activities are transacted in local currencies, including Australian dollars, Brazilian real, British pounds, Canadian dollars, Euros, Indian rupee, Japanese yen and New Zealand dollars. In addition, our foreign sales are denominated in local currencies. Fluctuations in the foreign currency rates could affect our sales, cost of revenues and profit margins and could result in exchange losses. In addition, currency devaluations can result in a loss if we maintain deposits in a foreign currency. During the three and six month periods ended June 30, 2014, approximately 31% and 24%, respectively, of our consolidated sales were generated outside the United States, and we anticipate that sales generated outside the United States will continue to represent greater than 10% of our consolidated sales for fiscal 2014 and will continue to grow in subsequent fiscal years.

We believe that the operating expenses of our international subsidiaries that are incurred in local currencies will not have a material adverse effect on our business, results of operations or financial condition for fiscal 2014. Our operating results and certain assets and liabilities that are denominated in foreign currencies are affected by changes in the relative strength of the U.S. dollar against the applicable foreign currency. Our expenses denominated in foreign currencies are positively affected when the U.S. dollar strengthens against the applicable foreign currency and adversely affected when the U.S. dollar weakens.

During the three month periods ended June 30, 2014 and 2013, we incurred net foreign exchange gains (losses) totaling $0.2 million and ($1.3) million, respectively. During the six month periods ended June 30, 2014 and 2013, we incurred net foreign exchange gains (losses) totaling $0.6 million and ($1.3) million, respectively. During the three month periods ended June 30, 2014 and 2013, we realized losses of ($0.7) million and ($0.1) million, respectively, related to transactions denominated in foreign currencies. During the six month periods ended June 30, 2014 and 2013, we realized losses of ($0.7) million and ($0.4) million, respectively, related to transactions denominated in foreign currencies. As of June 30, 2014, we had an intercompany receivable from our Australian subsidiary that is denominated in Australian dollars and not deemed to be of a “long-term investment” nature totaling $3.7 million at June 30, 2014 exchange rates ($3.9 million Australian). In addition, two of our German subsidiaries each have an intercompany payable to us that are denominated in U.S. dollars and not deemed to be of a “long-term investment” nature totaling $19.3 million at June 30, 2014; and two of our UK subsidiaries each have an intercompany payable to us that are denominated in U.S. dollars and not deemed to be of a “long-term investment” nature totaling $3.2 million at June 30, 2014.

 

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A hypothetical 10% increase or decrease in foreign currencies in which we transact would not have a material adverse effect on our financial condition or results of operations with the exception of the impact on the unrealized gain (loss) on our intercompany receivables and payables discussed above. A hypothetical 10% increase or decrease in the foreign currencies related to these intercompany payables and receivables would result in an incremental $2.3 million gain or loss.

We currently do not have a program in place that is designed to mitigate our exposure to changes in foreign currency exchange rates. We frequently evaluate 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.

 

Item 4. Controls and Procedures

Disclosure Controls and Procedures.

Our principal executive officer and principal financial officer, after evaluating the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Quarterly Report on Form 10-Q, have concluded that, based on such evaluation, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to our management, including our principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Internal Control over Financial Reporting.

As a result of our recent acquisitions, we have begun to integrate certain business processes and systems. Accordingly, certain changes have been made and will continue to be made to our internal controls over financial reporting until such time as these integrations are complete. There have been no other changes in our internal control over financial reporting that occurred during the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

 

Item 1. Legal Proceedings

We are subject to legal proceedings, claims and litigation arising in the ordinary course of business. We do not expect the ultimate costs to resolve these matters to have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

On May 3, 2013, a purported shareholder of the Company (the Plaintiff) filed a derivative and class action complaint in the United States District Court for the District of Delaware (the Court) against certain of our officers and directors as well as the Company as a nominal defendant (the Defendants). The complaint asserts derivative claims, purportedly brought on behalf of the Company, for breach of fiduciary duty, waste of corporate assets, and unjust enrichment in connection with certain equity grants (awarded in 2010, 2012, and 2013) that allegedly exceeded an annual limit on per-employee equity grants purported to be contained in the 2007 Plan. The complaint also asserts a direct claim, brought on behalf of the Plaintiff and a proposed class of our shareholders, alleging our proxy statement filed on April 26, 2013 was false and misleading because it failed to disclose that the equity grants were improper. The plaintiff seeks, among other relief, rescission of the equity grants, unspecified damages, injunctive relief, disgorgement, attorneys’ fees, and such other relief as the Court may deem proper.

Defendants filed a motion to dismiss on August 30, 2013. Plaintiff responded to the motion on October 18, 2013 and Defendants replied on November 22, 2013. No hearing date has been set.

On June 27, 2014, the parties engaged in mediation and reached agreement in principle on the terms of a potential settlement. Pursuant to the settlement, defendant members of our Board of Directors would cause the Company’s insurer to make a cash payment of $0.5 million to the Company, and cause the Company to undertake certain reforms in connection with equity granting practices. However, the settlement remains subject to numerous contingencies, including finalization of settlement documentation and court approval. Additionally, we believe that the Defendants have substantial legal and factual defenses to the claims in the complaint, and intend to pursue these defenses vigorously. There can be no assurance, however, that such efforts will be successful. However, as a

 

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result of this agreement in principle on the terms of a potential settlement, we have determined that it is probable that we will incur a loss related to this matter principally related to the remaining amount of our insurance deductible, which was not material and has been accrued for as of June 30, 2014. With respect to the $0.5 million payment to EnerNOC that would result under the terms of this settlement, this amount represents a contingent gain and will be recorded as other income, if and when, the amount is realized. In addition, regardless of the outcome of this matter, the matter may divert financial and management resources and result in general business disruption, including that we may suffer from adverse publicity that could harm our reputation and negatively impact our stock price.

 

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. The following risk factors and other information included in this Quarterly Report on Form 10-Q should be carefully considered. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business. We refer you to our note on forward-looking statements in Item 2 above, which identifies certain forward-looking statements contained in this report that are qualified by these risk factors.

Risks Related to Our Business and Industry

A substantial majority of our revenues are and have been generated from open market program sales to a certain electric power grid operator customer, and the modification or termination of this open market program or sales relationship, or the modification or termination of a sales relationship with any future significant electric power grid operator or utility customer could materially adversely affect our business.

During the years ended December 31, 2013, 2012 and 2011, revenues generated from open market sales to PJM, an electric power grid operator customer, accounted for 45%, 40% and 53%, respectively, of our total revenues. The modification or termination of our sales relationship with PJM, or the modification or termination of any of PJM’s open market programs in which we participate, including increases to the operational requirements related to the provision of demand response, modifications to the cost, quantity and clearing mechanics related to our participation in capacity auctions or other limitations on our ability to effectively manage our portfolio of demand response capacity, could significantly reduce our future revenues and profit margins and have a material adverse effect on our results of operations and financial condition. For example, the introduction in the PJM market of the summer-only, extended-summer and annual demand response products beginning in the 2014/2015 delivery year could adversely impact our ability to successfully manage our portfolio of demand response capacity in that program and have a material adverse effect on our results of operations and financial condition.

If we fail to obtain favorable prices in the open market programs in which we currently participate or choose to participate in the future, specifically in the PJM market, our revenues, gross profits and profit margins will be negatively impacted.

In open market programs, electric power grid operators and utilities generally seek bids from companies such as ours to provide demand response capacity based on prices offered in competitive bidding. These prices may be subject to volatility due to certain market conditions or other events, and, as a result, the prices offered to us for this demand response capacity may be significantly lower than historical prices. To the extent we are subject to price reductions in certain of the markets in which we currently participate or choose to participate in the future, our revenues, gross profits and profit margins could be negatively impacted. In addition, we may alter our participation in both new markets and in markets in which we currently offer our EIS and related solutions, services and products, including by determining not to participate in open market bids to provide demand response capacity. We also may be subject to reduced capacity prices or be unable to participate in certain open market programs for a period of time to the extent that our bidding strategy fails to produce favorable results. In addition, adverse changes in the general economic and market conditions in the regions in which we provide demand response capacity may result in a reduced demand for electricity, resulting in lower prices for capacity, both demand-side and supply-side, for the foreseeable future, which could materially and adversely affect our results of operations and financial condition.

Unfavorable regulatory decisions, changes to the market rules applicable to the programs in which we currently participate or may participate in the future, and varying regulatory structures in certain regional electric power markets could negatively affect our business and results of operations.

Unfavorable regulatory decisions in markets where we currently operate or choose to operate in the future could significantly and negatively affect our business. For example, in a May 23, 2014 decision by the United States Court of Appeals for the D.C. Circuit, the court held that 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. If the decision is upheld and FERC Order 745 is invalidated, certain revenues earned in connection with our participation in price-based/economic demand response programs may become subject to refund, which could negatively impact our business and results of operations, and these programs may in the future be regulated on a state-by-state basis, the effect of which would be unknown. In addition, in the event the court’s decision is broadened to include capacity or ancillary services markets in which we currently operate or choose to operate in the future, our future revenues and profit margins may be significantly reduced and

 

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our results of operations and financial condition could be negatively impacted. Program or market rules could also be modified to change the design of, or pricing related to a particular demand response program, which may adversely affect our participation in that program or cause us to cease participation in that program altogether, or a demand response program in which we currently participate could be eliminated in its entirety and/or replaced with a new program that is more expensive for us to operate. Any elimination or change in the design of a demand response program, including any supplemental program or market rule, could adversely impact our ability to successfully manage our portfolio of demand response capacity in that program, especially in the PJM market where we continue to have substantial operations, and could have a material adverse effect on our results of operations and financial condition.

Regulators could also modify market rules in certain areas to further limit the use of back-up generators in demand response markets or could implement bidding floors or caps that could lower our revenue opportunities. For example, the Environmental Protection Agency, or the EPA, recently issued a final rule in the National Environmental Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines that will allow emergency generators to participate in emergency demand response programs for up to 100 hours per year. In the event this final rule is challenged, and such challenge results in a decrease to the 100 hour per year limit for, or the elimination of any, participation by emergency generators in emergency demand response programs, some of the demand response capacity reductions that we aggregate from C&I customers willing to reduce consumption from the electric power grid by activating their own back-up generators during demand response events would not qualify as capacity without the addition of certain emissions reduction equipment. If this were to occur, we would have to find alternative sources of capacity to meet our capacity obligations to our electric power grid operator and utility customers. If we were unable to procure additional sources of capacity to meet these obligations, our business and results of operations could be negatively impacted.

The electric power industry is highly regulated. The regulatory structures in regional electricity markets are varied and some regulatory requirements make it more difficult for us to provide some or all of our EIS and related solutions, services and products in those regions. For instance, in some markets, regulated quantity or payment levels for demand response capacity or energy make it more difficult for us to cost-effectively enroll and manage many C&I customers in demand response programs. Further, some markets have regulatory structures that do not yet include demand response as a qualifying resource for purposes of short-term reserve requirements known as ancillary services. As part of our business strategy, we intend to expand into additional regional electricity markets. However, unfavorable regulatory structures could limit the number of regional electricity markets available to us for expansion.

In addition, a buildup of new electric generation facilities or reduced demand for electric capacity could result in excess electric generation capacity in certain regional electric power markets. Excess electric generation capacity and unfavorable regulatory structures could lower the value of demand response services and limit the number of economically attractive regional electricity markets that are available to us for expansion, which could negatively impact our business and results of operations.

We may be subject to governmental or regulatory investigations or audits and may incur significant penalties and fines if found to be in non-compliance with any applicable State or Federal regulation.

While the electric power markets in which we operate are regulated, most of our business is not directly subject to the regulatory framework applicable to the generation and transmission of electricity. However, regulations by FERC related to market design, market rules, tariffs, and bidding rules impact how we can interact with our electric power grid operator and utility customers. In addition, we may be subject to governmental or regulatory investigations or audits from time to time in connection with our participation in certain demand response programs. Any investigation by FERC or any other governmental or regulatory authorities could result in a material adjustment to our historical financial statements and may have a material adverse effect on our results of operations and financial condition. As part of any regulatory investigation or audit, FERC or any other governmental or regulatory entity may review our performance under our utility contracts and open market bidding programs, cost structures, and compliance with applicable laws, regulations and standards. If an investigation or audit uncovers improper or illegal activities, we may be subject to civil and criminal penalties and administrative sanctions, in addition to any negative publicity associated with any such penalties or sanctions, as well as, incur legal and related costs, which could have a material adverse effect on our results of operations and financial condition.

 

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Failure to comply with laws and regulations could harm our business.

We conduct our business in the United States and are expanding internationally in various other countries. We are subject to regulation by various federal, state, local and foreign governmental agencies, including, but not limited to, agencies responsible for monitoring and enforcing employment and labor laws, workplace safety, product safety, environmental laws, consumer protection laws, federal securities laws and tax laws and regulations.

We are subject to the U.S. domestic bribery statute contained in 18 U.S.C. § 201, the U.S. Foreign Corrupt Practices Act of 1977, as amended, and the rules and regulations thereunder (the “FCPA”), the U.S. Travel Act, the U.K. Bribery Act 2010 and possibly other anti-bribery laws, including those that comply with the OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions and other international conventions. Anti-corruption laws are interpreted broadly and generally prohibit our company from authorizing, offering, or providing directly or indirectly, anything of value to foreign government officials (defined broadly) for an improper or corrupt purpose. Certain anti-corruption laws, such as the U.K. Bribery Act 2010, also prohibit private sector or commercial bribery. Certain laws could prohibit us from soliciting or accepting bribes or kickbacks. Our company has direct government interactions and in several cases uses third party representatives, for regulatory compliance, sales and other purposes in a variety of countries. These factors increase our anti-corruption risk profile. We can be held liable for the corrupt activities of our employees, representatives, contractors, partners, agents, acquired entities, and anyone else who interacts with others on our behalf even if we did not authorize such activity. Although we have implemented policies and procedures designed to ensure compliance with anti-corruption laws, there can be no assurance that all of our employees, representatives, contractors, partners, agents and acquired entities will comply with these laws and policies.

Our products and solutions are subject to export controls and import laws and regulations in the jurisdictions in which we conduct business, including the U.S. Export Administration Regulations, U.S. Customs regulations, and various economic and trade sanctions regulations administered by the U.S. Treasury Department’s Office of Foreign Assets Controls and the U.S. Department of State. Exports of our products and solutions must be made in compliance with these laws and regulations. If we fail to comply with these laws and regulations, we and certain of our employees could be subject to substantial civil or criminal penalties, including the possible loss of export or import privileges; fines, which may be imposed on us and responsible employees or managers; and, in extreme cases, the incarceration of responsible employees or managers. Obtaining the necessary authorizations, including any required licenses, for a particular transaction may be time-consuming, is not guaranteed and may result in the delay or loss of sales opportunities. In addition, changes in our products or solutions or changes in applicable export or import laws and regulations may create delays in the introduction and sale of our products and solutions in international markets, prevent our customers with international operations from deploying our products and solutions or, in some cases, prevent the export or import of our products and solutions to certain countries, governments or persons altogether. Any change in export or import laws and regulations, shift in the enforcement or scope of existing laws and regulations, or change in the countries, governments, persons or technologies targeted by such laws and regulations, could also result in decreased use of our products and solutions, or in our decreased ability to export or sell our products and solutions to existing or potential customers with international operations. Any decreased use of our products and solutions or limitation on our ability to export or sell our products and solutions would likely adversely affect our business, financial condition and results of operations.

We incorporate encryption technology into certain of our products and solutions. Various countries regulate the import of certain encryption technology, including through import permitting/licensing requirements, and have enacted laws that could limit our ability to distribute our products and solutions or could limit our customers’ ability to implement our products and solutions in those countries. Encryption products and solutions and the underlying technology may also be subject to export controls restrictions. Governmental regulation of encryption technology and regulation of imports or exports of encryption products, or our failure to obtain required import or export approval for our products and solutions, when applicable, could harm our international sales and adversely affect our revenues. Compliance with applicable regulatory laws and regulations regarding the export of our products and solutions, including with respect to new releases of our solutions, may create delays in the introduction of our products and solutions in international markets, prevent our customers with international operations from deploying our products and solutions throughout their globally-distributed systems or, in some cases, prevent the export of our products and solutions to some countries altogether.

U.S. export controls laws and economic sanctions laws also prohibit the shipment of certain products and services to countries, governments and persons that are subject to U.S. economic embargoes and trade sanctions.

 

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Even though we take precautions to prevent our products and solutions from being shipped or provided to U.S. sanctions targets, our products and solutions could be shipped to those targets or provided to such targets by third-parties despite such precautions. Any such shipment could have negative consequences, including government investigations, penalties and reputational harm. Furthermore, any new embargo or sanctions program, or any change in the countries, governments, persons or activities targeted by such programs, could result in decreased use of our products and solutions, or in our decreased ability to export or sell our products and solutions to existing or potential customers, which would likely adversely affect our business and our financial condition.

Changes in laws that apply to us could result in increased regulatory requirements and compliance costs which could harm our business, financial condition and results of operations. In certain jurisdictions, regulatory requirements may be more stringent than in the United States. Noncompliance with applicable regulations or requirements could subject us to whistleblower complaints, investigations, sanctions, settlements, mandatory product recalls, enforcement actions, disgorgement of profits, fines, damages, civil and criminal penalties or injunctions, suspension or debarment from contracting with certain governments or other customers, the loss of export privileges, multi-jurisdictional liability, reputational harm, and other collateral consequences. If any governmental or other sanctions are imposed, or if we do not prevail in any possible civil or criminal litigation, our business, results of operations and financial condition could be materially harmed. In addition, responding to any action will likely result in a materially significant diversion of management’s attention and resources and an increase in defense costs and other professional fees. Enforcement actions and sanctions could further harm our business, results of operations, and financial condition.

Our international expansion could increase the risk of violations of anti-corruption, export controls, and economic sanctions laws in the future.

As we expand into adjacent markets and introduce new products, failure to comply with new and potentially more burdensome laws and regulations in connection with our expanded offerings may adversely affect our business and results of operations.

As we explore expansion into new and adjacent markets and the introduction of new products, we may experience increased governmental regulation with respect to our expanded offerings. Our failure to comply with any regulations applicable to these expanded offerings could expose us to unexpected liability and governmental proceedings, potentially causing reputational harm and the possibility of a material adverse effect on our business. In addition, the future enactment of more restrictive laws or rules at the federal, state or local level, or, with respect to our international operations, in foreign jurisdictions at the national, provincial, state or other level, could have an adverse impact on our business and operating results.

Efforts to comply with these new regulations may also delay and possibly prevent our entry into adjacent markets or introduction of new products, limit our ability to sell our solution to potential clients, or adversely affect the ability of clients to adopt our solution. Compliance with these laws and regulations may impose added costs on our business, and failure to comply with these or other applicable regulations and requirements could lead to substantial civil or criminal penalties, fines, claims for damages, and could seriously impair our overall business. Failure to comply with such regulations or to manage such risks successfully could limit our growth and adversely affect our business and results of operations.

We face risks related to our expansion into international markets.

We intend to expand our addressable market by continuing to pursue opportunities to provide our EIS and related solutions, services and products in international markets. For example, in the fourth quarter of 2013 we entered into a joint venture in Japan, in the first quarter of 2014 we consummated two separate acquisitions of demand response companies in Germany and Ireland to complement our international operations in Australia, Canada, the United Kingdom and New Zealand and in the second quarter of 2014 we consummated an acquisition of a utility bill management company with a global reach, including in China, India and Brazil. Accordingly, new international markets may require us to respond to new and unanticipated regulatory, marketing, sales and other challenges, including with respect to compliance with anti-corruption laws, including the FCPA and the U.K. Bribery Act 2010. These compliance efforts may be time-consuming and costly, and there can be no assurance that we will be successful in responding to these and other challenges we may face as we enter and attempt to expand in international markets. International operations also entail a variety of other risks, including:

 

    unexpected changes in legislative, regulatory or market requirements of foreign countries;

 

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    currency exchange fluctuations;

 

    longer payment cycles and greater difficulty in accounts receivable collection; and

 

    significant taxes or other burdens of complying with a variety of foreign laws.

International operations are also subject to general geopolitical risks, such as political, social and economic instability and changes in diplomatic and trade relations. One or more of these factors could adversely affect any international operations and result in lower revenue than we expect and could significantly affect our results of operations and financial condition.

We may not be able to identify suitable acquisition candidates or complete acquisitions successfully, which may inhibit our rate of growth, and acquisitions that we complete may expose us to a number of unanticipated operational and financial risks.

In addition to organic growth, we intend to continue to pursue growth through the acquisition of companies or assets that may enable us to enhance our technology and capabilities, expand our geographic market, add experienced management personnel and increase our service offerings. However, we may be unable to implement this growth strategy if we cannot identify suitable acquisition candidates, reach agreement on potential acquisitions on acceptable terms, successfully integrate personnel or assets that we acquire or for other reasons. Our acquisition efforts may involve certain risks, including:

 

    unexpected acquisition costs or liabilities that may cause us to fail to meet our previously stated financial guidance, or the effects of purchase accounting may be different from our expectations;

 

    problems that may arise with our ability to successfully integrate the acquired businesses, which may result in us not operating as effectively and efficiently as expected, and may include:

 

    diversion of management time, as well as a shift of focus from operating the businesses to issues related to integration and administration or inadequate management resources available for integration activity and oversight;

 

    failure to retain and motivate key employees;

 

    failure to successfully manage relationships with customers and suppliers;

 

    failure of customers to accept our new EIS and related solutions, services and products;

 

    failure to effectively coordinate sales and marketing efforts;

 

    failure to combine service offerings quickly and effectively;

 

    failure to effectively enhance acquired technology, applications, services and products or develop new applications, services and products relating to the acquired businesses;

 

    difficulties and inefficiencies in managing and operating businesses in multiple locations or operating businesses in which we have either limited or no direct experience;

 

    difficulties integrating financial reporting systems;

 

    difficulties in the timely filing of required reports with the SEC; and

 

    difficulties in implementing controls, procedures and policies, including disclosure controls and procedures and internal controls over financial reporting, appropriate for a larger public company at companies that, prior to their acquisition, lacked such controls, procedures and policies, which may result in ineffective disclosure controls and procedures or material weaknesses in internal controls over financial reporting;

 

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    difficulties in achieving the expected synergies from an acquisition including taking longer than expected to achieve those synergies;

 

    incurring future impairment charges related to diminished fair value of businesses acquired as compared to the price we paid for them;

 

    restructuring operations or reductions in workforce, which may result in substantial charges to our operations; and

 

    issuance of potentially dilutive equity securities, the incurrence of debt—or contingent liabilities, which could harm our financial condition.

We are currently subject to litigation, the unfavorable outcome of which could have a material adverse effect on our financial condition, results of operations and cash flows.

On May 3, 2013, a purported stockholder of the Company filed a derivative and class action complaint in the United States District Court for the District of Delaware against certain of our officers and directors, as well as the Company as a nominal defendant, alleging breach of fiduciary duty, waste of corporate assets, and unjust enrichment in connection with certain equity grants (awarded in 2010, 2012, and 2013) that allegedly exceeded an annual limit on per-employee equity grants purported to be contained in our 2007 Plan. While we have reached an agreement in principle to settle this matter (as described below in Part II, Item 1, Legal Proceedings), that agreement must be approved by the court and therefore the ultimate outcome of this litigation remains difficult to predict and quantify, and the continued defense against such claims or actions may be costly. There can be no assurance that the agreement in principle to settle this matter will be approved by the court, that our defense of this lawsuit will be successful, or that this claim, in excess of the deductible, will be covered by our insurance. A denial of the claim by the insurance provider or a judgment significantly in excess of our insurance coverage could materially and adversely affect our consolidated financial condition, results of operations and cash flows. In addition, regardless of the outcome of this matter, the matter may continue to divert financial and management resources and result in general business disruption, including that we may suffer from adverse publicity that could harm our reputation and negatively impact our stock price.

Our future profitability is uncertain and we may incur net losses in the future.

As of June 30, 2014, we had an accumulated deficit of $139.2 million. For the six month period ended June 30, 2014, we incurred a net loss of $57.9 million. Although we achieved profitability for the years ended December 31, 2013 and 2010, with net income of $22.1 million and $9.6 million, respectively, we incurred net losses for all other fiscal years since our inception. Our operating losses have historically been driven by start-up costs, costs of developing our technology including new product and service offerings, and operating expenses related to increased headcount and the expansion of the number of MW under our management. As we seek to grow our revenues and customer base, we plan to continue to invest in our business and employee base in order to capitalize on emerging opportunities and expand our EIS and related solutions, services and products, which will require increased operating expenses. Although we believe we will be able to grow our revenues at rates that will allow us to achieve profitability again in the future, these increased operating expenses, as well as other factors, may cause us to incur net losses in the near term.

The success of our business depends in part on our ability to develop new EIS and related solutions, services and products and increase the functionality of our current EIS and related solutions, services and products.

The market for our EIS and related solutions, services and products is characterized by rapid technological changes, frequent new software introductions, Internet-related technology enhancements, uncertain product life cycles, changes in customer demands and evolving industry standards and regulations. We may not be able to successfully develop and market new EIS and related solutions, services and products that comply with present or emerging industry regulations and technology standards. Also, any new or modified regulation or technology standard could increase our cost of doing business.

 

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From time to time, our customers have expressed a need for increased functionality in our EIS and related solutions, services and products. In response, and as part of our strategy to enhance our EIS and related solutions, services and products and grow our business, we plan to continue to make substantial investments in the research and development of new technologies. Our future success will depend in part on our ability to continue to design and sell new, competitive EIS and related solutions, services and products and enhance our existing EIS and related solutions, services and products. Initiatives to develop new EIS and related solutions, services and products will require continued investment, and we may experience unforeseen problems in the performance of our technologies and operational processes, including new technologies and operational processes that we develop and deploy, to implement our EIS and related solutions, services and products. In addition, software addressing our EIS and related solutions, services and products is complex and can be expensive to develop, and new software and software enhancements can require long development and testing periods. If we are unable to develop new EIS and related solutions, services and products or enhancements to our existing EIS and related solutions, services and products on a timely basis, or if the market does not accept our new or enhanced EIS and related solutions, services and products, we will lose opportunities to realize revenues and obtain customers, and our business and results of operations will be adversely affected.

We depend on the electric power industry for revenues and, as a result, our operating results have experienced, and may continue to experience, significant variability due to volatility in electric power industry spending and other factors affecting the electric utility industry, such as seasonality of peak demand and overall demand for electricity.

We derive recurring revenues from the sale of our EIS and related solutions, services and products, directly or indirectly, to the electric power industry. Purchases of our demand response application and services by electric power grid operators or utilities may be deferred, cancelled or otherwise negatively impacted as a result of many factors, including challenging economic conditions, mergers and acquisitions involving these entities, fluctuations in interest rates and increased electric utility capital spending on traditional supply-side resources. In addition, sales of our EIS and related solutions, services and products to electric power grid operator and utility customers may be negatively impacted by changing regulations and program rules, which could have a material adverse effect on our results of operations and financial condition.

Sales of demand response capacity in open market bidding programs are particularly susceptible to variability based on changes in the spending patterns of our electric power grid operator and utility customers and on associated fluctuating market prices for capacity. In addition, peak demand for electricity and other capacity constraints tend to be seasonal. Peak demand in the United States tends to be most extreme in warmer months, which may lead some demand response capacity markets to yield higher prices for demand response capacity or contract for the availability of a greater amount of demand response capacity during these warmer months. As a result, our demand response revenues may be seasonal. For example, in the PJM forward capacity market, which is a market from which we derive a substantial portion of our revenues, we recognize capacity-based revenue from PJM during the third quarter of our fiscal year. This will result in higher revenues in our third quarter as compared to our other fiscal quarters. As a result of this seasonality, we believe that quarter to quarter comparisons of our operating results are not necessarily meaningful and that these comparisons cannot be relied upon as indicators of future performance.

Further, occasional events, such as a spike in natural gas prices or potential decreases in availability, can lead electric power grid operators and utilities to implement short-term calls for demand response capacity to respond to these events, but we cannot be sure that such calls will occur or that we will be in a position to generate revenues when they do occur. In addition, given the current economic slowdown and the related potential reduction in demand for electricity, there can be no assurance that there will not be a corresponding reduction in the implementation of both supply and demand-side resources by electric power grid operators and utilities. We have experienced, and may in the future experience, significant variability in our revenues, on both an annual and a quarterly basis, as a result of these and other factors. Pronounced variability or an extended period of reduction in spending by electric power grid operators and utilities could negatively impact our business and make it difficult for us to accurately forecast our future sales.

The 2013 credit facility contains financial and operating restrictions that may limit our access to credit. If we fail to comply with covenants contained in the 2013 credit facility, we may be required to repay our indebtedness thereunder. In addition, if we fail to extend, renew or replace the 2013 credit facility and we still have letters of

 

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credit issued and outstanding when it matures on April 18, 2015, we will be required to post up to 105% of the value of the letters of credit in cash with the bank to collateralize those letters of credit. Either of these conditions may have a material adverse effect on our liquidity.

Provisions in the 2013 credit facility impose restrictions on our ability to, among other things:

 

    incur additional indebtedness;

 

    create liens;

 

    enter into transactions with affiliates;

 

    transfer assets; make certain acquisitions;

 

    pay dividends or make distributions on, or repurchase, EnerNOC stock;

 

    merge or consolidate;

 

    or undergo a change of control.

In addition, we are required to meet certain financial covenants customary with this type of credit facility, including maintaining minimum free cash flow, minimum unrestricted cash and a minimum specified ratio of current assets to current liabilities. The 2013 credit facility also contains other customary covenants. We may not be able to comply with these covenants in the future. Our failure to comply with these covenants may result in the declaration of an event of default and could cause us to be unable to borrow under the 2013 credit facility. In addition to preventing additional borrowings under the 2013 credit facility, an event of default, if not cured or waived, may result in the acceleration of the maturity of indebtedness outstanding under the 2013 credit facility, which would require us to pay all amounts outstanding. In addition, in the event that we default under the 2013 credit facility while we have letters of credit outstanding, we will be required to post up to 105% of the value of the letters of credit in cash with SVB to collateralize those letters of credit. Furthermore, the 2013 credit facility matures on April 18, 2015. If we fail to extend, renew or replace the 2013 credit facility when it matures, and we still have letters of credit issued and outstanding, we will be required to post up to 105% of the value of the letters of credit in cash with SVB to collateralize those letters of credit.

While we were in compliance with all of the financial covenants under the 2013 credit facility as of December 31, 2013, if an event of default occurs, we may not be able to cure it within any applicable cure period, if at all. If the maturity of our indebtedness is accelerated, we may not have sufficient funds available for repayment or collateralization of our letters of credit. In addition, we may not have the ability to borrow or obtain sufficient funds to replace the accelerated indebtedness on terms acceptable to us, or at all.

The expiration of our existing utility contracts without obtaining renewal or replacement utility contracts, or the termination of any of our existing utility contracts, could negatively impact our business by reducing our revenues and profit margins, thereby having a material adverse effect on our results of operations and financial condition.

We have entered into utility contracts with our electric power grid operator and utility customers in different geographic regions in the United States, as well as in Australia, Canada, New Zealand and the United Kingdom, and are regularly in discussions to enter into new utility contracts with electric power grid operators and utilities. However, there can be no assurance that we will be able to renew or extend our existing utility contracts or enter into new utility contracts on favorable terms, if at all. If, upon expiration, we are unable to renew or extend our existing utility contracts and are unable to enter into new utility contracts, our future revenues and profit margins could be significantly reduced, which could have a material adverse effect on our results of operations and financial condition.

Our existing utility contracts generally contain termination provisions pursuant to which the utility customer can terminate the contract under certain circumstances, including in the event that we fail to comply with the terms or provisions contained therein. In addition, in the event that we breach any of our utility contracts, we may be liable to pay the utility customer an associated fee or penalty payment in connection with such breach. The

 

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termination of any of our existing utility contracts, or any fees or penalties payable by us in connection with a breach of our existing utility contracts, could negatively impact our business by reducing our revenues and profit margins, thereby having a material adverse effect on our results of operations and financial condition.

An increased rate of terminations by our C&I customers, or their failure to renew contracts when they expire, would negatively impact our business by reducing our revenues and requiring us to spend more money to maintain and grow our C&I customer base.

Our ability to provide demand response capacity under our utility contracts and in open market bidding programs depends on the amount of MW that we manage across C&I customers who enter into contracts with us to reduce electricity consumption on demand. If our existing C&I customers do not renew their contracts as they expire, we will need to acquire MW from additional C&I customers or expand our relationships with existing C&I customers in order to maintain our revenues and grow our business. The loss of revenues resulting from C&I customer contract terminations or expirations could be significant, and limiting C&I customer terminations is an important factor in our ability to return to profitability in future periods. If we are unsuccessful in limiting our C&I customer terminations, we may be unable to acquire a sufficient amount of MW or we may incur significant costs to replace MW in our portfolio, which could cause our revenues to decrease and our cost of revenues to increase.

We face pricing pressure relating to electric capacity made available to electric power grid operators and utilities and in the percentage or fixed amount paid to C&I customers for making capacity available, which could adversely affect our results of operations and financial condition.

The rapid growth of the EIS and related solutions, services and products sector is resulting in increasingly aggressive pricing, which could cause the prices in that sector to decrease over time. Our electric power grid operator and utility customers may switch to other EIS and related solutions, services and products providers based on price, particularly if they perceive the quality of our competitors’ products or services to be equal or superior to ours. Continued decreases in the price of demand response capacity by our competitors could result in a loss of electric power grid operator and utility customers or a decrease in the growth of our business, or it may require us to lower our prices for capacity to remain competitive, which would result in reduced revenues and lower profit margins and would adversely affect our results of operations and financial condition. Continued increases in the percentage or fixed amount paid to C&I customers by our competitors for making capacity available could result in a loss of C&I customers or a decrease in the growth of our business. It also may require us to increase the percentage or fixed amount we pay to our C&I customers to remain competitive, which would result in increases in the cost of revenues and lower profit margins and would adversely affect our results of operations and financial condition.

Our business is subject to government regulation and may become subject to modified or new government regulation, which may negatively impact our ability to sell and market our EIS and related solutions, services and products.

While the electric power markets in which we operate are regulated, most of our business is not directly subject to the regulatory framework applicable to the generation and transmission of electricity, with the exception of Celerity, which exports power to the electric power grid and is thus subject to direct regulation by FERC and its regulations related to the sale of wholesale power at market based rates. However, we may become directly subject to the regulation of FERC to the extent we are deemed to own, operate, or control generation used to make wholesale sales of power or provide ancillary services that involve a sale of electric energy or capacity for resale, or the export of power to the electric power grid. In addition, FERC has specified that when a demand response resource makes sales of energy for resale, the resource may become subject to direct regulation by FERC. Although we do not expect any further clarification by FERC of its jurisdiction over demand response activities to have a material adverse effect on our consolidated financial condition, results of operations or cash flows, we may become subject to other new or modified government regulations that could have a material adverse effect on our results of operations and financial condition.

The installation of devices or the activation of electric generators used in providing our EIS and related solutions, services and products may be subject to governmental oversight and regulation under state and local ordinances relating to building codes, public safety regulations pertaining to electrical connections, security

 

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protocols, environmental protection and local and state licensing requirements. In a relatively few instances, we have agreed to own and operate a back-up generator at a C&I customer site for a period of time and to activate the generator when capacity is called for dispatch so that the C&I customer can reduce its consumption of electricity from the electric power grid. These generators are ineligible to participate in demand response programs in certain regions, and in others they may become partly or wholly ineligible to participate in the future or may be compensated less for such participation, thereby reducing our revenues and adversely affecting our financial condition.

In addition, certain of our utility contracts and expansion of existing utility contracts are subject to approval by federal, state, provincial, local, or foreign regulatory agencies. There can be no assurance that such approvals will be obtained or be issued on a timely basis, if at all. Additionally, federal, state, provincial, local or foreign governmental entities may seek to change existing regulations, impose additional regulations or change their interpretation of the applicability of existing regulations. Any modified or new government regulation applicable to our current or future EIS and related solutions, services and products, whether at the federal, state, provincial or local level, may negatively impact the installation, servicing and marketing of, and increase our costs and the price related to, our EIS and related solutions, services and products. In addition, despite our efforts to manage compliance with any other regulations to which we are subject, we may be found to be in non-compliance with such regulations and therefore subject to sanctions, including penalties or fines, which could have a material adverse effect on our business, financial condition and results of operations.

Failure of third parties to manufacture or install quality products or provide reliable services in a timely manner or at all could cause delays in the delivery of our EIS and related solutions, services and products, or could result in a failure to provide accurate data to our electric power grid operator and utility customers, which could damage our reputation, cause us to lose customers and have a material adverse effect on our business results of operations and financial condition.

Our success depends on our ability to provide quality, reliable, and secure EIS and related solutions, services and products in a timely manner, which in part requires the proper functioning of facilities and equipment owned, operated, installed or manufactured by third parties upon which we depend. For example, our reliance on third parties includes:

 

    utilizing components that we or third parties install or have installed at C&I customer sites;

 

    relying on metering information provided by third parties to accurately and reliably provide customer data to our electric power grid operator and utility customers;

 

    outsourcing email notification and cellular and paging wireless communications that are used to notify our C&I customers of their need to reduce electricity consumption at a particular time and to execute instructions to devices installed at our C&I customer sites that are programmed to automatically reduce consumption on receipt of such secure communications; and

 

    outsourcing certain installation and maintenance operations to third-party providers.

Any delays, malfunctions, inefficiencies or interruptions in these products, services or operations could adversely affect the reliability or operation of our EIS and related solutions, services and products, which could cause us to experience difficulty monitoring or retaining current customers and attracting new customers. Any errors in metering information provided to us by third parties, including electric power grid operators and utilities, could also adversely affect the customer data that we provide to our electric power grid operator and utility customers. Such delays and errors could result in an overpayment or underpayment to us and our C&I customers from our electric power grid operator and utility customers, which in some instances may cause us to violate certain market rules and require us to make refunds to our electric power grid operator and utility customers and pay associated penalties or fines. In addition, in such instances our brand, reputation and growth could be negatively impacted.

 

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Our results of operations could be adversely affected if our operating expenses and cost of sales do not correspond with the timing of our revenues.

Most of our operating expenses, such as employee compensation and rental expense for properties, are either relatively fixed in the short-term or incurred in advance of sales. Moreover, our spending levels are based in part on our expectations regarding future revenues. As a result, if revenues for a particular quarter are below expectations, we may not be able to proportionately reduce operating expenses for that quarter. For example, if a demand response event or metering and verification test does not occur in a particular quarter, we may not be able to recognize revenues for the undemonstrated capacity in that quarter. This shortfall in revenues could adversely affect our operating results for that quarter and could cause the market price of our common stock to decline substantially.

We incur significant up-front costs associated with the expansion of the number of MW and the infrastructure necessary to enable those MW. In most of the markets in which we originally focused our growth, we generally begin earning revenues from our MW shortly after enablement. However, in certain forward capacity markets in which we participate or may choose to participate in the future, it may take longer for us to begin earning revenues from MW that we enable, in some cases up to a year after enablement. For example, the PJM forward capacity market, which is a market from which we derive a substantial portion of our revenues, operates on a June to May program-year basis, which means that a MW that we enable after June of each year will typically not be recognized until September of the following year. The up-front costs we incur to expand our MW in PJM and other similar markets, coupled with the delay in receiving revenues from those MW, could adversely affect our operating results and could cause the market price of our common stock to decline substantially.

We operate in highly competitive markets; if we are unable to compete successfully, we could lose market share and revenues.

The market for EIS and related solutions, services and products is fragmented. Some traditional providers of advanced metering infrastructure services have added, or may add, demand response or other EIS and related solutions, services and products to their existing business. We face strong competition from other energy management service providers, both larger and smaller than we are. We also compete against traditional supply-side resources such as natural gas-fired peaking power plants. In addition, utilities and competitive electricity suppliers offer their own EIS and related solutions, services and products, which could decrease our base of potential customers and revenues and have a material adverse effect on our results of operations and financial condition.

Many of our competitors and potential competitors have greater financial resources than we do. Our competitors could focus their substantial financial resources to develop a competing business model or develop products or services that are more attractive to potential customers than what we offer. Some advanced metering infrastructure service providers, for example, are substantially larger and better capitalized than we are and have the ability to combine advanced metering and demand response services into an integrated offering to a large, existing customer base. Our competitors may offer EIS and related solutions, services and products at prices below cost or even for free in order to improve their competitive positions. Any of these competitive factors could make it more difficult for us to attract and retain customers, cause us to lower our prices in order to compete, and reduce our market share and revenues, any of which could have a material adverse effect on our financial condition and results of operations. In addition, we may also face competition based on technological developments that reduce peak demand for electricity, increase power supplies through existing infrastructure or that otherwise compete with our EIS and related solutions, services and products.

If the actual amount of demand response capacity that we make available under our capacity commitments is less than required, our committed capacity could be reduced and we could be required to make refunds or pay penalty fees, which could negatively impact our results of operations and financial condition.

We provide demand response capacity to our electric power grid operator and utility customers either under utility contracts or under terms established in open market bidding programs where capacity is purchased. Under the utility contracts and open market bidding programs, electric power grid operators and utilities make periodic payments to us based on the amount of demand response capacity that we are obligated to make available to them during the contract period, or make periodic payments to us based on the amount of demand response capacity that we bid to make available to them during the relevant period. We refer to these payments as committed capacity payments. Committed capacity is negotiated and established by the utility contract or set in the open market bidding process and is subject to subsequent confirmation by measurement and verification tests or performance in a demand response event. In our open market bidding programs, we offer different amounts of committed capacity to our

 

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electric power grid operator and utility customers based on market rules on a periodic basis. We refer to measured and verified capacity as our demonstrated or proven capacity. Once demonstrated, the proven capacity amounts typically establish a baseline of capacity for each C&I customer site in our portfolio, on which committed capacity payments are calculated going forward and until the next demand response event or measurement and verification test when we are called upon to make capacity available.

Under some of our utility contracts and in certain open market bidding programs, any difference between our demonstrated capacity and the committed capacity on which capacity payments were previously made will result in either a refund payment from us to our electric power grid operator or utility customer or an additional payment to us by such customer. Any refund payable by us would reduce our deferred revenues, but would not impact our previously recognized revenues. If there is a refund payment due to an electric power grid operator or utility customer, we generally make a corresponding adjustment in our payments to the C&I customer or customers who failed to make the appropriate level of capacity available, however we are sometimes unable to do so. In addition, some of our utility contracts with, and open market programs established by, our electric power grid operator and utility customers provide for penalty payments, which could be substantial, in certain circumstances in which we do not meet our capacity commitments, either in measurement and verification tests or in demand response events. Further, because measurement and verification test results for some utility contracts and in certain open market bidding programs establish capacity levels on which payments will be made until the next measurement and verification test or demand response event, the payments to be made to us under these utility contracts and open market bidding programs could be reduced until the level of capacity is established at the next measurement and verification test or demand response event. We could experience significant period-to-period fluctuations in our financial results in future periods due to any refund or penalty payments, capacity payment adjustments, replacement costs or other payments made to our electric power grid operator or utility customers, which could be substantial. We incurred aggregate net penalty payments of $0.8 million, $1.9 million, and $0.7 million during the years ended December 31, 2013, 2012 and 2011, respectively.

Our ability to achieve our committed capacity depends on the performance of our C&I customers, and the failure of these customers to make the appropriate levels of capacity available when called upon could cause us to make refund payments to, or incur penalties imposed by, our electric power grid operator and utility customers.

The capacity level that we are able to achieve is dependent upon the ability of our C&I customers to curtail their energy usage when called upon by us during a demand response event or a measurement and verification test. Certain demand response programs in which we currently participate or choose to participate in the future may have rigorous requirements, making it difficult for our C&I customers to perform when called upon by us. For example, if PJM dispatches a measurement and verification test and our C&I customers fail to perform or perform in a deficient manner, we may be subject to substantial penalties given that we have enrolled a significant number of MW in the PJM demand response market. In the event that our C&I customers are unable to perform or perform at levels below which they agreed to perform, we may be unable to achieve our committed capacity levels and may be subject to the refunds or penalties described in the risk factor above, which could have a material adverse effect on our results of operations and financial condition. The capacity level that we are able to achieve also varies with the electricity demand of targeted equipment, such as heating and cooling equipment, at the time a C&I customer is called to perform. Accordingly, our ability to deliver committed capacity depends on factors beyond our control, such as the temperature and humidity, and then-current electricity use by our C&I customers when those C&I customers are called to perform. The correct operation of, and timely communication with, devices used to control equipment are also important factors that affect available capacity.

If we fail to successfully educate existing and potential electric power grid operator and utility customers regarding the benefits of our EIS and related solutions, services and products or a market otherwise fails to develop for those applications, services and products, our ability to sell our EIS and related solutions, services and products and grow our business could be limited.

Our future success depends on commercial acceptance of our EIS and related solutions, services and products and our ability to enter into additional utility contracts and new open market bidding programs. We anticipate that revenues related to our demand response application and services will constitute a substantial majority of our revenues for the foreseeable future. The market for EIS and related solutions, services and products

 

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in general is relatively new. If we are unable to educate our potential customers about the advantages of our EIS and related solutions, services and products over competing products and services, or our existing customers no longer rely on our EIS and related solutions, services and products, our ability to sell our EIS and related solutions, services and products will be limited. In addition, because the EIS and related solutions, services and products sector is rapidly evolving, we cannot accurately assess the size of the market, and we may have limited insight into trends that may emerge and affect our business. For example, we may have difficulty predicting customer needs and developing EIS and related solutions, services and products that address those needs. Further, we are subject to the risk that the current global economic and market conditions will result in lower overall demand for electricity in the United States and other markets that we are seeking to penetrate over the next few years. Such a reduction in the demand for electricity could create a corresponding reduction in both supply-and demand-side resources being implemented by electric power grid operators and utilities. If the market for our EIS and related solutions, services and products does not continue to develop, our ability to grow our business could be limited and we may not be able to operate profitably.

We expect to continue to expand our sales and marketing, operations, and research and development capabilities, as well as our financial and reporting systems, and as a result we may encounter difficulties in managing our growth, which could disrupt our operations.

We expect to experience continued growth in the number of our employees and significant growth in the scope of our operations. To manage our anticipated future growth, we must continue to implement and improve our managerial, operational, financial and reporting systems, improve our internal controls, procedures and compliance programs, expand our facilities, and continue to recruit and train additional qualified personnel. All of these measures will require significant expenditures and will demand the attention of management. Due to our limited resources, we may not be able to effectively manage the expansion of our operations, implement sufficient internal controls, procedures or compliance programs, or recruit and adequately train additional qualified personnel. The physical expansion of our operations may lead to significant costs and may divert our management and business development resources. Any inability to manage growth could delay the execution of our business plans or disrupt our operations.

We allocate our operations, sales and marketing, research and development, general and administrative, and financial resources based on our business plan, which includes assumptions about current and future utility contracts and open market programs with electric power grid operator and utility customers, current and future contracts with C&I customers, variable prices in open market programs for demand response capacity, the development of ancillary services markets which enable demand response as a revenue generating resource and a variety of other factors relating to electricity markets, and the resulting demand for our EIS and related solutions, services and products. However, these factors are uncertain. If our assumptions regarding these factors prove to be incorrect or if alternatives to those offered by our EIS and related solutions, services and products gain further acceptance, then actual demand for our EIS and related solutions, services and products could be significantly less than the demand we anticipate and we may not be able to sustain our revenue growth or return to profitability in future periods.

We may require significant additional capital to pursue our growth strategy, but we may not be able to obtain additional financing on acceptable terms or at all.

The growth of our business will depend on substantial amounts of additional capital for posting financial assurances in order to enter into utility contracts and open market bidding programs with electric power grid operators and utilities, and marketing and product development of our EIS and related solutions, services and products. Our capital requirements will depend on many factors, including the rate of our revenue and sales growth, our introduction of new EIS and related solutions, services and products and enhancements to our existing EIS and related solutions, services and products, and our expansion of sales and marketing and product development activities. In addition, we may consider strategic acquisitions of complementary businesses or technologies to grow our business, which could require significant capital and could increase our capital expenditures related to future operation of the acquired business or technology. Because of our historical losses, we do not fit traditional credit lending criteria. Moreover, the financial turmoil affecting the banking system and financial markets in recent years has resulted in a reduction in the availability of credit in the credit markets, which could adversely affect our ability to obtain additional funding. We may not be able to obtain loans or additional capital on acceptable terms or at all.

 

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If we lose key personnel upon whom we are dependent, or if we fail to attract and retain qualified personnel, we may not be able to manage our operations and meet our strategic objectives.

Our continued success depends upon the continued availability, contributions, vision, skills, experience and effort of our senior management, sales and marketing, research and development, and operations teams. We do not maintain “key person” insurance on any of our employees. We have entered into employment agreements with certain members of our senior management team, but none of these agreements guarantees the services of the individual for a specified period of time. All of the employment arrangements with our key personnel, including the members of our senior management team, provide that employment is at-will and may be terminated by the employee at any time and without notice. The loss of the services of any of our key personnel might impede our operations or the achievement of our strategic and financial objectives. We rely on our research and development team to research, design and develop new and enhanced EIS and related solutions, services and products. We rely on our operations team to install, test, deliver and manage our EIS and related solutions, services and products. We rely on our sales and marketing team to sell our EIS and related solutions, services and products to our customers, build our brand and promote our company. The loss or interruption of the service of members of our senior management, sales and marketing, research and development, or operations teams, or our inability to attract or retain other qualified personnel or advisors could have a material adverse effect on our business, financial condition and results of operations and could significantly reduce our ability to manage our operations and implement our strategy.

An inability to protect our intellectual property could negatively affect our business and results of operations.

Our ability to compete effectively depends in part upon the maintenance and protection of the intellectual property related to our EIS and related solutions, services and products. We hold a few patents and numerous trademarks and copyrights. Patent protection is unavailable for certain aspects of the technology and operational processes that are important to our business. Any patent held by us or to be issued to us, or any of our pending patent applications, could be challenged, invalidated, unenforceable or circumvented. Moreover, some of our trademarks which are not in use may become available to others. To date, we have relied principally on patent, copyright, trademark and trade secrecy laws, as well as confidentiality and proprietary information agreements and licensing arrangements, to establish and protect our intellectual property. However, we have not obtained confidentiality and proprietary information agreements from all of our customers and vendors, and although we have entered into confidentiality and proprietary information agreements with all of our employees, we cannot be certain that these agreements will be honored. Some of our confidentiality and proprietary information agreements may not be in writing, and some customers are subject to laws and regulations that require them to disclose information that we would otherwise seek to keep confidential. Policing unauthorized use of our intellectual property is difficult and expensive, as is enforcing our rights against unauthorized use. The steps that we have taken or may take may not prevent misappropriation of the intellectual property on which we rely. In addition, effective protection may be unavailable or limited in jurisdictions outside the United States, as the intellectual property laws of foreign countries sometimes offer less protection or have onerous filing requirements. From time to time, third parties may infringe our intellectual property rights. Litigation may be necessary to enforce or protect our rights or to determine the validity and scope of the rights of others. Any litigation could be unsuccessful, cause us to incur substantial costs, divert resources away from our daily operations and result in the impairment of our intellectual property. Failure to adequately enforce our rights could cause us to lose rights in our intellectual property and may negatively affect our business.

We may be subject to damaging and disruptive intellectual property litigation related to allegations that our EIS and related solutions, services and products infringe on intellectual property held by others, which could result in the loss of use of those applications, services and products.

Third-party patent applications, patents and other intellectual property rights may relate to our EIS and related solutions, services and products. As a result, third-parties may in the future make infringement and other allegations that could subject us to intellectual property litigation relating to our EIS and related solutions, services and products, which litigation could be time-consuming and expensive, divert attention and resources away from our daily operations, impede or prevent delivery of our EIS and related solutions, services and products, and require us to pay significant royalties, licensing fees and damages. In addition, parties making infringement and other claims may be able to obtain injunctive or other equitable relief that could effectively block our ability to provide our EIS and related solutions, services and products and could cause us to pay substantial damages. In the event of a successful claim of infringement, we may need to obtain one or more licenses from third parties, which may not be available on reasonable terms, or at all.

The use of open source software in our systems and technology may expose us to additional risks and harm our intellectual property.

Our information technology and other systems include software that is subject to open source licenses. While we monitor the use of all open source software in our EIS and related solutions and take certain measures to ensure that no open source software is used or distributed in such a way as to subject our EIS or related solutions to any unanticipated conditions or restrictions, such use or distribution could inadvertently occur. In the event that any of our EIS or related solutions were determined to be subject to an open source license, whether through our own incorporation of software or through licensed software from a third-party provider, we could be required to release the affected portions of our source code publicly, make portions of such applications available under open source licenses, re-engineer all, or a portion of, such applications or otherwise be limited in the licensing of our EIS or related solutions, each of which could reduce or eliminate the value of our EIS and related solutions, services and products. Many of the risks associated with usage of open source software cannot be eliminated, and could negatively affect our business, results of operations and financial condition.

 

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If our information technology systems fail to adequately gather, assess and protect data used in providing our EIS and related solutions, services and products, or if we experience an interruption in their operation, our business, financial condition and results of operations could be adversely affected.

The efficient operation of our business is dependent on our information technology systems. We rely on our information technology systems to effectively control the devices which enable our EIS and related solutions, services and products, gather and assess data used in providing our EIS and related solutions, services and products, manage relationships with our customers, and maintain our research and development data. The failure of our information technology systems to perform as we anticipate could disrupt our business and product development and make us unable, or severely limit our ability, to respond to demand response events. In addition, our information technology systems are vulnerable to damage or interruption from:

 

    earthquake, fire, flood and other natural disasters;

 

    terrorist attacks and attacks by computer viruses or hackers;

 

    power loss; and

 

    computer systems, Internet, telecommunications or data network failure.

Any interruption in the operation of our information technology systems could result in decreased revenues under our contracts and commitments, reduced profit margins on revenues where fixed payments are due to our C&I customers, reductions in our demonstrated capacity levels going forward, customer dissatisfaction and lawsuits and could subject us to penalties, any of which could have a material adverse effect on our business, financial condition and results of operations.

Any internal or external security breaches involving our EIS and related solutions, services and products, and even the perception of security risks involving our EIS and related solutions, services and products or the transmission of data over the Internet, whether or not valid, could harm our reputation and inhibit market acceptance of our EIS and related solutions, services and products and cause us to lose customers.

We use our EIS and related solutions, services and products to compile and analyze sensitive or confidential information related to our customers. In addition, some of our EIS and related solutions, services and products allow us to remotely control equipment at C&I customer sites. Our EIS and related solutions, services and products rely on the secure transmission of proprietary data over the Internet for some of this functionality. Well-publicized compromises of Internet security, or cyber-attacks, could have the effect of substantially reducing confidence in the Internet as a medium of data transmission. The occurrence or perception of security breaches in our EIS and related solutions, services and products or our customers’ concerns about Internet security or the security of our EIS and related solutions, services and products, whether or not they are warranted, could have a material adverse effect on our business, harm our reputation, inhibit market acceptance of our EIS and related solutions, services and products and cause us to lose customers, any of which could have a material adverse effect on our financial condition and results of operations.

We may come into contact with sensitive consumer information or data when we perform operational, installation or maintenance functions for our customers. Even the perception that we have improperly handled sensitive, confidential information could have a negative effect on our business. If, in handling this information, we fail to comply with privacy or security laws, we could incur civil liability to government agencies, customers and individuals whose privacy is compromised. In addition, third parties may attempt to breach our security or inappropriately use our EIS and related solutions, services and products, particularly as we grow our business, through computer viruses, electronic break-ins and other disruptions. We may also face a security breach or electronic break-in by one of our employees or former employees. If a breach is successful, confidential information may be improperly obtained, and we may be subject to lawsuits and other liabilities.

 

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Global economic and credit market conditions, and any associated impact on spending by electric power grid operators and utilities or on the continued operations of our C&I customers, could have a material adverse effect on our business, operating results, and financial condition.

Volatility and disruption in the global capital and credit markets in recent years have led to a significant reduction in the availability of business credit, decreased liquidity, a contraction of consumer credit, business failures, higher unemployment, and declines in consumer confidence and spending in the United States and internationally. If global economic and financial market conditions deteriorate or remain weak for an extended period of time, numerous economic and financial factors could have a material adverse effect on our business, operating results, and financial condition, including:

 

    decreased spending by electric power grid operators or utilities, or by end-users of electricity, may result in reduced demand for our EIS and related solutions, services and products;

 

    consumer demand for electricity may be reduced, which could result in lower prices for both demand-side and supply-side capacity pursuant to utility contracts and in open market programs with electric power grid operators and utilities;

 

    if C&I customers in our demand response network experience financial difficulty, some may cease or reduce business operations, or reduce their electricity usage, all of which could reduce the number of MW of demand response capacity under our management;

 

    we may be unable to find suitable investments that are safe, liquid, and provide a reasonable return, which could result in lower interest income or longer investment horizons, and disruptions to capital markets or the banking system may also impair the value of investments or bank deposits we currently consider safe or liquid;

 

    if our C&I customers to whom we provide our EIS applications and services experience financial difficulty, it could result in their inability to timely meet their payment obligations to us, extended payment terms, higher accounts receivable, reduced cash flows, greater expense associated with collection efforts, and an increase in charges for uncollectable receivables; and

 

    due to stricter lending standards, C&I customers to whom we offer our supply consulting services may be unable to obtain adequate credit ratings acceptable to electricity suppliers, resulting in increased costs, which might make our supply consulting services less attractive or result in their inability to contract with us for supply consulting services.

Uncertainty about current global economic conditions could also continue to increase the volatility of our stock price.

Enterprise customer and electric power industry customer sales cycles can be lengthy and unpredictable and require significant employee time and financial resources with no assurances that we will realize revenues.

Sales cycles with enterprise customers, electric power grid operator customers and utility customers are generally long and unpredictable. The enterprises, electric power grid operators and utilities that are our potential customers generally have extended budgeting, procurement and regulatory approval processes. They also tend to be risk averse and tend to follow industry trends rather than be the first to purchase new products or services, which can extend the lead time for or prevent acceptance of new products or services such as our EIS and related solutions, services and products. Accordingly, our potential enterprise, electric power grid operator and utility customers may take longer to reach a decision to purchase our software and services. This extended sales process requires the dedication of significant time by our personnel and our use of significant financial resources, with no certainty of success or recovery of our related expenses. It is not unusual for an enterprise, electric power grid operator or utility customer to go through the entire sales process and not accept any proposal or quote. Long and unpredictable sales cycles with enterprise, electric power grid operator and utility customers could have a material adverse effect on our business, financial condition and results of operations.

 

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We are exposed to potential risks and will continue to incur significant costs as a result of the internal control testing and evaluation process mandated by Section 404 of the Sarbanes-Oxley Act of 2002.

We assessed the effectiveness of our internal control over financial reporting as of December 31, 2013 and assessed all deficiencies on both an individual basis and in combination to determine if, when aggregated, they constitute a material weakness. As a result of this evaluation, no material weaknesses were identified.

We expect to continue to incur significant costs, including increased accounting fees and increased staffing levels, in order to maintain compliance with Section 404 of the Sarbanes-Oxley Act. We continue to monitor controls for any weaknesses or deficiencies. No evaluation can provide complete assurance that our internal controls will detect or uncover all failures of persons within the company to disclose material information otherwise required to be reported. The effectiveness of our controls and procedures could also be limited by simple errors or faulty judgments. In addition, as we continue to expand globally, the challenges involved in implementing appropriate internal controls will increase and will require that we continue to improve our internal controls over financial reporting.

In the future, if we fail to complete the Sarbanes-Oxley 404 evaluation in a timely manner, or if our independent registered public accounting firm cannot attest in a timely manner to our evaluation, we could be subject to regulatory scrutiny and a loss of public confidence in our internal controls, which could adversely impact the market price of our common stock. We or our independent registered public accounting firm may identify material weaknesses in internal controls over financial reporting, which also may result in a loss of public confidence in our internal controls and adversely impact the market price of our common stock. In addition, any failure to implement required, new or improved controls, or difficulties encountered in their implementation, could harm our operating results or cause us to fail to meet our reporting obligations.

Our ability to provide security deposits or letters of credit is limited and could negatively affect our ability to bid on or enter into utility contracts or arrangements with electric power grid operators and utilities.

We are increasingly required to provide security deposits in the form of cash to secure our performance under utility contracts or open market bidding programs with our electric power grid operator and utility customers. In addition, some of our electric power grid operator or utility customers require collateral in the form of letters of credit to secure our performance or to fund possible damages or penalty payments resulting from our failure to make available capacity at agreed upon levels or any other event of default by us. Our ability to obtain such letters of credit primarily depends upon our capitalization, working capital, past performance, management expertise and reputation and external factors beyond our control, including the overall capacity of the credit market. Events that affect credit markets generally may result in letters of credit becoming more difficult to obtain in the future, or being available only at a significantly greater cost. As of December 31, 2013, we had $49.2 million of letters of credit outstanding under the 2013 credit facility, leaving $20.8 million available under this facility for additional letters of credit. Furthermore, if it is determined that we are in default of our covenants under the 2013 credit facility, then any amounts outstanding under the 2012 credit facility would become immediately due and payable and we would be required to collateralize with cash any outstanding letters of credit up to 105% of the amounts outstanding.

We may be required, from time to time, to seek alternative sources of security deposits or letters of credit, which may be expensive and difficult to obtain, if available at all. Our inability to obtain letters of credit and, as a result, to bid or enter into utility contracts or arrangements with electric power grid operators or utilities, could have a material adverse effect on our future revenues and business prospects. In addition, in the event that we default under our utility contracts or open market bidding programs with our electric power grid operator and utility customers pursuant to which we have posted collateral, we may lose a portion or all of such collateral, which could have a material adverse effect on our financial condition and results of operations.

Our ability to use our net operating loss carryforwards may be subject to limitation.

Generally, a change of more than 50% in the ownership of a company’s stock, by value, over a three-year period constitutes an ownership change for United States federal income tax purposes. An ownership change may limit a company’s ability to use its net operating loss carryforwards attributable to the period prior to such change. The number of shares of our common stock that we issued in our initial public offering, or IPO, and follow-on

 

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public offerings, together with any subsequent shares of stock we issue, may be sufficient, taking into account prior or future shifts in our ownership over a three-year period, to cause us to undergo an ownership change. As a result, as we earn net taxable income, our ability to use our pre-ownership change net operating loss carryforwards to offset United States federal taxable income may become subject to limitations, which could potentially result in increased future tax liability for us. To date, although we have been able to utilize our net operating loss carryforwards to offset the maximum amount of taxable income allowed by the various tax jurisdictions in which we operate, we may not be able to utilize some or all of these net operating losses in the future.

If the software systems we use in providing our EIS and related solutions, services and products or the manual implementation of such systems produce inaccurate information or is incompatible with the systems used by our customers, it could preclude us from providing our EIS and related solutions, services and products, which could lead to a loss of revenues and trigger penalty payments.

Our software is complex and, accordingly, may contain undetected errors or failures when introduced or subsequently modified. Software defects or inaccurate data may cause incorrect recording, reporting or display of information about the level of demand reduction at a C&I customer site, which could cause us to fail to meet our commitments to have capacity available or could result in an overpayment or underpayment to us and our C&I customers by our electric power grid operator and utility customer. Any such failures could also cause us to be subject to penalty payments to our electric power grid operator and utility customers, cause a reduction in our revenue in the period that any adjustment is identified and result in reductions in capacity payments under utility contracts and open market bidding programs in subsequent periods. In addition, such defects and inaccurate data may prevent us from successfully providing our portfolio of additional EIS and related solutions, services and products, which would result in lost revenues. Software defects or inaccurate data may lead to customer dissatisfaction and our customers may seek to hold us liable for any damages incurred. As a result, we could lose customers, our reputation could be harmed and our financial condition and results of operations could be materially adversely affected.

We currently serve a C&I customer base that uses a wide variety of constantly changing hardware, software applications and operating systems. Building control, process control and metering systems frequently reside on non-standard operating systems. Our EIS and related solutions, services and products need to interface with these non-standard systems in order to gather and assess data and to implement changes in electricity consumption. Our business depends on the following factors, among others:

 

    our ability to integrate our technology with new and existing hardware and software systems, including metering, building control, process control, and distributed generation systems;

 

    our ability to anticipate and support new standards, especially Internet-based standards and building control and metering system protocol languages; and

 

    our ability to integrate additional software modules under development with our existing technology and operational processes.

If we are unable to adequately address any of these factors, our results of operations and prospects for growth could be materially adversely affected.

We may face certain product liability or warranty claims if we disrupt our customers’ networks or applications.

For some of our current and planned applications our software and hardware is integrated with our C&I customers’ networks and software applications. The integration of our software and hardware may entail the risk of product liability or warranty claims based on disruption or security breaches to these networks or applications. In addition, the failure of our software and hardware to perform to customer expectations could give rise to warranty claims against us. Any of these claims, even if without merit, could result in costly litigation or divert management’s attention and resources. Although we carry general liability insurance, our current insurance coverage could be insufficient to protect us from all liability that may be imposed under these types of claims. A material product liability claim may seriously harm our results of operations.

 

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Fluctuations in the exchange rates of foreign currencies in which we conduct our business, in relation to the U.S. dollar, could harm our business and prospects.

We maintain sales and service offices outside the United States. The expenses of our international offices are denominated in local currencies. In addition, our foreign sales may be denominated in local currencies. Fluctuations in foreign currency exchange rates could affect our revenues, cost of revenues and profit margins and could result in exchange losses. In addition, currency devaluation can result in a loss if we hold deposits of that currency. In the last few years we have not hedged foreign currency exposures, but we may in the future hedge foreign currency denominated sales. There is a risk that any hedging activities will not be successful in mitigating our foreign exchange risk exposure and may adversely impact our financial condition and results of operations.

An adverse change in the projected cash flows from our acquired businesses or the business climate in which they operate, including the continuation of the current financial and economic turmoil, could require us to incur an impairment charge, which would have an adverse impact on our operating results.

We periodically review the carrying value of the goodwill and other long-lived assets reflected in our financial statements to determine if any adverse conditions exist or a change in circumstances has occurred that would indicate impairment of the value of these assets. Conditions that would indicate impairment and necessitate a revaluation of these assets include, but are not limited to, a significant adverse change in the business climate or the legal or regulatory environment within which we operate. If the carrying value of an asset is determined to be impaired we will write-down the carrying value of the intangible asset to its fair value in the period identified. We generally calculate fair value as the present value of estimated future cash flows to be generated by the asset using a risk-adjusted discount rate. As of June 30, 2014, we had approximately $131.2 million of goodwill and definite-lived intangible assets, including $39.8 million of goodwill and definite-lived intangible assets from our acquisitions completed to date in fiscal 2014. As of November 30, 2013, which is our annual impairment test date, the fair value of our reporting units exceeded the book value of their corresponding net assets and as such, there was no indication of goodwill impairment. In addition, as of December 31, 2013, we had no indefinite-lived intangible assets. Our market capitalization was greater than the book value of our net assets as of December 31, 2013. We will continue to monitor our market capitalization compared to the book value of our net assets. It is possible that the continuation of the current global financial and economic turmoil could negatively affect our anticipated cash flows, or the discount rate that is applied to valuing those cash flows, which could require an interim impairment test of goodwill or our definite-lived intangible assets. Any impairment test could result in a material impairment charge that would have an adverse impact on our financial condition and results of operations.

Risks Related to Our Common Stock

We expect our quarterly revenues and operating results to fluctuate. If we fail in future periods to meet our publicly announced financial guidance or the expectations of market analysts or investors, the market price of our common stock could decline substantially.

Our quarterly revenues and operating results have fluctuated in the past and may vary from quarter to quarter in the future. Accordingly, we believe that period-to-period comparisons of our results of operations may be misleading. The results of one quarter should not be used as an indication of future performance. We provide public guidance on our expected results of operations for future periods. This guidance is comprised of forward-looking statements subject to risks and uncertainties, including the risks and uncertainties described in this Quarterly Report on Form 10-Q for the second quarter ended June 30, 2014 and in our other public filings and public statements, and is based necessarily on assumptions we make at the time we provide such guidance. Our revenues and operating results may fail to meet our previously stated financial guidance or the expectations of securities analysts or investors in some quarter or quarters. Our failure to meet such expectations or our financial guidance could cause the market price of our common stock to decline substantially.

Our quarterly revenues and operating results may vary depending on a number of factors, including:

 

    demand for and acceptance of our EIS and related solutions, services and products;

 

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    the seasonality of our demand response business in certain of the markets in which we operate, where revenues recognized under certain utility contracts and pursuant to certain open market bidding programs can be higher or concentrated in particular seasons and months;

 

    changes in open market bidding program rules and reductions in pricing for demand response capacity;

 

    delays in the implementation and delivery of our EIS and related solutions, services and products, which may impact the timing of our recognition of revenues;

 

    delays or reductions in spending for EIS and related solutions, services and products by our electric power grid operator or utility customers and potential customers;

 

    the long lead time associated with securing new customer contracts;

 

    the structure of any forward capacity market in which we participate, which may impact the timing of our recognition of revenues related to that market;

 

    the mix of our revenues during any period, particularly on a regional basis, since local fees recognized as revenues for demand response capacity tend to vary according to the level of available capacity in given regions;

 

    the termination or expiration of existing contracts with electric power grid operator, utility and C&I customers;

 

    the potential interruptions of our customers’ operations;

 

    development of new relationships and maintenance and enhancement of existing relationships with customers and strategic partners;

 

    temporary capacity programs that could be implemented by electric power grid operators and utilities to address short-term capacity deficiencies;

 

    the imposition of penalties or the reversal of deferred revenue due to our failure to meet a capacity commitment;

 

    the elimination, modification or flawed design of, or our decision not to participate or to reduce our participation in, any demand response program in which we currently participate;

 

    global economic and credit market conditions; and

 

    increased expenditures for sales and marketing, software development and other corporate activities.

Our stock price has been and is likely to continue to be volatile and the market price of our common stock may fluctuate substantially.

Prior to our IPO, there was not a public market for our common stock. Since our common stock began trading on The NASDAQ Global Market, or NASDAQ, on May 18, 2007 through December 31, 2013, our stock price has fluctuated from a low of $4.80 to a high of $50.50. For the period of December 31, 2013, through August 6, 2014, our stock price fluctuated from a high of $24.35 on May 5, 2014 and a low of $16.85 on January 2, 2014. Furthermore, the stock market has continued to experience significant volatility.

The volatility of stocks for companies in the energy and technology industry often does not relate to the operating performance of the companies represented by the stock. Our stock price is likely to continue to be volatile and subject to significant price and volume fluctuations in response to market and other factors, including:

 

    demand for and acceptance of our management applications, services and products;

 

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    our ability to develop new relationships and maintain and enhance existing relationships with customers and strategic partners;

 

    changes in open market bidding program rules and reductions in pricing for demand response capacity;

 

    the termination or expiration of existing contracts with electric power grid operator, utility and C&I customers;

 

    general market conditions and overall fluctuations in equity markets in the United States;

 

    the elimination, modification or flawed design of, or our decision not to participate or to reduce our participation in, any demand response program in which we currently participate;

 

    introduction of technological innovations or new EIS and related solutions, services or products by us or our competitors;

 

    actual or anticipated variations in quarterly revenues and operating results;

 

    the financial guidance we may provide to the public, any changes in such guidance or our failure to meet such guidance;

 

    changes in estimates or recommendations by securities analysts that cover our common stock;

 

    delays in the implementation and delivery of our EIS and related solutions, services and products, which may impact the timing of our recognition of revenues;

 

    litigation or regulatory enforcement actions;

 

    changes in the regulations affecting our industry in the United States and internationally;

 

    the way in which we recognize revenues and the timing associated with our recognition of revenues;

 

    developments with respect to recent acquisitions, including with respect to expected synergies, and any unforeseen integration costs or impairment charges;

 

    developments or disputes concerning patents or other proprietary rights;

 

    period-to-period fluctuations in our financial results;

 

    the potential interruptions of our customers’ operations;

 

    the seasonality of our demand response business in certain of the markets in which we operate;

 

    failure to secure adequate capital to fund our operations, or the future sale or issuance of equity securities at prices below fair market price or in general;

 

    economic and other external factors or other disasters or crises; and

 

    announcement by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments.

These and other external factors may cause the market price and demand for our common stock to fluctuate substantially, which may limit or prevent investors from readily selling their shares of common stock and may otherwise negatively affect the liquidity of our common stock. In addition, in the past, when the market price of a stock has been volatile, holders of that stock have instituted securities class action litigation against the company that issued the stock. Our stock price has been particularly volatile recently and may continue to be volatile in the near term and we could incur substantial costs defending any lawsuit brought against us by any of our stockholders. Such a lawsuit could also divert the time and attention of our management.

 

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In addition, the sale of substantial amounts of our common stock could adversely impact its price. As of June 30, 2014, we had outstanding 30,618,012 shares of our common stock and options to purchase 822,490 shares of our common stock (of which 807,481 were exercisable as of that date). We also had outstanding 250,382 unvested restricted stock units as of June 30, 2014.

Provisions of our certificate of incorporation, bylaws and Delaware law, and of some of our employment arrangements, may make an acquisition of us or a change in our management more difficult and could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Certain provisions of our certificate of incorporation and bylaws could discourage, delay or prevent a merger, acquisition or other change of control that stockholders may consider favorable, including transactions in which we may have otherwise received a premium on our shares of common stock. These provisions also could limit the price that investors might be willing to pay in the future for shares of our common stock, thereby depressing the market price of our common stock. Stockholders who wish to participate in these transactions may not have the opportunity to do so. Furthermore, these provisions could prevent or frustrate attempts by our stockholders to replace or remove our management. These provisions:

 

    allow the authorized number of directors to be changed only by resolution of our board of directors;

 

    require that vacancies on the board of directors, including newly created directorships, be filled only by a majority vote of directors then in office;

 

    establish a classified board of directors, providing that not all members of the board be elected at one time;

 

    authorize our board of directors to issue, without stockholder approval, blank check preferred stock that, if issued, could operate as a “poison pill” to dilute the stock ownership of a potential hostile acquirer to prevent an acquisition that is not approved by our board of directors;

 

    require that stockholder actions must be effected at a duly called stockholder meeting and prohibit stockholder action by written consent;

 

    prohibit cumulative voting in the election of directors, which would otherwise allow holders of less than a majority of stock to elect some directors;

 

    establish advance notice requirements for stockholder nominations to our board of directors or for stockholder proposals that can be acted on at stockholder meetings, which were modified in February 2014;

 

    limit who may call stockholder meetings; and

 

    require the approval of the holders of 75% of the outstanding shares of our capital stock entitled to vote in order to amend certain provisions of our certificate of incorporation and bylaws.

Some of our employment arrangements and equity agreements provide for severance payments and accelerated vesting of benefits, including accelerated vesting of equity awards, upon a change of control. These provisions may discourage or prevent a change of control. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law, which may, unless certain criteria are met, prohibit large stockholders, in particular those owning 15% or more of our outstanding voting stock, from merging or combining with us for a proscribed period of time.

The foregoing provisions could impede a merger, takeover or other business combination involving us or discourage a potential acquirer from making a tender offer for our common stock, which, under certain circumstances, could reduce the market price of our common stock.

 

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We do not intend to pay dividends on our common stock.

We have not declared or paid any cash dividends on our common stock to date, and we do not anticipate paying any dividends on our common stock in the foreseeable future. We currently intend to retain all available funds and any future earnings for use in the development, operation and growth of our business. In addition, the 2013 credit facility prohibits us from paying dividends and future loan agreements may also prohibit the payment of dividends. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements, business opportunities, contractual restrictions and other factors deemed relevant. To the extent we do not pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in our common stock.

If securities or industry analysts do not publish research or publish inaccurate or unfavorable research about our business, our stock price and trading volume could decline.

The trading market for our common stock will continue to depend in part on the research and reports that securities or industry analysts publish about us or our business. If these analysts do not continue to provide adequate research coverage or if one or more of the analysts who covers us downgrades our stock or publishes inaccurate or unfavorable research about our business, our stock price would likely decline. If one or more of these analysts ceases coverage of our company or fails to publish reports on us regularly, demand for our stock could decrease, which could cause our stock price and trading volume to decline.

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and The NASDAQ Stock Market LLC, require significant resources, increase our costs and distract our management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with equity securities listed on NASDAQ, we must comply with statutes and regulations of the SEC and the requirements of NASDAQ. Complying with these statutes, regulations and requirements occupies a significant amount of the time of our board of directors and management and significantly increases our costs and expenses. In addition, as a public company we incur substantial costs to obtain director and officer liability insurance policies. These factors could make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee.

 

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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 second quarter of fiscal 2014:

 

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 March 31, 2014

     —        $ —          —        $ 20,545,298  

April 1, 2014 - April 30, 2014

     37,900        22.10        —          20,545,298  

May 1, 2014 - May 31, 2014

     10,841        23.30        —          20,545,298  

June 1, 2014 - June 30, 2014

     16,883        18.70        —          20,545,298  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total for the second quarter of 2014

     65,624      $ 21.42        —        $ 20,545,298  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) We repurchased 65,624 shares of our common stock in the second quarter of fiscal 2014 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.
(2) Average price paid per share is calculated based on the average price per share related to 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 6, 2013, our board of directors authorized and we publicly announced the repurchase of up to $30 million of our common stock during the twelve month period ending August 6, 2014, unless earlier terminated by the board of directors. In the fourth quarter of 2013, we repurchased 274,663 shares of our common stock at an average price of $16.25 under the $30 million share repurchase plan. There were no repurchases of our common stock in the first or second quarters of fiscal 2014 pursuant to our share repurchase program. The share repurchase program expired on August 6, 2014.

 

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Item 6. Exhibits.

 

10.1@*    EnerNOC, Inc. 2014 Long-Term Incentive Plan and Australian Sub-Plan, and forms of agreement there under.
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 June 30, 2014, formatted in XBRL (Extensible Business Reporting Language): (i) the Unaudited Condensed Consolidated Balance Sheets, (ii) the Unaudited Condensed Consolidated Statements of Income, (iii) the Unaudited Condensed Consolidated Statements of Comprehensive Income, (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.