| Description of Business, Basis of Presentation and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
| Dec. 31, 2014 |
| Accounting Policies [Abstract] | |
| Description of Business | Description of Business |
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| EnerNOC, Inc. (the Company) is the leading provider of energy intelligence software and related solutions. The Company’s enterprise customers use its software to transform how they manage and control energy spend for their organizations, while utilities leverage its software to better engage their customers and meet their demand-side management goals and objectives. |
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| The Company’s EIS and related solutions provide its enterprise customers with a Software-as-a-Service, solution to manage: |
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| • | | energy supplier selection, procurement and implementation; | | | | | | | | | | | | | | | | | | | | | |
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| • | | energy budget forecasting; | | | | | | | | | | | | | | | | | | | | | |
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| • | | utility bills and payment; | | | | | | | | | | | | | | | | | | | | | |
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| • | | facility optimization, including the measurement, tracking, analysis and reporting on greenhouse gas emissions; | | | | | | | | | | | | | | | | | | | | | |
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| • | | project tracking; | | | | | | | | | | | | | | | | | | | | | |
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| • | | demand response, both in open and vertically-integrated markets; and | | | | | | | | | | | | | | | | | | | | | |
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| • | | peak demand and the related cost impact. | | | | | | | | | | | | | | | | | | | | | |
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| The Company’s EIS and related solutions provide its enterprise customers the visibility they need to prioritize resources against the activities that will deliver the highest return on investment. The Company offers its EIS and related solutions to its enterprise customers at four subscription levels: basic, standard, professional, and industrial. The Company delivers its SaaS solutions on all of the major Internet browsers and on leading mobile device operating systems. In addition to its EIS packages, the Company sells two categories of premium professional services, which it refers to as Software Enhancement Services and Energy & Procurement Services. The Company’s Software Enhancement Services help its enterprise customers set their energy management strategy and enhance the effectiveness of EIS deployment. The Company’s Energy and Procurement Services consist of audits, retro-commissioning, and supply procurement consulting. The Company’s target enterprise customers for its EIS and related solutions are organizations that spend approximately $100,000/year or more per site on energy, and the Company sells to these customers primarily through its direct salesforce. |
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| The Company’s EIS for utilities is a SaaS solution that provides utilities with customer engagement, energy efficiency and demand response applications, while improving operational effectiveness. The Company delivers shared value for both the utility and its customers by combining its deep expertise with enterprise customers with energy data analytics, machine learning, and predictive algorithms to deliver segmentation and targeting capabilities that enable utilities to serve their most complex market segments, including commercial, institutional and industrial end-users of energy, and small and medium-sized enterprises. The Company’s EIS and related solutions provide its utility customers with a cost-effective and holistic solution that improves customer satisfaction ratings, delivers savings and consumption reductions to help achieve energy efficiency mandates, manages system peaks and grid constraints, and increases demand for utility-provided products and services. |
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| The Company’s EIS and related solutions for utilities customers and electric power grid operators also include the demand response solutions and applications, EnerNOC Demand Manager™ and EnerNOC Demand Resource™. EnerNOC Demand Manager is a SaaS application that provides utilities with the underlying technology to manage their demand response programs and secure reliable demand-side resources. The Company’s EnerNOC Demand Manager product consists of long-term contracts with a utility customer for a SaaS solution that allows utilities to manage demand response capacity in utility-sponsored demand response programs. This product provides its utility customers with real-time load monitoring, dispatching applications, customizable reports, measurement and verification, and other professional services. The Company’s EnerNOC Demand Resource is a turnkey demand response resource where it matches obligation, in the form of megawatts (MW) that it agrees to deliver to the Company’s utility customers and electric power grid operators, with supply, in the form of MW that it is able to curtail from the electric power grid through its arrangements with its enterprise customers. When the Company is called upon by its utility customers and electric power grid operators to deliver its contracted capacity, the Company uses its Network Operations Center (NOC) to remotely manage and reduce electricity consumption across its growing network of enterprise customer sites, making demand response capacity available to its utility customers and electric power grid operators on demand while helping its enterprise customers achieve energy savings, improve financial results and realize environmental benefits. The Company receives recurring payments from its utility customers and electric power grid operators for providing its EnerNOC Demand Resource and the Company shares these recurring payments with its enterprise customers in exchange for those enterprise customers reducing their power consumption when called upon by the Company to do so. The Company occasionally reallocates and realigns its capacity supply and obligation through open market bidding programs, supplemental demand response programs, auctions or other similar capacity arrangements and third-party contracts to account for changes in supply and demand forecasts, as well as changes in programs and market rules in order to achieve more favorable pricing opportunities. The Company refers to the above activities as managing its portfolio of demand response capacity. |
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| Since inception, the Company’s business has grown substantially. The Company began by providing its demand response solutions in one state in the United States in 2003 and has expanded to providing its EIS and related solutions throughout the United States, as well as internationally in Australia, Brazil, Canada, China, Germany, India, Ireland, Japan, New Zealand, South Korea and the United Kingdom. |
| Reclassifications | Reclassifications |
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| The Company has reclassified certain amounts in its consolidated statements of operations for the years ended December 31, 2013 and 2012 to conform to the 2014 presentation. The reclassifications made relate to the presentation of the Company’s revenues from DemandSMART, EfficiencySMART, and SupplySMART, which were the Company’s classifications of its applications and services, and other revenues to revenues from grid operators, revenues from utilities, and revenues from enterprise customers. This reclassification was done in order to provide the users of the Company’s consolidated financial statements with additional insight into how the Company and its management view and evaluate its revenues and related growth. This reclassification within the consolidated statements of operations for the years ended December 31, 2013 and 2012 had no impact on previously reported total consolidated revenues or consolidated results of operations. |
| Presentational Changes | Presentational Changes |
| The Company has recorded certain adjustments related to the presentation of revenue and cost of revenue in its consolidated statement of operations for the year ended December 31, 2014. The Company has historically recorded revenue and cost of revenues net (as an agent) for certain transactions with enterprise customers and upon further analysis during fiscal 2014, the Company concluded revenue and cost of revenues for these transactions should be recorded gross (as a principal). The Company assessed the materiality of the historical misstatements, individually and in the aggregate, on its prior annual and quarterly consolidated financial statements and concluded the effect of the error was not material to its consolidated financial statements for any of the periods. The Company recorded an adjustment in the consolidated statement of operations for the year ended December 31, 2014 to correct the presentation of such revenues on a year-to-date basis. This correction resulted in an increase to both grid operator revenue and cost of revenue of $4,344 for the year ended December 31, 2014. |
| Basis of Consolidation | Basis of Consolidation |
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| The consolidated financial statements of the Company include the accounts of its wholly-owned subsidiaries and have been prepared in conformity with accounting principles generally accepted in the United States (GAAP). Intercompany transactions and balances are eliminated upon consolidation. |
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| On December 10, 2013, the Company entered into a joint venture with Marubeni Corporation. The new company was formed in January 2014 and named EnerNOC Japan K.K. The Company is the majority-owner and owns 60% of EnerNOC Japan K.K. The remaining 40% represents the non-controlling interest. The Company has evaluated its accounting for its ownership interest and has concluded that it is required to consolidate this entity. |
| Use of Estimates in Preparation of Financial Statements | Use of Estimates in Preparation of Financial Statements |
| The preparation of these consolidated financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, the Company evaluates its estimates, including those related to revenue recognition, allowance for doubtful accounts, valuations and purchase price allocations related to business combinations, fair value of accrued acquisition consideration, expected future cash flows including growth rates, discount rates, terminal values and other assumptions and estimates used to evaluate the recoverability of long-lived assets and goodwill, estimated fair values of intangible assets and goodwill, amortization methods and periods, certain accrued expenses and other related charges, stock-based compensation, contingent liabilities, tax reserves and recoverability of the Company’s net deferred tax assets and related valuation allowance. |
| The Company bases its estimates on historical experience and various other assumptions that it believes to be reasonable under the circumstances. Changes in estimates are recorded in the period in which they become known. Actual results may differ from management’s estimates if these results differ from historical experience or other assumptions prove not to be substantially accurate, even if such assumptions are reasonable when made. |
| Restricted Cash and Cash Equivalents | Restricted Cash and Cash Equivalents |
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| Restricted cash as of December 31, 2014 and 2013 represents cash used to collateralize certain demand response programs and cash used to secure certain insurance commitments. |
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| Cash equivalents are comprised of highly liquid investments with insignificant interest rate risk and maturities of three months or less at the time of acquisition. Investments qualifying as cash equivalents consist of investments in money market funds, excluding restricted cash, which have no withdrawal restrictions or penalties and totaled $225,815 and $145,076 at December 31, 2014 and 2013, respectively. |
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| The Company held no marketable securities as of December 31, 2014 or 2013 or during the years ended December 31, 2014 or 2013. |
| Disclosure of Fair Value of Financial Instruments | Disclosure of Fair Value of Financial Instruments |
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| The Company’s financial instruments mainly consist of cash and cash equivalents, restricted cash, accounts receivable and accounts payable. The carrying amounts of these financial instruments approximate their respective fair value due to their short-term nature. The Company has $160,000 of convertible debt outstanding (See Note 10) as of December 31, 2014. The fair value of this convertible debt was approximately $133,392 as of December 31, 2014 based on the trading prices of the underlying convertible notes as of that date. As of December 31, 2013, the Company had no debt obligations outstanding. |
| Concentrations of Credit Risk | Concentrations of Credit Risk |
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| Financial instruments that potentially subject the Company to significant concentrations of credit risk principally consist of cash and cash equivalents, restricted cash, and accounts receivable and unbilled revenue. The Company maintains its cash and cash equivalent balances with highly rated financial institutions and as a result, such funds are subject to minimal credit risk. |
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| The Company’s significant customers consist of PJM Interconnection (PJM) and Independent Market Operator (IMO). PJM is an electric power grid operator customer in the mid-Atlantic region of the United States that is comprised of multiple utilities and was formed to control the operation of the regional power system, coordinate the supply of electricity, and establish fair and efficient markets. IMO is an entity that was established to administer and operate the Western Australia (WA) wholesale electricity market. The main objectives of the IMO are to coordinate the supply of electricity, encourage competition in the market, establish fair and efficient markets, and ensure economic supply of electricity to customers in WA. The Company performs ongoing credit evaluations of the financial condition of its customers and generally does not require collateral. Although the Company is directly affected by the overall financial condition of the energy industry as well as global economic conditions, the Company does not believe significant credit risk exists as of December 31, 2014. The Company generally has not experienced material losses related to receivables from individual customers or groups of customers. The Company maintains an allowance for doubtful accounts based on accounts past due and historical collection experience. The Company’s losses related to collection of trade receivables have consistently been within the Company’s expectations. Due to these factors, the Company believes no additional credit risk beyond amounts provided for collection losses is probable. |
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| The following table presents the Company’s significant customers. |
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| | Year Ended December 31, | |
| | 2014 | | | 2013 | | | 2012 | |
| | Revenues | | | % of Total | | | Revenues | | | % of Total | | | Revenues | | | % of Total | |
| Revenues | Revenues | Revenues |
| PJM | | $ | 246,405 | | | | 52 | % | | $ | 174,303 | | | | 45 | % | | $ | 111,138 | | | | 40 | % |
| IMO | | $ | 54,930 | | | | 12 | % | | $ | 45,708 | | | | 12 | % | | | * | | | | * | % |
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| * | Represents less than 10% of total revenues | | | | | | | | | | | | | | | | | | | | | | | |
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| No other customers accounted for more than 10% of the Company’s consolidated revenues for the years ended December 31, 2014, 2013 or 2012. |
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| PJM, Southern California Edison Company and IMO were the only customers that each comprised 10% or more of the Company’s accounts receivable balance at December 31, 2014, representing 21%, 17% and 12%, respectively, of such accounts receivable balance. PJM and Southern California Edison Company were the only customers that comprised 10% or more of the accounts receivable balance at December 31, 2013, representing 39%, and 18%, respectively. |
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| Unbilled revenue related to PJM was $96,404 and $64,643 at December 31, 2014 and 2013, respectively. There was no significant unbilled revenue for any other customers at December 31, 2014 and 2013. |
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| Deposits consist of funds to secure performance under certain contracts and open market bidding programs with electric power grid operator and utility customers. |
| Property and Equipment | Property and Equipment |
| Property and equipment, which includes computers, office equipment, software, furniture and fixtures, and back-up generators, is stated at cost and depreciated using the straight-line method over the estimated useful lives of the respective assets, ranging from three to ten years. Demand response equipment is depreciated over the lesser of its useful life or the estimated enterprise customer relationship period, which historically has been approximately three years. Leasehold improvements are amortized over their useful life or the original lease term, whichever is shorter. Expenditures that improve or extend the life of an asset are capitalized while repairs and maintenance expenditures are expensed as incurred. The estimated useful lives, by asset classification, are as follows: |
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| Computers and office equipment | | 3 | | | | | | | | | | | | | | | | | | | | | | |
| Furniture and fixtures | | 5 | | | | | | | | | | | | | | | | | | | | | | |
| Software | | 2 – 5 | | | | | | | | | | | | | | | | | | | | | | |
| Back-up generators | | 5 – 10 | | | | | | | | | | | | | | | | | | | | | | |
| Software Development Costs | Software Development Costs |
| The Company applies the provisions of ASC 350-40, Internal-Use Software (ASC 350-40). ASC 350-40 requires computer software costs associated with internal use software to be expensed as incurred until certain capitalization criteria are met, and it also defines which types of costs should be capitalized and which should be expensed. The Company capitalizes the payroll and payroll-related costs of employees and applicable third-party costs who devote time to the development of internal-use computer software and amortizes these costs on a straight-line basis over the estimated useful life of the software, which is generally two to five years. The Company’s judgment is required in determining the point at which various projects enter the stages at which costs may be capitalized, in assessing the ongoing value and impairment of the capitalized costs, and in determining the estimated useful lives over which the costs are amortized. Internal use software development costs of $5,955, $7,947 and $4,653 during the years ended December 31, 2014, 2013, and 2012, respectively, have been capitalized in accordance with ASC 350-40. Amortization of capitalized software development costs was $6,162, $5,732 and $4,562 for the years ended December 31, 2014, 2013, and 2012, respectively. Accumulated amortization of capitalized software development costs was $27,603 and $21,441 as of December 31, 2014 and 2013, respectively. |
| The costs for the development of new software and substantial enhancements to existing software that is intended to be sold or marketed (external use software) are expensed as incurred until technological feasibility has been established, at which time any additional costs would be capitalized. The Company has determined that technological feasibility of external use software is established at the time a working model of software is completed. Because the Company believes its current process for developing external use software will be essentially completed concurrently with the establishment of technological feasibility, no such costs have been capitalized to date. |
| Impairment of Property and Equipment | Impairment of Property and Equipment |
| The Company reviews long-lived assets, including property and equipment for impairment whenever events or changes in circumstances indicate that the carrying amount of assets may not be recoverable over its remaining estimated useful life. If these assets are considered to be impaired, the long-lived assets are measured for impairment at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets or liabilities. Impairment is recognized in earnings and equals the amount by which the carrying value of the assets exceeds their fair value determined by either a quoted market price, if any, or a value determined by utilizing a discounted cash flow (DCF) technique. If these assets are not impaired, but their useful lives have decreased, the remaining net book value is amortized over the revised useful life. |
| During the years ended December 31, 2014, 2013 and 2012, the Company identified certain impairment indicators related to certain demand response equipment as a result of the removal of such equipment from operational sites during each of these respective years. As such, the equipment had no remaining useful life and no fair value. The remaining net carrying value was written off, resulting in the recognition of impairment charges of $1,071, $706, and $984, respectively, which is included in cost of revenues in the accompanying consolidated statements of operations. |
| Business Combinations | Business Combinations |
| The Company records tangible and intangible assets acquired and liabilities assumed in business combinations under the purchase method of accounting. Amounts paid for each acquisition are allocated to the assets acquired and liabilities assumed based on their fair values at the dates of acquisition. The fair value of identifiable intangible assets is based on detailed valuations that use information and assumptions provided by the Company. The Company estimates the fair value of contingent consideration at the time of the acquisition using all pertinent information known to the Company at the time to assess the probability of payment of contingent amounts. The Company allocates any excess purchase price over the fair value of the net tangible and intangible assets acquired and liabilities assumed to goodwill. |
| The Company primarily uses the income approach to determine the estimated fair value of identifiable intangible assets, including customer relationships, non-compete agreements and trade names. This approach determines fair value by estimating the after-tax cash flows attributable to an in-process project over its useful life and then discounting these after-tax cash flows back to a present value. The Company bases its revenue assumptions on estimates of relevant market sizes, expected market growth rates and expected trends, including introductions by competitors of new EIS and related solutions, services and products. The Company bases the discount rate used to arrive at a present value as of the date of acquisition on the time value of money and market participant investment risk factors. The use of different assumptions could materially impact the purchase price allocation and the Company’s financial condition and results of operations. |
| The Company utilized the cost approach to determine the estimated fair value of acquired intangible assets related to acquired in-process research and development given the stage of development as of the acquisition date and the lack of sufficient information regarding future expected cash flows. The cost approach calculates fair value by calculating the reproduction cost of an exact replica of the subject intangible asset. The Company calculates the replacement cost based on actual development costs incurred through the date of acquisition. In determining the appropriate valuation methodology, the Company considers, among other factors: the in-process projects’ stage of completion; the complexity of the work completed as of the acquisition date; the costs already incurred; the projected costs to complete; the expected introduction date; and the estimated useful life of the technology. The Company believes that the estimated in-process research and development amounts so determined represented the fair value at the date of acquisition and did not exceed the amount a third party would pay for the projects. |
| Intangible Assets | Intangible Assets |
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| The Company amortizes its intangible assets that have finite lives using either the straight-line method or, if reliably determinable, based on the pattern in which the economic benefit of the asset is expected to be consumed utilizing expected undiscounted future cash flows. Amortization is recorded over the estimated useful lives ranging from one to ten years. The Company reviews its intangible assets subject to amortization to determine if any adverse conditions exist or a change in circumstances has occurred that would indicate impairment or a change in the remaining useful life. If the carrying value of an asset exceeds its undiscounted cash flows, the Company will write-down the carrying value of the intangible asset to its fair value in the period identified. In assessing recoverability, the Company must make assumptions regarding estimated future cash flows and discount rates. If these estimates or related assumptions change in the future, the Company may be required to record impairment charges. The Company generally calculates fair value as the present value of estimated future cash flows to be generated by the asset using a risk-adjusted discount rate. If the estimate of an intangible asset’s remaining useful life is changed, the Company will amortize the remaining carrying value of the intangible asset prospectively over the revised remaining useful life. |
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| During the years ended December 31, 2014, 2013 and 2012, the Company did not identify any adverse conditions or change in expected cash flows or useful lives of its definite-lived intangible assets that could indicate the existence of a potential impairment. |
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| The Company had no indefinite-lived intangible assets as of December 31, 2014 and 2013, respectively. |
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| 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. |
| Goodwill | Goodwill |
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| 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 has determined that it currently has 2 reporting units: (1) North America and Utility Bill Management (UBM) operations and (2) the International operations. Events that would indicate impairment and trigger an interim impairment assessment include, but are not limited to, current economic and market conditions, including a decline in market capitalization, a significant adverse change in legal factors, business climate or operational performance of the business, and an adverse action or assessment by a regulator. The Company’s annual impairment test date is November 30 (Impairment Test Date). |
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| In performing the test, the Company utilizes the two-step approach prescribed under ASC 350. The first step requires a comparison of the carrying value of the reporting units to the fair value of these units. The Company considers a number of factors to determine the fair value of a reporting unit, including an independent valuation to conduct this test. The valuation is based upon expected future discounted operating cash flows of the reporting unit as well as analysis of recent sales or offerings of similar companies. The Company bases the discount rate used to arrive at a present value as of the date of the impairment test on its weighted average cost of capital (WACC). If the carrying value of the reporting unit exceeds its fair value, the Company will perform the second step of the goodwill impairment test to measure the amount of impairment loss, if any. The second step of the goodwill impairment test compares the implied fair value of a reporting unit’s goodwill to its carrying value. |
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| In order to determine the fair values of its reporting units, the Company utilizes both a market approach based on the quoted market price of its common stock and the number of shares outstanding and a DCF model under the income approach. The key assumptions that drive the fair value in the DCF model are the discount rates (i.e., WACC), terminal values, growth rates, and the amount and timing of expected future cash flows. If the current worldwide financial markets and economic environment were to deteriorate, this would likely result in a higher WACC because market participants would require a higher rate of return. In the DCF, as the WACC increases, the fair value decreases. The other significant factor in the DCF is its projected financial information (i.e., amount and timing of expected future cash flows and growth rates) and if its assumptions were to be adversely impacted this could result in a reduction of the fair value of the entity. As a result of completing the first step of the impairment assessment on the Impairment Test Date, the fair values (for both reporting units) exceeded the carrying values for both reporting units, and as such, the second step was not required. To date, the Company has not been required to perform the second step of the impairment test. |
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| Any loss resulting from an impairment test would be reflected in operating income (loss) as an impairment expense in the Company’s consolidated statements of operations. The annual impairment testing process is subjective and requires judgment at many points throughout the analysis. If these estimates or their related assumptions change in the future, the Company may be required to record impairment charges for these assets not previously recorded. |
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| The following table shows the change of the carrying amount of goodwill from December 31, 2013 to December 31, 2014: |
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| Balance at December 31, 2013 | | $ | 77,104 | | | | | | | | | | | | | | | | | | | | | |
| Foreign currency translation impact | | | (2,722 | ) | | | | | | | | | | | | | | | | | | | | |
| Acquisitions | | | 41,338 | | | | | | | | | | | | | | | | | | | | | |
| Dispositions | | | (781 | ) | | | | | | | | | | | | | | | | | | | | |
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| Balance at December 31, 2014 | | $ | 114,939 | | | | | | | | | | | | | | | | | | | | | |
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| Income Taxes | Income Taxes |
| The Company uses the asset and liability method for accounting for income taxes. Under this method, the Company determines deferred tax assets and liabilities based on the difference between financial reporting and tax bases of its assets and liabilities. The Company measures deferred tax assets and liabilities using enacted tax rates and laws that will be in effect when the differences are expected to reverse. |
| The Company’s deferred tax assets relate primarily to net operating losses and tax credit carryforwards, intangible assets, deferred revenue, and stock-based compensation. The Company has accumulated consolidated net losses since its inception and, as a result, recorded a valuation allowance against certain of its deferred tax assets. Deferred tax liabilities primarily relate to acquisitions, depreciation of property and equipment, and the convertible debt issued in 2014. |
| ASC 740, Income Taxes (ASC 740), prescribes a recognition threshold and measurement criteria for tax positions taken or expected to be taken in a tax return. ASC 740 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition and defines the criteria that must be met for the benefits of a tax position to be recognized. |
| The Company has $1,794 and $554 of unrecognized tax benefits as of December 31, 2014 and 2013, respectively. |
| In the ordinary course of global business, there are many transactions and calculations where the ultimate tax outcome is uncertain. Judgment is required in determining the Company’s worldwide income tax provision. Although the Company believes its estimates are reasonable, no assurance can be given that the final outcome of tax matters will be consistent with its historical income tax accruals, and the differences could have a material impact on the Company’s income tax provision and operating results in the period in which such determination is made. |
| Industry Segment Information | Industry Segment Information |
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| The Company views its operations and manages its business as one operating segment. Operating segments are defined as components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in making decisions on how to allocate resources and assess performance. The Company’s chief operating decision maker is considered to be its Chief Executive Officer. |
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| The Company operates in the major geographic areas noted in the chart below. The “All other” designation includes revenues from other international locations, primarily consisting of Brazil, Canada, China, Germany, India, Japan, Ireland, New Zealand, South Korea and the United Kingdom. Revenues are based upon customer location and internationally totaled $98,214, $73,738 and $34,211 for the years ended December 31, 2014, 2013 and 2012, respectively. No individual foreign country accounted for more than 10% of the Company’s total revenues for the year ended 2012, and only Australia accounted for more than 10% of the Company’s total revenues for the years ended December 31, 2014 and 2013. |
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| Revenues by geography as a percentage of total revenues are as follows: |
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| | Year Ended December 31, | | | | | | | | | | | | | |
| | 2014 | | | 2013 | | | 2012 | | | | | | | | | | | | | |
| United States | | | 79 | % | | | 81 | % | | | 88 | % | | | | | | | | | | | | |
| Australia | | | 12 | | | | 13 | | | | 8 | | | | | | | | | | | | | |
| All other | | | 9 | | | | 6 | | | | 4 | | | | | | | | | | | | | |
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| Total | | | 100 | % | | | 100 | % | | | 100 | % | | | | | | | | | | | | |
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| As of December 31, 2014 and 2013, the long-lived tangible assets related to the Company’s international subsidiaries were less than 10% of the Company’s long-lived tangible assets and were deemed not material. |
| Revenue Recognition | Revenue Recognition |
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| The Company derives recurring revenues from the sale of its EIS and related solutions. The Company’s customers include grid operators, utilities and enterprises. The Company does not recognize any revenues until persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and collection is deemed to be reasonably assured. In making these judgments, the Company evaluates the following criteria: |
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| • | | 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. | | | | | | | | | | | | | | | | | | | | | |
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| • | | 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. | | | | | | | | | | | | | | | | | | | | | |
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| • | | Fees are fixed or determinable. The Company considers 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 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. | | | | | | | | | | | | | | | | | | | | | |
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| • | | 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. | | | | | | | | | | | | | | | | | | | | | |
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| The Company maintains a reserve for customer adjustments and allowances as a reduction in revenues. In determining the Company’s revenue reserve estimate, the Company relies on historical data and known performance adjustments. These factors, and unanticipated changes in the economic and industry environment, could cause the Company’s reserve estimates to differ from actual results. The Company records a provision for estimated customer adjustments and allowances in the same period as the related revenues are recorded. These estimates are based on the specific facts and circumstances of a particular program, analysis of credit memo data, historical customer adjustments, and other known factors. If the data the Company uses to calculate these estimates does not properly reflect reserve requirements, then a change in the allowances would be made in the period in which such a determination is made and revenues in that period could be affected. The Company’s revenue reserves were $475 as of December 31, 2014 and 2013. During the year ended December 31, 2013, the Company recorded a reduction to its revenue reserves of $125 due to a decline in the overall rate of adjustments. |
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| Revenues from grid operators and revenues from utilities principally represent demand response revenues. During the years ended December 31, 2014, 2013 and 2012, revenues from grid operators and utilities were comprised of $424,537, $342,093 and $244,802, respectively, of demand response revenues. |
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| The Company’s enterprise revenues from the sales of its EIS and related solutions to its enterprise customers generally represent ongoing software or service arrangements under which the revenues are recognized ratably over the same period commencing upon delivery of the EIS and related solutions to the enterprise customer. Under certain of its arrangements, a portion of the fees received may be subject to adjustment or refund based on the validation of the energy savings delivered after the implementation is complete. As a result, The Company defers the portion of the fees that are subject to adjustment or refund until such time as the right of adjustment or refund lapses, which is generally upon completion and validation of the implementation. In addition, under certain other of the Company’s arrangements, the Company sells proprietary equipment to enterprise customers that is utilized to provide the ongoing services that the Company delivers. Currently, this equipment has been determined to not have stand-alone value. As a result, the Company defers revenues associated with the equipment and begins recognizing such revenue ratably over the expected enterprise customer relationship period (generally three years), once the enterprise customer is receiving the ongoing services from the Company. In addition, the Company capitalizes the associated direct and incremental costs, which primarily represent the equipment and third-party installation costs, and recognizes such costs over the expected enterprise customer relationship period. |
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| The Company’s EIS and related solutions for utility customers and electric power grid operators also include the following demand response applications, EnerNOC Demand Manager and EnerNOC Demand Resource. |
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| EnerNOC Demand Resource Solution |
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| The Company’s grid operator revenues and utility revenues primarily reflect the sale of its EnerNOC Demand Resource solution. The revenues primarily consist of capacity and energy payments, including ancillary services payments, as well as payments derived from the effective management of its portfolio, including the Company’s participation in capacity auctions and third-party contracts and ongoing fixed fees for the overall management of utility-sponsored demand response programs. The Company derives revenues from its EnerNOC Demand Resource solution by making demand response capacity available in open market programs and pursuant to contracts that are entered into with electric power grid operators and utilities. In certain markets, the Company enters into contracts with electric power utilities, generally ranging from three to ten years in duration, to deploy its EnerNOC Demand Resource solution. The Company refers to these contracts as utility contracts. |
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| 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. |
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| Commencing in fiscal 2012, all demand response capacity revenues related to the Company’s participation in the PJM open market program for its Limited demand response product (referred to as the PJM summer-only open market program in prior filings) are being recognized at the end of the four-month delivery period of June through September, or during the three month period ended September 30th of each year. Because the period during which the Company is required to perform (June through September) is shorter than the period over which payments are received under the program (June through May), a portion of the revenues that have been earned are recorded and accrued as unbilled revenue. Substantially all revenues related to the PJM open market program were recognized during the three month periods ended September 30, 2014 and September 30, 2013, respectively. As a result of the billing period not coinciding with the revenue recognition period, the Company had $96,404 and $64,643 in unbilled revenues from PJM at December 31, 2014 and December 31, 2013, respectively. |
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| Two new demand response programs were introduced in the PJM market beginning in the 2014/2015 delivery year (June 1, 2014—May 31, 2015): the Extended and Annual demand response programs. Under the PJM Extended program, the delivery period is from June through October and then May in the subsequent calendar year. The revenues and any associated penalties, if any, for underperformance related to participation in the PJM Extended demand response program are separate and distinct from the Company’s participation in other offerings within the PJM open market program. Under the PJM Extended demand response program, penalties incurred as a result of underperformance for a demand response event dispatched during the months of June through September and for a demand response test event are the same as the PJM Limited demand response program service offering that the Company has historically participated in. However, penalties incurred as a result of underperformance for an event dispatched during the month of October or the month of May are 1/52 multiplied by the number of the shortfall amount (committed capacity less actual delivered capacity) times the applicable capacity rate. Consistent with the PJM Limited demand response program, the Company notes that the fees could potentially be subject to adjustment or refund based on performance during the applicable performance period. Due to the lack of historical performance experience with the PJM Extended program, the Company is unable to reliably estimate the amount of fees potentially subject to adjustment or refund as of the end of September. For this reason, revenue from the PJM Extended program will be deferred and recognized at the end of the delivery period (i.e., May). For the PJM Extended demand response delivery period that commenced on June 1, 2014 and ends on May 31, 2015, the potential fees that could be earned are not material, however, for subsequent years beyond the delivery period ending on May 31, 2015, the potential fees from participation in the PJM Extended demand response program could be material. Under the PJM Annual program, the delivery period is from June through May. Consistent with the Limited and Extended programs, revenues from the Annual program will be recognized at the end of the service delivery period. The Company has no MW capacity obligations in the Annual program for the 2014/2015 delivery year. |
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| Demand response capacity revenues related to the Company’s participation in an open market program in Western Australia are potentially subject to refund and therefore, are deferred until a portion of such capacity revenues are reliably estimable which currently occurs upon an emergency event dispatch or until the end of the program period on September 30th. Historically all capacity revenues have been recognized during the three month period ended September 30th as there have previously been no emergency event dispatches. During the three month period ended June 30, 2014, there was an emergency event dispatch in this open market program and as a result, a portion of the capacity revenues were fixed and no longer subject to adjustment. As of September 30, 2014, the Company determined that the amount of fees potentially subject to adjustment or refund was reliably estimable beginning with the new program year in Western Australia commencing on October 1, 2014. Therefore, future revenues will be recognized ratably over the delivery period from October 1 to September 30. |
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| 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 years ended December 31, 2014, 2013 and 2012 the Company recognized $26,460, $25,061, and $10,846, respectively, of energy event revenues. |
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| 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). |
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| The Company has evaluated the factors within ASC 605 regarding gross versus net revenue reporting for its demand response revenues and its payments to enterprise customers. Based on the evaluation of the factors within ASC 605, the Company has determined that all of the applicable indicators of gross revenue reporting were met. The applicable indicators of gross revenue reporting included, but were not limited to, the following: |
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| • | | The Company is the primary obligor in its arrangements with electric power grid operators and utility customers because the Company provides its demand response services directly to electric power grid operators and utilities under long-term contracts or pursuant to open market programs and contracts separately with enterprise customers to deliver such services. The Company manages all interactions with the electric power grid operators and utilities, while enterprise customers do not interact with the electric power grid operators and utilities. In addition, the Company assumes the entire performance risk under its arrangements with electric power grid operators and utility customers, including the posting of financial assurance to assure timely delivery of committed capacity with no corresponding financial assurance received from its enterprise customers. In the event of a shortfall in delivered committed capacity, the Company is responsible for all penalties assessed by the electric power grid operators and utilities without regard for any recourse the Company may have with its enterprise customers. | | | | | | | | | | | | | | | | | | | | | |
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| • | | The Company has latitude in establishing pricing, as the pricing under its arrangements with electric power grid operators and utilities is negotiated through a contract proposal and contracting process or determined through a capacity auction. The Company then separately negotiates payments to enterprise customers and has complete discretion in the contracting process with enterprise customers. | | | | | | | | | | | | | | | | | | | | | |
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| • | | The Company has complete discretion in determining which suppliers (enterprise customers) will provide the demand response services, provided that the enterprise customer is located in the same region as the applicable electric power grid operator or utility. | | | | | | | | | | | | | | | | | | | | | |
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| • | | The Company is involved in both the determination of service specifications and performs part of the services, including the installation of metering and other equipment for the monitoring, data gathering and measurement of performance, as well as, in certain circumstances, the remote control of enterprise customer loads. | | | | | | | | | | | | | | | | | | | | | |
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| As a result, the Company has concluded that it earns revenue (as a principal) from the delivery of demand response services to electric power grid operators and utility customers and records the amounts billed to the electric power grid operators and utility customers as gross demand response revenues and the amounts paid to enterprise customers as cost of revenues. |
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| EnerNOC Demand Manager Solution |
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| With respect to EnerNOC Demand Manager, the Company generally receives an ongoing fee for overall management of the utility demand response program based on enrolled capacity or enrolled enterprise customers, which is not subject to adjustment based on performance during a demand response dispatch. The Company recognizes revenues from these fees ratably over the applicable service delivery period commencing upon when the enterprise customers have been enrolled and the contracted services have been delivered. In addition, under this offering, the Company may receive additional fees for program start-up, as well as, for enterprise customer installations. The Company has determined that these fees do not have stand-alone value due to the fact that such services do not have value without the ongoing services related to the overall management of the utility demand response program and therefore, these fees are recognized over the estimated customer relationship period, which is generally the greater of three years or the contract period, commencing upon the enrollment of the enterprise customers and delivery of the contracted services. |
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| The Company follows the provisions of ASC Update No. 2009-13, Multiple-Deliverable Revenue Arrangements (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. |
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| In certain circumstances, the Company is not able to establish VSOE for all deliverables in a multiple element arrangement. This may be due to the infrequent occurrence of stand-alone sales for an element, a limited sales history for new services or pricing within a broader range than permissible by the Company’s policy to establish VSOE. In those circumstances, the Company proceeds to the alternative levels in the hierarchy of determining selling price. Third Party Evidence (TPE) of selling price is established by evaluating largely similar and interchangeable competitor products or services in stand-alone sales to similarly situated customers. The Company is typically not able to determine TPE and has not used this measure since the Company has been unable to reliably verify stand-alone prices of competitive solutions. Management’s best estimate of selling price (ESP) is established in those instances where neither VSOE nor TPE are available, by considering internal factors such as margin objectives, pricing practices and controls, customer segment pricing strategies and the product life cycle. Consideration is also given to market conditions such as competitor pricing information gathered from experience in customer negotiations, market research and information, recent technological trends, competitive landscape and geographies. Use of ESP is limited to a very small portion of the Company’s services, principally certain other EIS software and related solutions. |
| Cost of Revenues | Cost of Revenues |
| Cost of revenues for the Company’s EIS and related solutions primarily consists of amounts owed to its enterprise customers for their participation in the Company’s demand response network and are generally recognized over the same performance period as the corresponding revenue. The Company enters into contracts with its enterprise customers under which it delivers recurring cash payments to them for the capacity they commit to make available on demand. The Company also generally makes energy payments when an enterprise customer reduces consumption of energy from the electric power grid during a demand response event. The EIS equipment and installation costs for the Company’s devices located at its enterprise customer sites, which monitor energy usage, communicate with enterprise 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. The Company also includes in cost of revenues its amortization of acquired developed technology, amortization of capitalized internal-use software costs related to its EIS and related solutions, the monthly telecommunications and data costs it incurs as a result of being connected to enterprise customer sites, services and products, third-party services, equipment costs, equipment depreciation, its internal payroll and related costs allocated to an enterprise customer site, the wages and associated benefits that it pays to its project managers for the performance of their services, and related costs of revenue related to the delivery of services of its utility bill management solution. Certain costs, such as equipment depreciation and telecommunications and data costs, are fixed and do not vary based on revenues recognized. |
| Research and Development Expenses | Research and Development Expenses |
| Research and development expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to the Company’s 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. Costs incurred in research and development are expensed as incurred. |
| Stock-Based Compensation | Stock-Based Compensation |
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| The Company grants share-based awards to employees, non-employees, members of the board and advisory board members. The Company accounts for grants of stock-based compensation in accordance with ASC 718, Stock Compensation (ASC 718). The Company accounts for share-based awards granted to non-employees in accordance with ASC 505-50, Equity Based Payments to Non-Employees, which results in the Company continuing to re-measure the fair value of the non-employee share-based awards until such time as the awards vest. All share-based awards granted, including grants of stock options, restricted stock and restricted stock units, are recognized in the statement of operations based on their fair value as of the date of grant. As of December 31, 2014, the Company had one stock-based compensation plan, which is more fully described in Note 12. |
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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 certain exceptions. The fair value of restricted stock upon which vesting is solely service-based is expensed ratably over the vesting period. With respect to restricted stock where vesting contains certain performance-based vesting conditions, the fair value is expensed based on the accelerated attribution method as prescribed by ASC 718, over the vesting period. With the exception of certain executives whose employment agreements provide for continued vesting in certain circumstances upon departure, if the employee who received the restricted stock leaves the Company prior to the vesting date for any reason, the shares of restricted stock will be forfeited and returned to the Company. |
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| For stock options granted prior to January 1, 2009, the fair value of each option was estimated at the date of grant using a Black-Scholes option-pricing model. For stock options granted on or after January 1, 2009, the fair value of each option has been and will be estimated on the date of grant using a lattice valuation model. The lattice model considers characteristics of fair value option pricing that are not available under the Black-Scholes model. Similar to the Black-Scholes model, the lattice model takes into account variables such as expected volatility, dividend yield rate, and risk free interest rate. However, in addition, the lattice model considers the probability that the option will be exercised prior to the end of its contractual life and the probability of termination or retirement of the option holder in computing the value of the option. For these reasons, the Company believes that the lattice model provides a fair value that is more representative of actual experience and future expected experience than that value calculated using the Black-Scholes model. |
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| A summary of significant assumptions used to estimate the fair value of stock options granted to employees were as follows: |
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| | Year Ended December 31, | | | | | | | | | | | | | |
| | 2014 | | | 2013 | | | 2012 | | | | | | | | | | | | | |
| Risk-free interest rate | | | 2.5 | % | | | 1.8 | % | | | 1.8 | % | | | | | | | | | | | | |
| Vesting term, in years | | | 2.22 | | | | 2.22 | | | | 2.22 | | | | | | | | | | | | | |
| Expected annual volatility | | | 70 | % | | | 75 | % | | | 78 | % | | | | | | | | | | | | |
| Expected dividend yield | | | — | % | | | — | % | | | — | % | | | | | | | | | | | | |
| Exit rate pre-vesting | | | 7.7 | % | | | 7.7 | % | | | 8 | % | | | | | | | | | | | | |
| Exit rate post-vesting | | | 14.06 | % | | | 14.06 | % | | | 14.06 | % | | | | | | | | | | | | |
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| The risk-free interest rate is the rate available as of the option date on zero-coupon U.S. Treasury securities with a term equal to the expected life of the option. Volatility measures the amount that a stock price has fluctuated or is expected to fluctuate during a period. The Company calculates volatility using a component of implied volatility and historical volatility to determine the value of share-based payments. The Company has not paid dividends on its common stock in the past and does not plan to pay any dividends in the foreseeable future. In addition, the terms of the 2014 credit facility preclude the Company from paying dividends. The Company periodically evaluates its employee demographics and historical forfeiture experience to determine if its estimated pre-vesting and post-vesting exit rates need to be revised. During the year ended December 31, 2014, the Company did not change its estimated pre-vesting and post-vesting exit rates. The change in estimates during the year ended December 31, 2013 did not have a material impact on the Company’s stock-based compensation expense. |
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| Stock based compensation expense recorded in the consolidated statements of operations was as follows: |
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| | Year Ended December 31, | | | | | | | | | | | | | |
| | 2014 | | | 2013 | | | 2012 | | | | | | | | | | | | | |
| Selling and marketing expenses | | $ | 5,488 | | | $ | 5,829 | | | $ | 4,641 | | | | | | | | | | | | | |
| General and administrative expenses | | | 9,225 | | | | 8,629 | | | | 7,755 | | | | | | | | | | | | | |
| Research and development expenses | | | 1,350 | | | | 1,410 | | | | 1,220 | | | | | | | | | | | | | |
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| Total | | $ | 16,063 | | | $ | 15,868 | | | $ | 13,616 | | | | | | | | | | | | | |
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| Stock-based compensation expense related to share-based awards granted to non-employees was not material for the years ended December 31, 2014, 2013 and 2012. The Company recognized income tax benefits from share-based compensation arrangements of $625, $595 and $0, respectively, during the years ended December 31, 2014, 2013 and 2012. No material compensation expense was capitalized during the years ended December 31, 2014, 2013 and 2012. |
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| Beginning in 2014, the Company’s chief executive officer is required to receive his performance based bonus, if achieved, in shares of common stock. The Company recorded this amount as stock-based compensation expense rateably over the applicable performance and service period in accordance with ASC 718. During the year ended December 31, 2014, the Company recorded $476 of stock-based compensation expense related to this performance based bonus. In accordance with ASC 718, the offsetting credit was recorded to accrued bonus during the year ended December 31, 2014. In Q1 2015, the Company will reduce the accrued bonus with an offsetting credit to APIC when the shares are issued. |
| Foreign Currency Translation | Foreign Currency Translation |
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| The financial statements of the Company’s international subsidiaries are translated in accordance with ASC 830, Foreign Currency Matters (ASC 830), into the Company’s reporting currency, which is the United States dollar. The functional currencies of the Company’s subsidiaries in Australia, Brazil, Canada, Germany, Ireland, India, Japan, New Zealand, South Korea and the United Kingdom are the local currencies. |
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| Assets and liabilities are translated to the United States dollar from the local functional currency at the exchange rate in effect at each balance sheet date. Before translation, the Company re-measures foreign currency denominated assets and liabilities, including certain inter-company accounts receivable and payable which have not been deemed a “long-term investment,” as defined by ASC 830, into the functional currency of the respective entity, resulting in unrealized gains or losses recorded in the consolidated statements of operations. Revenues and expenses are translated using average exchange rates during the respective periods. |
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| Foreign currency translation adjustments are recorded as a component of stockholders’ equity within accumulated other comprehensive loss. (Losses) gains arising from transactions denominated in foreign currencies and the remeasurement of certain intercompany receivables and payables are included in other (expense) income, net on the consolidated statements of operations and were ($4,417), ($1,732), and $1,106 for the years ended December 31, 2014, 2013 and 2012, respectively. |
| Comprehensive Income (Loss) | Comprehensive Income (Loss) |
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| Comprehensive income (loss) is defined as the change in equity of a business enterprise during a period resulting from transactions and other events and circumstances from non-owner sources. The Company’s comprehensive income (loss) is composed of net income (loss) and foreign currency translation adjustments. As of December 31, 2014 and 2013, accumulated other comprehensive loss was comprised solely of cumulative foreign currency translation adjustments. The Company presents its components of other comprehensive income (loss), net of related tax effects, which have not been material to date. |
| Recent Accounting Pronouncements | 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 was evaluated in connection with the sale of Utility Solutions Consulting and was deemed immaterial to its consolidated financial statements. |
| In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers(ASU 2014-09. ASU 2014-09 provides guidance for revenue recognition and the standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. The new guidance is effective for annual and interim periods beginning after December 15, 2016, with no early adoption permitted. Therefore, ASU No 2014-09 will be effective for the Company beginning in the first quarter of fiscal year 2017, and allows for full retrospective adoption applied to all periods presented or retrospective adoption with the cumulative effect of initially applying this update recognized at the date of initial application. The Company has not yet determined the method of adoption. The Company is currently in the process of evaluating the impact of adoption of this ASU on its consolidated financial position and results of operations. |
| Disposal Cost Obligations | In June 2012, the Company exercised its termination option under the former lease for its corporate headquarters at 75-101 Federal Street, Boston, Massachusetts (the Old Lease) and provided notice of its election to terminate the Old Lease effective as of June 30, 2013. As a result of its election to terminate the Old Lease, the Company was required to make a lease termination payment of $1,146 of which $573 was paid upon exercise of the election to terminate and the remaining $573 was paid in June 2013. In accordance with ASC 420, Exit or Disposal Cost Obligations, the Company recorded the fair value of this lease termination expense of $1,146 within general and administrative expenses during 2012. |
| Leases | In July 2012, the Company entered into a lease for its new corporate headquarters at One Marina Park Drive, Floors 4-6, Boston, Massachusetts (the New Lease). The New Lease term is through July 2020 and the New Lease contains both a rent holiday period and escalating rental payments over the New Lease term. The New 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 New 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. During the year ended December 31, 2013, the Company recorded $4,919 as deferred rent related to landlord lease incentives. 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 New 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 December 31, 2014, the Company’s asset retirement obligation totaled $421. |
