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ENOC > SEC Filings for ENOC > Form 10-K on 7-Mar-2014All Recent SEC Filings

Show all filings for ENERNOC INC

Form 10-K for ENERNOC INC


7-Mar-2014

Annual Report


Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion and analysis of our financial condition and results of operations together with our "Selected Financial Data" and consolidated financial statements and accompanying notes thereto included elsewhere in this Annual Report on Form 10-K. In addition to the historical information, the discussion contains certain forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those expressed or implied by the forward-looking statements due to applications of our critical accounting policies and factors including, but not limited to, those set forth under the caption "Risk Factors" in Item 1A of Part I of this Annual Report on Form 10-K.

Overview

We are a leading provider of energy intelligence software (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, and our electric power grid operator and utility customers by delivering a comprehensive suite of demand-side management solutions that reduce real-time demand for electricity, increase energy efficiency, improve energy supply transparency in competitive markets and mitigate emissions by providing a suite of software and related solutions that allows our customers to make better and more strategic decisions about how and when they use electricity.

We believe that we are the world's leading provider of demand response applications and solutions. 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.

We provide our utility and grid operator customers with two demand response solutions: EnerNOC Demand Resource and EnerNOC Demand Manager, which we collectively refer to as EnerNOC DemandSMART. 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 C&I customers. We deploy a sales team to contract with our C&I customers and by installing our advanced metering equipment at these customers' sites to connect them to our network, resulting in an increase to our ability to curtail demand from the electric power grid. 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 C&I customer sites, making demand response capacity available to electric power grid operators and utilities on demand while helping C&I customers achieve energy savings, improved financial results and environmental benefits. 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 C&I customers in exchange for those C&I 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. EnerNOC's Demand Manager product consists of long-term contracts with a utility customer for a Software-as-a-Service 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 a leading demand response provider by using our NOC and energy intelligence software platform to deliver a portfolio of additional energy intelligence software and solutions to new and existing C&I, electric power grid operator and utility customers. These additional energy intelligence software and solutions include our EfficiencySMART and SupplySMART applications and solutions, and certain wireless


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energy management products. EfficiencySMART is our data-driven energy efficiency suite that includes energy efficiency planning, audits, assessments, commissioning and retro-commissioning authority services, and a cloud-based energy analytics application used for managing energy across a C&I customer's portfolio of sites. The cloud-based energy analytics application also includes the ability to integrate with a C&I customer's existing energy management system, provide utility bill management and tools for measurement, tracking, analysis, reporting and management of greenhouse gas emissions. SupplySMART is our energy price and risk management application and solution that provides our C&I customers located in restructured or deregulated markets throughout the United States with the ability to more effectively manage the energy supplier selection process, including energy supply product procurement and implementation, budget forecasting, and utility bill management. Our wireless energy management products are designed to ensure that our C&I customers can connect their equipment remotely and access meter data securely, and include both cellular modems and an agricultural specific wireless technology solution.

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 portfolio of energy intelligence software and solutions in several regions throughout the United States, as well as internationally in Australia, Canada, Germany, Ireland, Japan, New Zealand and the United Kingdom.

Use of Non-Financial Business and Operational Data

We utilize certain non-financial business and operational data to provide additional insight into factors and opportunities relevant to our business. This non-financial business and operational data 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 December 31, 2013 and 2012 (amounts rounded to nearest hundred):

                                                December 31, 2012             December 31, 2013
C&I Customers Participating in Demand
Response (1)                                                 5,900                         5,800
C&I Sites Participating in Demand
Response (1)                                                13,500                        13,500
Enterprise-Customers (2)                                       400                           600
Enterprise-Sites (2)                                         2,000                         2,500

(1) The term "C&I Customers Participating in Demand Response" describes the number of our commercial, industrial and institutional customers that 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 commercial, industrial and institutional customer base that actively participate in our demand response programs. Certain of these customers and sites may additionally use our energy intelligence software and 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.

(2) The term "Enterprise-Customers" describes the number of our enterprise customers that separately purchase our energy intelligence software and solutions to gain control of how and when they consume electricity.By extension, the term "Enterprise -Sites" describes the number of sites across our enterprise customer base that separately purchase our energy intelligence software 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. Both Enterprise Customers and Enterprise Sites include SupplySMART contract data.


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The number of C&I customers participating in demand response at December 31, 2013 was approximately 5,800 compared to approximately 5,900 at December 31, 2012. 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 decrease in the number of C&I customers participating in demand response at December 31, 2013 as compared to December 31, 2012 primarily reflects our decision to decrease our participation in the New England market in 2013 due to unfavorable market and policy conditions and offset the aggregate progress we otherwise made in growing the number of C&I customers participating in demand response, particularly in our PJM and Western Australia demand response programs. The number of C&I customer sites participating in demand response at December 31, 2013 was 13,500 which was unchanged compared to December 31, 2012. In general, we expect that the number of C&I customers participating in demand response to increase or decrease in tandem with the number of C&I sites participating in demand response. That may not be the case depending on the density of C&I customers in any geographic market. 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 enterprise customers that have deployed our energy intelligence software and solutions at December 31, 2013 was approximately 600 compared to approximately 400 at December 31, 2012. This increase of approximately 200 enterprise customers reflects our increased efforts to develop our enterprise selling team, the relative success that our enterprise selling team has had in penetrating the market for energy intelligence software and solutions, and the growing need for our solutions with enterprise customers who are increasingly turning to energy intelligence software and solutions to make better and more strategic decisions about the how and when they use electricity. The number of enterprise customer sites that are under the management of our enterprise energy intelligence software and solutions at December 31, 2013 was approximately 2,500 compared to approximately 2,000 at December 31, 2012. The number of enterprise customer sites that are under the management of our enterprise energy intelligence software and solutions has increased in tandem with the increase in enterprise customers. We expect that the number of enterprise customers and enterprise customer sites that use or are managed by our energy intelligence software 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.

Significant Recent Developments

On December 3, 2013, and January 16, 2014, we entered into second and third amendments to our $70 million senior secured revolving credit facility with the several lenders from time to time party thereto and Silicon Valley Bank, or SVB, as administrative agent, swingline lender, issuing lender, lead arranger and book manager, dated April 18, 2013, which we refer to as the 2013 credit facility. We refer to SVB, together with the other lenders, as the Lenders. The second amendment provided for the licensing of intellectual property rights to one of our subsidiaries and the lessening of a restriction on our and our subsidiaries' ability to make certain permitted investments. The third amendment provided for lessening of certain restrictions on our and our subsidiaries' ability to acquire other entities, incur additional indebtedness, enter into transactions with affiliates, transfer assets, and repurchase our common stock. In addition, the third amendment provided for a decrease to the minimum free cash flow financial covenant that we are required to meet.

Revenues and Expense Components

Revenues

We derive recurring revenues from the sale of our energy intelligence software 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.


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Our revenues from our demand response solutions primarily consist of capacity and energy payments, including ancillary services payments, revenues 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 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. 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 an energy payment.

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, as necessary. We recognize demand response capacity revenues when we have provided verification to the electric power grid operator or utility of our ability to deliver the committed capacity under the open market program or utility contract. Committed capacity is verified through the results of an actual demand response event or a measurement and verification test. Once the capacity amount has been verified, the revenues are recognized and future revenues become fixed or determinable and are recognized monthly over the performance period until the next demand response event or measurement and verification test. In subsequent demand response events or measurement and verification tests, if our verified capacity is below the previously verified amount, the electric power grid operator or utility customer will reduce future payments based on the adjusted verified capacity amounts. Under certain utility contracts and open market program participation rules, our performance and related fees are measured and determined over a period of time. If we can reliably estimate our performance for the applicable performance period, we will reserve the entire amount of estimated penalties that will be incurred, if any, as a result of estimated underperformance prior to the commencement of revenue recognition. If we are unable to reliably estimate the performance and any related penalties, we defer the recognition of revenues related to our EnerNOC Demand Resource 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 forward capacity market, which is a market from which we derive a substantial portion of our revenues. Because PJM operates on a June to May program-year basis, a MW that we enable after June of each year may not begin earning revenue until June of the following year. Certain other markets in which we currently participate, such as the Western Australia market and ISO New England, Inc., or ISO-NE, 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 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


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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 30th of each year. Therefore, commencing in fiscal 2012, all demand response capacity revenues related to our participation in the PJM open market program are being recognized at the end of the performance period, or during the three month period ended September 30th 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 recognize 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 30th of each year, that our revenues will typically be higher in the third quarter as compared to any other quarter in our fiscal year. However, 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 could negatively impact our results of operations and financial condition.

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.

Revenues generated from open market sales to PJM accounted for 45%, 40% and 53% respectively, of our total revenues for the years ended December 31, 2013, 2012 and 2011. 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. Our unbilled revenue of $64.6 million from PJM at December 31, 2013, will be billed and collected through June 2014. Our unbilled revenue of $44.9 million as of December 31, 2012 was collected through June 2013.

Revenues generated from our WA demand response program accounted for 12% of our total revenues for the year ended December 31, 2013. Revenues generated from WA accounted for less than 10% of our total revenues for the years ended December 31, 2012 and December 31, 2011.

Revenues generated from open market sales to ISO-NE accounted for less than 10% of our total revenues for the years ended December 31, 2013 and December 31, 2012. Revenues generated from open market sales to ISO-NE accounted for 13% of our total revenues for the year ended December 31, 2011. Other than PJM, WA and ISO-NE, no individual electric power grid operator or utility customers accounted for more than 10% of our total revenues for the years ended December 31, 2013, 2012 and 2011, respectively. If we choose to participate in additional or different markets in the future, or we increase or decrease our participation in the markets in which we currently participate, the contribution of our current electric power grid operator and utility customers to total revenues may 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


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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 3 years or the contract period, commencing upon the enrollment of the C&I customers and delivery of the contracted services.

With respect to our EfficiencySMART and SupplySMART applications and solutions, these generally represent 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, in particular certain EfficiencySMART arrangements with utilities, 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, we sell proprietary equipment to C&I 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 C&I customer relationship period (generally 3 years), once the C&I 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 C&I customer relationship period.

Revenues derived from EfficiencySMART and SupplySMART applications and services, and certain other wireless energy management products were $41.2 million, $33.1 million and $27.5 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Cost of Revenues

Cost of revenues for our demand response solutions primarily consist of amounts owed to our C&I customers for their participation in our EnerNOC Demand Resource network and are generally recognized over the same performance period as the corresponding revenue. We enter into contracts with our C&I customers under which we deliver recurring cash payments to them for the capacity they commit to make available on demand. We also generally make an energy payment when a C&I customer reduces consumption of energy from the electric power grid during a demand response event. The equipment and installation costs for our devices located at our C&I customer sites, which monitor energy usage, communicate with C&I customer sites and, in certain instances, remotely control energy usage to achieve committed capacity are capitalized and depreciated over the lesser of the remaining estimated customer relationship period or the estimated useful life of the equipment, and this depreciation is reflected in cost of revenues. We also include in cost of revenues our amortization of acquired developed technology, amortization of capitalized internal-use software costs related to our DemandSMART application, the monthly telecommunications and data costs we incur as a result of being connected to C&I customer sites, and our internal . . .

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