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ENOC > SEC Filings for ENOC > Form 10-Q on 7-Aug-2013All Recent SEC Filings

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Form 10-Q for ENERNOC INC


7-Aug-2013

Quarterly Report


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

The following discussion should be read in conjunction with our unaudited condensed consolidated financial statements and related notes thereto included elsewhere in this Quarterly Report on Form 10-Q, as well as our audited financial statements and notes thereto and Management's Discussion and Analysis of Financial Condition and Results of Operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2012, as filed with the Securities and Exchange Commission, or the SEC, on February 27, 2013, or our 2012 Form 10-K. This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Without limiting the foregoing, the words "may," "will," "should," "could," "expect," "plan," "intend," "anticipate," "believe," "estimate," "predict," "potential," "continue," "target" and variations of those terms or the negatives of those terms and similar expressions are intended to identify forward-looking statements. All forward-looking statements included in this Quarterly Report on Form 10-Q are based on current expectations, estimates, forecasts and projections and the beliefs and assumptions of our management including, without limitation, our expectations regarding our results of operations, operating expenses and the sufficiency of our cash for future operations. We assume no obligation to revise or update any such forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of certain important factors, including those set forth below under this Item 2-"Management's Discussion and Analysis of Financial Condition and Results of Operations," Part II, Item 1A-"Risk Factors" and elsewhere in this Quarterly Report on Form 10-Q, as well as in our 2012 Form 10-K and Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013, as filed with the SEC on May 7, 2013, or our 2013 First Quarter 10-Q. You should carefully review those factors and also carefully review the risks outlined in other documents that we file from time to time with the SEC.

Overview

We are a leading provider of energy intelligence software 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 customers, and our electric power grid operator and utility customers by delivering a comprehensive suite of demand-side management services that reduce real-time demand for electricity, increase energy efficiency, improve energy supply transparency in competitive markets, and mitigate emissions.

We believe that we are the world's leading provider of demand response applications and services. Demand response is an alternative to traditional 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.

In providing our demand response services, 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 increase our ability to curtail demand from the electric power grid by deploying a sales team to contract with our C&I customers and by installing our equipment at these customers' sites to connect them to our network. When we are called upon by our utility or electric power grid operator customers to deliver MW, we use our Network Operations Center, or NOC, and our comprehensive demand response application, DemandSMART, to remotely manage and reduce electricity consumption across a 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 managing demand response capacity 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.

We build on our position as a leading demand response services provider by using our NOC and energy management application platform to deliver a portfolio of additional energy management applications, services and products to new and existing C&I, electric power grid operator and utility customers. These additional energy management applications, services and products include our EfficiencySMART and SupplySMART applications and services, and certain wireless 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


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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 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 demand response services in one state in 2003 and have expanded to providing our portfolio of energy management applications, services and products in several regions throughout the United States, as well as internationally in Australia, Canada, New Zealand and the United Kingdom.

Significant Recent Developments

At our 2013 Annual Meeting of Stockholders held on May 28, 2013, our stockholders approved an amendment and restatement of our Amended and Restated 2007 Employee, Director and Consultant Stock Plan, which we refer to as the 2007 Plan, to, among other things, increase the shares available for issuance under the 2007 Plan by 2,500,000 shares.

On June 3, 2013, David Samuels, our former Executive Vice President, notified us that he was resigning as an officer effective June 11, 2013 in order to pursue another professional opportunity.

On August 2, 2013, we entered into an amendment 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. This amendment provides for an increase to the maximum amount that we can spend to repurchase or redeem shares of our common stock held by our stockholders without the consent of SVB.

On August 2, 2013, Kevin J. Bligh notified us that he was resigning as our Chief Accounting Officer and principal accounting officer, effective November 29, 2013. Mr. Bligh will remain employed by us as a special advisor to the Chief Financial Officer until on or about June 2, 2014 in order to assist us in an orderly transition.

On August 6, 2013, our board of directors authorized the repurchase of up to $30 million of our common stock during the twelve month period ending August 6, 2014, unless earlier terminated by the board of directors. We have not made any repurchases to date.

Revenues and Expense Components

Revenues

We derive recurring revenues from the delivery of our energy management applications, services and products. We do not recognize any revenues until persuasive evidence of an arrangement exists, delivery has occurred, the fee is fixed or determinable, and we deem collection to be reasonably assured.

Our revenues from our demand response services primarily consist of capacity and energy payments, including ancillary services payments, and revenues derived from the effective management of our portfolio of demand response capacity, including our participation in capacity auctions and bilateral contracts. We derive revenues from demand response capacity that we make 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 demand response services. We refer to these contracts as utility contracts.

Where we operate in open market programs, our revenues from demand response capacity payments may vary from 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 as necessary. We recognize demand response capacity revenues when we have provided verification to the electric power grid operator or utility of


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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 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.

In the PJM Interconnection, or 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 performance during the months of July through September. Based on changes to certain PJM program rules during the year ended December 31, 2012, or fiscal 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 recognized at the end of the performance period, or during the three months 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 demand response program during the three months 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.

Under certain utility contracts and open market programs, such as PJM's Emergency Load Response Program, the period during which we are required to perform may be shorter than the period over which we receive payments under that contract or program. In these cases, we record revenue, net of reserves for estimated penalties related to potential delivered capacity shortfalls, over the mandatory performance obligation period, and a portion of the revenues that have been earned is recorded and accrued as unbilled revenue. Due to the fact the demand response capacity revenues related to the PJM Emergency Load Response Program are not recognized until the three months ended September 30th of each year, there were no material unbilled revenues as of June 30, 2013.

Fees received from the reallocation or realignment of our capacity supply and obligation through 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, are recognized as revenues as they become due and payable with such fees being recorded as a component of DemandSMART revenues.

Revenues generated from open market sales to ISO New England, Inc., or ISO-NE, accounted for approximately 13% and 20% of our total revenues for the three month periods ended June 30, 2013 and 2012, respectively. Revenues generated from open market sales to ISO-NE accounted for approximately 14% and 22% of our total revenues for the six month periods ended June 30, 2013 and 2012, respectively. Other than ISO-NE, no individual electric power grid operator or utility customer accounted for more than 10% of our total revenues for the three and six month periods ended June 30, 2013 and 2012. We expect revenues generated from sales to ISO-NE to decline as a percentage of total revenues for the foreseeable future as a result of our reduction in capacity supply obligations in this market and re-alignment of our resources. 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 our EfficiencySMART and SupplySMART applications and services, these applications and services generally represent ongoing service arrangements where the revenues are recognized ratably over the service period commencing upon delivery


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of the contracted service to the customer. Under certain of our arrangements, in particular certain EfficiencySMART arrangements with our utility customers, a portion of the fees received may be subject to adjustment or refund based on the validation of the energy savings delivered after the implementation is complete. As a result, we defer the portion of the fees that are subject to adjustment or refund until such time as the right of adjustment or refund lapses, which is generally upon completion and validation of the implementation. In addition, under certain of our other arrangements, in particular those arrangements entered into by our wholly-owned subsidiary M2M Communications Corporation, or M2M, we sell proprietary equipment to C&I customers that is utilized to provide the ongoing services that we deliver. Currently, this equipment has been determined to not have stand-alone value. As a result, we defer the fees associated with the equipment and begin recognizing those fees ratably over the expected C&I customer relationship period, which is generally three years, once the C&I customer is receiving the ongoing services from us. In addition, we capitalize the associated direct and incremental costs, which primarily represent the equipment and third-party installation costs, and recognize such costs over the expected C&I customer relationship period.

Cost of Revenues

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

We defer incremental direct costs related to the acquisition or origination of a utility contract or open market program in a transaction that results in the deferral or delay of revenue recognition. As of June 30, 2013 and December 31, 2012, we had no deferred incremental direct costs related to the acquisition or origination of a utility contract or open market program and during the three and six month periods ended June 30, 2013 and 2012, no contract origination costs were deferred. In addition, we defer incremental direct costs incurred related to customer contracts where the associated revenues have been deferred as long as the deferred incremental direct costs are deemed realizable. During the three month periods ended June 30, 2013 and 2012, we deferred $10.9 million and $8.0 million, respectively, of incremental direct costs associated with customer contracts. During the six month periods ended June 30, 2013 and 2012, we deferred $17.2 million and $10.7 million, respectively, of incremental direct costs associated with customer contracts. These deferred expenses will be expensed in proportion to the related revenue being recognized. The increase in the deferral of incremental costs during the six month period ended June 30, 2013 compared to the same period in 2012 was primarily related to the increase in deferred costs associated with our Western Australia and our PJM demand response programs where the deferred costs will be expensed when the associated revenues are recognized during the three month period ending September 30, 2013. During the three month periods ended June 30, 2013 and 2012, we expensed $1.4 million and $1.1 million, respectively, of deferred incremental direct costs to cost of revenues. During the six month periods ended June 30, 2013 and 2012, we expensed $2.5 million and $1.3 million, respectively, of deferred incremental direct costs to cost of revenues. As of June 30, 2013, there were no material realizability issues related to deferred incremental direct costs. We also capitalize the costs of our production and generation equipment utilized in the delivery of our demand response services and expense these costs over the lesser of the estimated useful life or the term of the contractual arrangement. During the three month periods ended June 30, 2013 and 2012, we capitalized $5.2 million and $2.7 million, respectively, of production and generation equipment costs. During the six month periods ended June 30, 2013 and 2012, we capitalized $7.6 million and $5.2 million, respectively, of production and generation equipment costs. We believe that the above accounting treatments appropriately match expenses with the associated revenues.


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Gross Profit and Gross Margin

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

Operating Expenses

Operating expenses consist of selling and marketing, general and administrative, and research and development expenses. Personnel-related costs are the most significant component of each of these expense categories. We grew from 625 full-time employees at June 30, 2012 to 744 full-time employees at June 30, 2013 primarily as a result of our overall growth and expansion into new markets over the past year. In addition, we incur significant up-front costs associated with the expansion of the number of contractual MW, which we expect to continue for the foreseeable future. We expect our overall operating expenses to increase marginally in absolute dollar terms for the foreseeable future as we continue to enable new C&I customer sites and expand the development of our energy management applications, services and products. In addition, amortization expense from intangible assets acquired in possible future acquisitions could potentially increase our operating expenses in future periods. Although we expect an increase in operating expenses in absolute dollar terms through at least the end of fiscal 2015, we expect that operating expenses as a percentage of revenues will decrease as we continue to realize improvements in our operating leverage and overall cost management.

Selling and Marketing

Selling and marketing expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our sales and marketing organization, (b) commissions, (c) travel and other out-of-pocket expenses, (d) marketing programs such as trade shows and
(e) other related overhead. Commissions are recorded as an expense when earned by the employee. We expect an increase in selling and marketing expenses in absolute dollar terms through at least the end of fiscal 2015 as we continue the expansion of our selling and marketing activities into new markets and regions; however, we expect that selling and marketing expenses as a percentage of revenues will decrease for the foreseeable future.

General and Administrative

General and administrative expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards and bonuses, related to our executive, finance, human resource, information technology and operations organizations, (b) facilities expenses,
(c) accounting and legal professional fees, (d) depreciation and amortization and (e) other related overhead. We expect general and administrative expenses to continue to increase in absolute dollar terms through at least the end of fiscal 2015 as we invest in infrastructure to support our continued growth; however, we expect that general and administrative expenses as a percentage of revenues will decrease for the foreseeable future.

Research and Development

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