Advertise with us
[August 08, 2012]
ENERNOC INC - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations.
(Edgar Glimpses Via Acquire Media NewsEdge) 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, 2011, as filed with the Securities and Exchange Commission, or the SEC, on March 15, 2012 and as amended on April 17, 2012, or our 2011 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 2011 Form 10-K. You should carefully review those factors and also carefully review the risks outlined in other documents that we file from time to time with the SEC.
Overview We are a leading provider of energy management applications, services and products for the smart grid, which include comprehensive demand response, data-driven energy efficiency, energy price and risk management and enterprise carbon management applications, services and products. Our energy management applications, services and products enable cost effective energy management strategies 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 reducing real-time demand for electricity, increasing energy efficiency, improving energy supply transparency, and mitigating carbon emissions.
We believe that we are the largest demand response service provider to C&I customers. As of June 30, 2012, we managed over 8,300 megawatts, or MW, of demand response capacity across a C&I customer base of approximately 5,600 accounts and approximately 13,000 sites throughout multiple electric power grids. 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. We use our Network Operations Center, or NOC, and 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. To date, we have received substantially all of our revenues from electric power grid operators and utilities, who make recurring payments to us for managing demand response capacity that we share with our C&I customers in exchange for those C&I customers reducing their power consumption when called upon.
In providing our demand response services, we match obligation, in the form of MW that we agree to deliver to our utility and 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 occasionally reallocate our obligation through open market bidding programs, supplemental demand response programs, auctions or other similar capacity arrangements, open program registrations and bilateral contracts to account for changes in supply and demand forecasts in order to achieve more favorable pricing opportunities. 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 grid operator customers to deliver MW, we use our DemandSMART application to dispatch this network to meet the demands of these utility and grid operator customers. 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, SupplySMART, and CarbonSMART applications and services, and certain wireless energy 23 -------------------------------------------------------------------------------- Table of Contents management products. EfficiencySMART is our data-driven energy efficiency suite that includes commissioning and retro-commissioning authority services, energy consulting and engineering services, a persistent commissioning application and an enterprise energy management application for managing energy across a portfolio of sites. 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. CarbonSMART is our enterprise carbon management application that supports and manages the measurement, tracking, analysis, reporting and management of greenhouse gas emissions. 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 acquired as part of our acquisition of M2M Communications Corporation, or M2M, in January 2011.
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 On June 28, 2012, we notified our landlord that we intend to terminate the current lease for our principal executive offices at 75-101 Federal Street, Boston, Massachusetts, which we refer to as the Current Lease, effective as of July 1, 2013 pursuant to a termination option contained in the Current Lease. In connection with this termination, we are obligated to pay a termination fee of approximately $1.1 million, payable in two equal installments. We paid the initial installment on June 28, 2012 and the remaining installment will be paid to the landlord on or before July 1, 2013.
On July 5, 2012, we entered into a new lease for our principal executive offices at One Marina Park Drive, Floors 4-6, Boston, Massachusetts, which we refer to as the New Lease. Pursuant to the New Lease, we have agreed to lease approximately 82,000 square feet of office space and expect to move into the premises on or about May 1, 2013. The term of the New Lease began on July 5, 2012 and will continue until July 31, 2020, however the obligation to pay rent will not commence until August 1, 2013. The average monthly rent over the initial term of the New Lease is $0.3 million, exclusive of operating expenses.
Pursuant to the New Lease, we have a right of first offer, subject to the rights of existing tenants in the building, whereby we may lease certain additional space in the building during the term of the New Lease and the right to extend the New Lease for one period of five years upon the expiration of the initial term. Under the terms of the New Lease, we are required to provide a security deposit in the form of an unconditional and irrevocable letter of credit of approximately $1.8 million, subject to reduction commencing August 1, 2015, and will be required to pay our pro rata share of any building operating expenses and real estate taxes over and above a base year, as well as certain utility costs. Additionally, we also have certain rights to sublease the New Lease.
Revenues and Expense Components Revenues We derive recurring revenues from the sale 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. 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 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 where 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.
24-------------------------------------------------------------------------------- Table of Contents 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 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.
We defer incremental direct costs incurred 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, 2012 and December 31, 2011, there were no deferred incremental direct contract acquisition costs. 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 months ended June 30, 2012 and 2011, we deferred $8.0 million and $2.1 million, respectively, of incremental direct costs. During the six months ended June 30, 2012 and 2011, we deferred $10.7 million and $4.1 million, respectively, of incremental direct costs. The increase in the deferral of incremental direct costs during the six months ended June 30, 2012 compared to the same period in 2011 was primarily related to the deferral of the costs associated with the payment obligations to our C&I customers in connection with our participation in the PJM Interconnection, or PJM, open market demand response program due to the change in our revenue recognition in the fiscal year ending December 31, 2012, or fiscal 2012. In addition, the increase in the deferral of incremental costs during the six months ended June 30, 2012 as compared to the same period in 2011 was also due to our participation in the Western Australia demand response program, a program which we did not participate in during the six months ended June 30, 2011 where the associated fees have been deferred because they are not fixed or determinable until the end of the applicable program periods on September 30th. During the three months ended June 30, 2012 and 2011, we capitalized $2.7 million and $4.7 million, respectively, of production and generation equipment costs. During the six months ended June 30, 2012 and 2011, we capitalized $5.2 million and $6.6 million, respectively, of production and generation equipment costs. We believe that this accounting treatment appropriately matches expenses with the associated revenue.
As of June 30, 2012, we had over 8,300 MW under management in our demand response network, meaning that we had entered into definitive contracts with our C&I customers representing over 8,300 MW of demand response capacity. In determining our MW under management in the seasonal demand response programs in which we participate, we typically count the maximum determinable amount of curtailable load for a C&I customer site over a trailing twelve-month period as the MW under management for that C&I customer site. However, the trailing period could be longer in certain programs under which significant rule changes have occurred or under which we do not have enough obligation to enroll all of our MW in a given program period, but have enough obligation in a future program period to enroll those MW again. We generally begin earning revenues from our MW under management within approximately one month 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. This results in a longer average revenue recognition lag time in our C&I customer portfolio from the point in time when we consider a MW to be under management to when we actually earn revenues from that MW. Certain other markets in which we currently participate, such as the ISO New England, Inc., or ISO-NE, market, or 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. Additionally, not all of our MW under management may be enrolled in a demand response program or may earn revenue in a given program period or year based on the way that we manage our portfolio of demand response capacity.
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 performance during the months of July through 25-------------------------------------------------------------------------------- Table of Contents September. Based on the recent changes to certain PJM program rules, we have concluded that we no longer have 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 months ended September 30th of the applicable 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. No revenues related to the current PJM open market program year were recognized during the three months ended June 30, 2012, and therefore we had no unbilled revenues from PJM at June 30, 2012. In accordance with our policy to capitalize direct and incremental costs associated with deferred revenues to the extent that such costs are realizable, we deferred the associated cost of our payments to C&I customers for the month of June totaling $3.7 million and will expense such deferred costs when the associated deferred revenues are recognized. We have evaluated the direct and incremental costs for recoverability prior to capitalization and determined that the capitalized costs are realizable.
In February 2012, the Federal Energy Regulatory Commission, or FERC, issued an order substantially accepting a proposal by PJM regarding certain market rule changes with respect to the measurement and verification of demand response resources in the PJM capacity market, which we refer to as the PJM proposal. The FERC order resulted in the immediate implementation of PJM's proposed market rule changes regarding capacity compliance measurement and verification. As a result, our future PJM revenues and profit margins will be significantly reduced and our future results of operations and financial condition will be negatively impacted. These impacts may be offset by our future growth in MW under management in the PJM market and effective management of our portfolio of demand response capacity.
Our revenues have historically been higher in our second and third fiscal quarters of our fiscal year due to seasonality related to the demand response market. As a result of the change in our ability to estimate performance in the PJM open market program, our revenues for the second quarter of fiscal 2012 are significantly lower than our revenues for the second quarter of the fiscal year ended December 31, 2011, or fiscal 2011, as all PJM revenues related to the current PJM program year which commenced on June 1, 2012 will be recognized during the third quarter of fiscal 2012. We recognized no revenue for the three or six months ended June 30, 2012 from open market sales to PJM, as compared to 52% and 35%, respectively, of our total revenues for the three and six months ended June 30, 2011.
Revenues generated from open market sales to ISO-NE accounted for 20% and 14%, respectively, of our total revenues for the three months ended June 30, 2012 and 2011 and 22% and 22%, respectively, of our total revenues for the six months ended June 30, 2012 and 2011. No other individual electric power grid operator or utility customer accounted for more than 10% of our total revenues for either the three or six months ended June 30, 2012.
In addition to demand response revenues, we generally receive either a subscription-based fee, consulting fee or a percentage savings fee for arrangements under which we provide our other energy management applications and services, specifically our EfficiencySMART, SupplySMART and CarbonSMART applications and services, and certain other wireless energy management products. Revenues derived from these applications and services were $7.1 million and $6.3 million, respectively, for the three months ended June 30, 2012 and 2011, and $13.8 million and $12.3 million, respectively, for the six months ended June 30, 2012 and 2011.
Cost of Revenues Cost of revenues for our demand response services primarily consists of amounts owed to our C&I customers for their participation in our demand response network and are generally recognized over the same performance period as the corresponding revenue. We enter into contracts with our C&I customers under which we deliver recurring cash payments to them for the capacity they commit to make available on demand. We also generally make an energy payment when a C&I customer reduces consumption of energy from the electric power grid during a demand response event. The equipment and installation costs for our devices located at our C&I customer sites, which monitor energy usage, communicate with C&I customer sites and, in certain instances, remotely control energy usage to achieve committed capacity are capitalized and depreciated over the lesser of the remaining estimated customer relationship period or the estimated useful life of the equipment, and this depreciation is reflected in cost of revenues.
We also include in cost of revenues our amortization of acquired developed technology, amortization of capitalized internal-use software costs related to our 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. Cost of revenues for our EfficiencySMART, SupplySMART and CarbonSMART 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.
26-------------------------------------------------------------------------------- Table of Contents 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 operator or utility, our portfolio of demand response capacity, (e) the introduction of new energy management applications, services and products, (f) our demand response event performance and (g) our ability to open and enter new markets and regions and expand deeper into markets we already serve. Our outcomes in negotiating favorable contracts with our C&I customers, as well as with our electric power grid operator and utility customers, the effective management of our portfolio of demand response capacity 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 554 full-time employees at June 30, 2011 to 625 full-time employees at June 30, 2012 due to our acquisition of Energy Response Holdings Pty Ltd, or Energy Response, in July 2011 and the overall growth of the company during this period.
We expect to continue to hire employees to support our growth for the foreseeable future. In addition, we incur significant up-front costs associated with the expansion of the number of MW under our management, which we expect to continue for the foreseeable future. We expect our overall operating expenses to increase in absolute dollar terms for the foreseeable future as we grow our MW under management, further increase our headcount and expand the development of our energy management applications, services and products. In addition, amortization expense from intangible assets acquired in future acquisitions could potentially increase our operating expenses in future periods.
Selling and Marketing Selling and marketing expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our sales and marketing organization, (b) commissions, (c) travel, lodging 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 for the foreseeable future as we further increase the number of sales professionals and, to a lesser extent, increase our marketing activities.
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 for the foreseeable future as we invest in infrastructure to support our continued growth.
Research and Development Research and development expenses consist primarily of (a) salaries and related personnel costs, including costs associated with share-based payment awards, related to our research and development organization, (b) payments to suppliers for design and consulting services, (c) costs relating to the design and development of new energy management applications, services and products, and enhancement of existing energy management applications, services and products, (d) quality assurance and testing and (e) other related overhead. During the three and six months ended June 30, 2012, we capitalized software development costs of $1.6 million and $2.3 million, respectively, and the amount is included as software in property and equipment at June 30, 2012. During the three and six months ended June 30, 2011, we capitalized software development costs of $2.3 million and $3.1 million, respectively, and the amount is included as software in property and equipment at June 30, 2011. We expect research and development expenses to increase in absolute dollar terms for the foreseeable future as we develop new technologies.
27 -------------------------------------------------------------------------------- Table of Contents Stock-Based Compensation We account for stock-based compensation in accordance with Accounting Standards Codification, or ASC, 718, Stock Compensation. As such, all share-based payments to employees, including grants of stock options, restricted stock and restricted stock units, are recognized in the statement of operations based on their fair values as of the date of grant. During the six months ended June 30, 2012, in lieu of a portion of cash bonuses related to our 2012 and 2013 bonus plans, we granted 1,023,010 shares of nonvested restricted stock to certain executives and non-executive employees that contain performance-based vesting conditions. These awards will vest in equal installments in 2013 and 2014 if the performance conditions are achieved. 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 us. In addition, in December 2011, we granted 283,334 shares of nonvested restricted stock to certain non-executive employees that contained performance-based vesting conditions in lieu of a portion of cash bonuses related to our 2012 and 2013 bonus plan. The performance conditions associated with the December 2011 grant were modified during the three months ended March 31, 2012. As a result of these grants of nonvested restricted stock, we anticipate that, on a per employee basis, stock-based compensation expense will increase with a corresponding decrease in cash compensation expense.
For the three months ended June 30, 2012 and 2011, we recorded expenses of approximately $3.3 million and $3.8 million, respectively, in connection with share-based payment awards to employees and non-employees. For the six months ended June 30, 2012 and 2011, we recorded expenses of approximately $6.7 million and $7.3 million, respectively, in connection with share-based payment awards to employees and non-employees. With respect to option grants through June 30, 2012, a future expense of non-vested options of approximately $2.6 million is expected to be recognized over a weighted average period of 1.7 years. For non-vested restricted stock and restricted stock units subject to service-based vesting conditions outstanding as of June 30, 2012, we had $8.9 million of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 2.3 years. For non-vested restricted stock subject to performance-based vesting conditions outstanding and that were probable of vesting as of June 30, 2012, we had $6.8 million of unrecognized stock-based compensation expense, which is expected to be recognized over a weighted average period of 1.5 years. For non-vested restricted stock subject to outstanding performance-based vesting conditions that were not probable of vesting as of June 30, 2012, we had $1.5 million of unrecognized stock-based compensation expense. If and when any additional portion of our outstanding equity awards is deemed probable to vest, we will reflect the effect of the change in estimate in the period of change by recording a cumulative catch-up adjustment to retroactively apply the new estimate.
Other Income and Expense, Net Other income and expense consist primarily of gain or loss on transactions designated in currencies other than our or our subsidiaries' functional currency, interest income earned on cash balances, and other non-operating income and expense. We historically have invested our cash in money market funds, treasury funds, commercial paper, and municipal bonds.
Interest Expense Interest expense primarily consists of fees associated with our $50.0 million senior secured revolving credit facility pursuant to an amended and restated credit agreement with Silicon Valley Bank, or SVB, which we refer to as the 2012 credit facility. Interest expense also consists of fees associated with issuing letters of credit and other financial assurances.
Back To NFVZone's Homepage