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EnerNOC (NASDAQ:ENOC)

Q3 2012 Earnings Call

November 05, 2012 5:00 pm ET

Executives

Jennifer Varley

Timothy G. Healy - Co-Founder, Executive Chairman and Chief Executive Officer

David B. Brewster - Co-Founder, President and Director

Kevin J. Bligh - Chief Accounting Officer

Analysts

Patrick Jobin - Crédit Suisse AG, Research Division

Benjamin Schuman - Pacific Crest Securities, Inc., Research Division

John Quealy - Canaccord Genuity, Research Division

Andrew Weisel - Macquarie Research

Ahmar M. Zaman - Piper Jaffray Companies, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the EnerNOC Third Quarter 2012 Conference Call. [Operator Instructions] Later we will conduct a question-and-answer session, and instructions will follow at that time. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to turn conference over to Jen Varley, Senior Manager of Investor Relations. Please begin.

Jennifer Varley

Thank you, Latoya. Thank you, and good afternoon, everyone, and welcome to EnerNOC's Investor conference call for the third quarter ended September 30, 2012. We appreciate you joining us today. I'm Jen Varley, Senior Manager of Investor Relations at EnerNOC; and with me on the call today is our Chairman and CEO, Tim Healy; our President, David Brewster; and our Chief Accounting Officer, Kevin Bligh.

Today's presentation contains estimates and other statements that are forward-looking under the Private Securities Litigation Reform Act of 1995 and other federal securities laws, including, but not limited to, management's future expectations, beliefs, intentions, goals, strategies, plans or prospects. These forward-looking statements include, without limitations, statements relating to EnerNOC's future financial performance; the global market opportunity for EnerNOC's energy management applications, services and products; and the future growth and success of EnerNOC's energy management applications, services and products in general. These forward-looking statements are subject to risks and uncertainties and involve a number of factors that could cause actual results to differ materially from those expressed or implied by such statements. Additional information concerning these factors is contained in EnerNOC's filings with the SEC, including our annual report on Form 10-K and quarterly reports on Form 10-Q, available at www.sec.gov. The forward-looking statements included in this call represent the company's views on November 5, 2012. EnerNOC disclaims any obligation to update these statements to reflect future events or circumstances.

During this call, we will refer to non-GAAP financial measures, including non-GAAP net income, free cash flow and adjusted EBITDA. These financial measures are non-GAAP financial measures that are not prepared in accordance with generally accepted accounting principles. The definitions of and reconciliations of these non-GAAP financial measures to the most directly comparable GAAP financial measures is available in the press release announcing our third quarter financial results. This press release is available on the Investors section of our website at www.enernoc.com.

And with that, I'll turn the call over now to Tim Healy.

Timothy G. Healy

Thanks, Jen, and thank you to everyone for joining us this afternoon on our third quarter earnings conference call. On today's call, my prepared remarks will cover our third quarter results and put them in the context of our strategic plan. I'll briefly update some key metrics regarding our growth and operating leverage, and provide an overview of our third quarter sales and operational performance, as well as highlight some relevant data about the continued effective management of our portfolio of demand response resources.

David Brewster will then provide color on some important regulatory developments and provide an overview of our current and emerging market opportunities. Finally, Kevin Bligh will discuss our Q3 financial results and provide some key business metrics along with our updated financial outlook. In sum, you'll hear that we remain on track to achieve our 2012 and 2013 objectives, and are excited by the execution and strong momentum we continue to drive throughout the organization.

So let's begin by reviewing some key third quarter developments and overall performance year-to-date. On our second quarter call, in August, we described that market expansion was a key theme of our year-to-date performance. As of the end of Q3, we had roughly 8,500 megawatts under management, with the additional capacity primarily driven by new customer additions outside of the PJM market, including international markets. Through the first 9 months of 2012, we've added approximately 900 customers to our global demand response network, representing well over 1 gigawatt of new capacity to manage. We're now operational in 46 different demand response markets covering 38 states, as well as 6 countries and 4 continents.

While expansion continues to be a key theme for EnerNOC, operational excellence, key to EnerNOC's third quarter performance. 2012 has been an exceptionally busy year for demand response. In fact, year-to-date, EnerNOC successfully responded to nearly 300 demand response dispatches, in line with the number of demand response dispatches during the same period in 2011. But the volume of demand response we have dispatched grew substantially, with EnerNOC delivering approximately 85 gigawatt hours of demand reduction across multiple demand response markets and products, including economic demand response. Economic DR represents resources that we dispatched for customers in our network who proactively respond to high prices in the wholesale markets, a growing trend for our customers.

Overall, this year's dispatches have been widespread throughout our network, including several new initiatives implemented in 2012, such as the Pennsylvania Act 129 programs and our LSSi auto demand response program in Alberta. In particular, we enjoyed significant success fulfilling our Act 129 commitments, including the expansion of our agreements with 2 Pennsylvania utilities as those programs were in full swing. We perceive that this achievement is a testament to our ability to execute and another strong statement that demand response from the industry leader is a reliable and cost-effective way to meet even the most aggressive demand-side targets.

Importantly, our future growth from PJM is driven not only by more megawatts for us to enroll and manage reliably, but also by strong upward pricing trends that we see in the megawatts-weighted system-wide clearing prices of PJM capacity over the next 4 years. The 2012, 2013 delivery year, which relates to fiscal year 2012 revenue for EnerNOC, marks the low point of megawatt-weighted clearing prices for the 4-year period between '12 -- excuse me, between 2012 and 2015, with a price of roughly $32,000 a megawatt year. Looking ahead to 2013, 2014, the megawatt-weighted clearing price increases to just under $45,000 a megawatt year, then to approximately $48,000 a megawatt year in '14, '15, and finally, to roughly $57,000 a megawatt year in '15, '16. As we've pointed out on the Q2 call, this represents a 79% price increase between 2012 and 2015. We're obviously pleased to have aggregated an asset base that positions us to successfully lock-in that type of pricing uplift.

We're also pleased that we've continued to increase our operational leverage, by reducing the cost of managing each new megawatt, as the company continues to benefit from our industry-leading scale. Further, our customer splits continue to trend favorably again this quarter, with better customer splits for EnerNOC in Q3 this year compared to Q3 last year, reinforcing our forecast of gross margins for 2012 trending at or now even above their 2011 level, and increasing slightly higher again in 2013. Our ability to adapt to new market rules, to continue to execute and deliver value to our customers, continues to be the foundation of the EnerNOC brand.

Looking now at our energy efficiency business. We've completed the deployment of EfficiencySMART Insight at nearly 500 sites within the Commonwealth of Massachusetts under our existing contract with the Massachusetts Department of Energy Resources. Based on the compelling economic value that we've already been able to deliver to the commonwealth, through our Software as a Service or SaaS-based application, we're pleased to have recently expanded our contract with this customer, which was one of our earliest EfficiencySMART Insight deals.

The next phase of the deployment involves the energy use of community colleges, trial courts and other state-owned office buildings. This is a good sign of the value that we're providing to the Commonwealth, similar to the value that we are now providing to the state of Connecticut under a similar contract.

Across our energy efficiency portfolio, approximately 2,000 buildings are now realizing the benefits of continuous energy savings from our EfficiencySMART products suite. We've also made significant enhancements to the operational delivery of our EE products and services. The investments we've made in our cloud-based energy management platform, including enhancements to our automated fall protection engine, have strengthened our ability to cost-effectively mind millions of meter readings and energy data points to provide valuable business intelligence to our customers. EnerNOC now collects and analyzes approximately 1 billion energy readings a month through our platform. And our database now has over 50 billion energy data points, which we believe represents one of the largest repositories of interval meter and building management system data in the world.

Our development engineers and energy services professionals remain extremely energized about the products we're creating and the value we can deliver by leveraging a unique combination of data, energy expertise and engaged end-use customers.

Our consistently strong performance in delivering reliable capacity to electric power grid operators and utilities, coupled with the favorable pricing tailwinds that are driving our top line growth for the business, provide us with great visibility going into 2013 and beyond. We've invested heavily into growing our business in 2011 and 2012, to position EnerNOC to capitalize on the macro trends. Our success year-to-date provides us with the ability to confidently raise the bottom end and midpoints of our 2012 revenue and adjusted EBITDA guidance, and to increase our GAAP EPS guidance. Some of our 2012 success has already positioned us for better performance in 2013 than we had originally forecast, particularly as it relates to the results of incremental auctions in which we, again, participated this year. These capacity auctions allow us to buy or sell capacity for current and future delivery years in PJM, which is a beneficial tool for all the participants, generators and demand response providers alike. Our auction activity, which has been a part of our portfolio management activity over the past several years, to help us and the PJM market to ensure that our zonal megawatt commitments match our customers' ability to deliver those commitments, to help them grant enhanced grid reliability, which becomes particularly meaningful if and when market rules change, as they did in early 2012. This auction activity bolstered our financial results due to the pricing and the incremental auctions. Furthermore, a number of the profitability initiatives that EnerNOC has initiated in 2012, and a number of other factors, give us the confidence to increase the bottom end and midpoints across the board on our guidance in 2013 as well.

So, with that, I'd like to turn the call over to David Brewster, whose remarks will provide more color around some of our Q2 highlights -- Q3 highlights, and discuss in greater detail the current regulatory landscape and some emerging market opportunities.

David B. Brewster

Thank you, Tim. Over the past several quarters, we've upped our commitment to being the leader in helping to shape and define regulatory compliance with the demand response industry. We've made important strides in this area, informed by our 2011 compliance audit by the Federal Energy Regulatory Commission, which was the first of its kind for any demand response provider and perhaps a sign of both the demand response industry coming of age and EnerNOC's leadership position in the industry.

On our Q2 call we announced the establishment of our centralized compliance program based on Deloitte's integrated compliance risk management guidelines. We also welcomed Tom Birmingham as our Director of Regulatory Compliance in July of 2012, to spearhead the effort of continuously assessing and enhancing our compliance processes and controls. We are proud to be setting the benchmark for compliance in the new and evolving demand response industry, and we believe that our heightened compliance program will serve as another competitive advantage for EnerNOC.

With that backdrop in mind, we want to discuss recent developments with respect to 2 investigations by FERC. The FERC addresses -- the first addresses unintentional meter data errors associated with a small number of our demand response sites in June. The second addresses failure by our wholly-owned subsidiary, Celerity Energy Partner San Diego LLC, to make 2 FERC filings in a timely manner in 2010.

We want to take the opportunity, on this call, to provide some context on these investigations. First, we acknowledge these errors and believe that the actions we're taking to bolster our compliance program will minimize the occurrence of unintentional errors of this sort in the future. Second, it's important to highlight that the first investigation addresses violations with respect to only 5 of EnerNOC's approximately 1,800 sites in New England. Third, there have been no allegations of intentional misconduct by EnerNOC or Celerity, to date. And finally, we currently do not expect that the outcome of these investigations will impact any of the financial guidance that we've provided. We continue to work collaboratively with FERC towards an expeditious settlement agreement that fully resolves these matters, and are optimistic that this matter will be settled within a matter of months, if not weeks.

Switching gears. We continue to monitor developments related to the EPA's proposed RICE NESHAP rules which allow properly funded and existing backup generators to participate in emergency demand response programs for up to 100 hours per year. There's nothing material to update on this matter as little has changed since we discussed the topic on our Q2 earnings call. We support EPA's proposal and we continue to expect a final decision on the proposed rule by December 14, 2012. In terms of understanding the potential impacts to EnerNOC's portfolio, which has a percentage of our megawatts in less than 1/3 backup generators, the financial guidance that we've provided takes into account a wide range of potential outcomes related to this matter, and we remain fully confident in our ability to continue to successfully manage our portfolio in compliance with all EPA rules and regulations.

Moving on to our operational highlights. As Tim mentioned, 2012 has been a busy year for demand response, and reliability has been as strong as ever. Let me start with PJM. Results indicate that emergency demand response performance in PJM appears to have been even better this summer than in the summer of 2011. During the 2 summer days this year, when PJM dispatched emergency demand response, the industry as a whole delivered 104% and 102% respectively, according to preliminary PJM reports. We're happy to report that EnerNOC played a major role in the dispatches, with initial numbers showing our own PJM portfolio outperforming the industry average. This is another data point highlighting the reliability of demand response as a proven demand-side resource, and EnerNOC is exceptionally proud to play a leading role in this market, providing critical grid support to the world's largest ISO.

Within PJM, we want to particularly highlight our success in every one of our Pennsylvania Act 129 contracts, providing another example of our flexibility in quickly adapting to new market opportunities, and of the greatly enhanced value that we can create both for our utility and our end-use customers. EnerNOC successfully delivered against our commitment across a handful of different Pennsylvania utility contracts. We were able to recruit, in a short period of time, a large number of megawatts and then delivered strong performance to help our utility partners achieve their Act 129 goals. Despite the fact that Act 129 was a difficult program to administer, given the interplay with the existing PJM DR programs, the high number of dispatch hours and the unique challenge of forecasting the top 100 hours of annual electricity demand. We look forward to future opportunities to work with our Pennsylvania utility partners, both in terms of demand response and energy efficiency.

Outside of PJM, we continue to innovate and expand our addressable international market opportunities, while closely inspecting how we can operate more efficiently within each of our existing programs. For starters, our sales performance in Australia and New Zealand has been exceptionally strong in 2012, particularly in Western Australia, which accounted for just under 10% of our Q3 revenues. The Australia and New Zealand region is poised for additional growth through both our existing programs as well as additional bilateral opportunities, such as the 20-megawatt DR program with Genesis Energy, in New Zealand, which began in July 2012, and our 35-megawatt contract with TransGrid, in Sydney, Australia, which we've just announced last week. In 2013, we believe that Australia and New Zealand will be our second largest revenue-generating region. And with our 240-megawatt DR opportunity in Western Australia, we expect to generate more than USD 40 million in revenues from that program alone next year. Our Australia and New Zealand business activities are a shining example of the momentum and increased revenue diversification that we are gaining.

Domestically we are actively participating in the regulatory discussions in Texas, as we've mentioned on our previous two earnings calls. The Public Utility Commission of Texas continues to examine solutions to address a decreasing reserve margin in the state, and its potential for impacting the power grid reliability. We believe that demand response will be an important component of any solution to this problem, and Texas regulators have clearly indicated that they agree. The debate in Texas today is not whether to create enhanced opportunities for DR, but how to design a model that will be attractive, to increased DR investment. Current estimates suggest that demand response penetration in Texas is less than 3% of the system peak, and with room to grow to as much as 10% or more within a few years. We've been delivering demand response in Texas for several years now and as such, believe that we are well positioned for expansion in the event that a revised market structure or rules present an opportunity for additional demand response.

And with that, I'll turn the call over to Kevin Bligh, who will provide additional color on our Q3 financial results as well our outlook for the rest of the year and 2013.

Kevin J. Bligh

Thank you, David, and good afternoon, everyone. I'd like to provide some additional details on our Q3 financial performance as well as update our financial guidance for 2012 and 2013.

For Q3, we achieved revenues of $177.9 million, GAAP net income of $2.21 per diluted share and non-GAAP net income of $2.40 per diluted share. Revenues were up from Q3 of last year, primarily due to our demand response business in Western Australia. All revenue for the trailing 12 months of this program were recognized at the end of the program year -- program period, which was September 30. We also had continued increases in both megawatt growth and revenue related to our Texas and California demand response markets, as well as increased revenues as a result of new demand response programs, such as Act 129 programs. As previously discussed, due to a change in timing of the revenues recognized from our participation in the PJM ELRP demand response program, all of our capacity revenues relating to our participation in this program were recognized during the 3-month period from July through September, compared to last year when we recognized -- when they were recognized over the 4-month period June through September. However, the increase in revenue, due to the change in timing of revenue recognition, was more than offset by the decrease in our megawatt delivery obligation coupled with less favorable pricing in this program. Q3 PJM ELRP revenues were down approximately 11.3% from last year. And year-to-date, PJM ELRP revenues were down approximately 28.9% from last year. Again, due to our smaller capacity obligation and lower program pricing in 2012. Revenues from our non-demand response business increased by approximately 13.4% from Q3 of last year.

Gross profit was $95 million and gross margin was 53.4%, both up from Q3 of last year, primarily due to strong portfolio management across our PJM portfolio, in particular, improvement in our overall C&I splits and the increase in recognized revenue that I just discussed. As in the past, our gross margin should follow a similar seasonal pattern as our revenues, and we expect that Q3 will be our highest gross margin period of the year. Remember that both PJM and Western Australia contribute negative gross margins outside of Q3 because cost of revenues from depreciation of installation costs, and related operational infrastructure, is booked ratably in all quarters while the capacity revenue is recognized in Q3. We continue to expect that our gross margins for the full year 2012 will be similar to our full year 2011 gross margins or slightly better.

Operating expenses were $35.7 million for Q3. We ended the quarter with 660 full-time employees, a net increase of 35 compared to Q2.

We recorded an income tax benefit for Q3, of approximately $700,000. At the end of Q3, we determined that we were able to make a reliable estimate of our effective annual tax rate, and this estimated annual effective tax rate was applied to our year-to-date U.S. income and resulted in an income tax benefit for Q3 due to the reversal of the U.S. tax provision provided during the first 2 quarters of this year. For the full year, we expect a tax provision of approximately $1.5 million, which will result in a tax provision, for Q4, of approximately this same amount. We also continue to expect a nominal amount of cash income taxes, primarily related to foreign jurisdictions.

We use additional non-GAAP measures, adjusted EBITDA and free cash flow to monitor growth trends in our business. For Q3 2012, our adjusted EBITDA was $69.1 million. Free cash flow for Q3 was $6 million as compared to $5.7 million in Q3 of last year. We ended the quarter with $93.2 million in cash and cash equivalents, and $10.3 million of restricted cash and deposits.

Now let me turn to guidance, starting with some key assumptions. Given the continued volatility of foreign exchange rates, our guidance assumes an Australian dollar pegged at USD 1.03 and a Canadian dollar pegged at USD 1.02. Under the previously stated assumptions, for the full year 2012 we are increasing our bottom end -- the bottom end of our revenue and adjusted EBITDA guidance and, raising our GAAP EPS guidance provided on our Q2 earnings call. We expect full year 2012 revenues in the range of $270 million to $280 million. We expect to generate full year GAAP net loss of $0.85 to $0.95 per share based on basic and diluted weighted average shares outstanding of 26.6 billion. Full year 2012 adjusted EBITDA is expected to be between $15 million and $20 million, with expected -- with estimated stock-based compensation of approximately $14 million, estimated amortization of intangibles of approximately $7 million, estimated depreciation of approximately $18 million, estimated $0 million to $0.5 million in interest and other expense net and estimated tax provision of approximately $1.5 million.

Turning to 2013. We are increasing the bottom end of our guidance provided in our Q2 earnings call. We expect full year 2013 revenues to be in the range of $360 million to $400 million. We expect GAAP net income for 2013 to be in the range of $0.50 to $0.75 per diluted share. These estimates are based on diluted weighted average shares outstanding of 28 million. Full year 2013 adjusted EBITDA is expected to be between $60 million and $75 million. We expect stock-based compensation to be between $12 million and $14 million, amortization of intangibles to be approximately $7 million, depreciation expense to be between $20 million and $23 million, and interest and other expense net to be between $1 million and $2 million. The estimated tax provision is expected to be between $6 million and $8 million.

We appreciate your interest and are ready to take your questions at this time.

Question-and-Answer Session

Operator

[Operator Instructions] The first question is from Patrick Jobin of Crédit Suisse.

Patrick Jobin - Crédit Suisse AG, Research Division

So, I guess the first question is really on 2 things from some of your remarks. I guess, on the economic DR, it's a great differentiator for EnerNOC. Can you talk to how many customers are enabled, and maybe the revenue in the quarter and kind of how you see that evolving? And then the second part is on the incremental auctions. Is it possible to quantify the benefit and kind of -- I know there's been a few years of incrementals, and how we should think about that relative to your outlook and guidance?

Timothy G. Healy

Yes. Patrick, it's Tim. Excuse me. As it relates to the economic demand response, I have some notes here, let me just grab them. Just as background, PJM paid out about $6.5 million in economic demand response, April through August. And, yes, we had a pretty sizable portion of that, between $2 million and $3 million worth of revenue from, basically, what is the impact, the initial impact of, for the quarter, 7.45, creating more opportunities for economic demand response. It's a relatively small percentage of our portfolio. We do have an initiative inside of EnerNOC, where we did assign, late last year, a very small team of just a couple of folks to develop our approach, our go-to-market strategy in the PJM market, and that team has just recently come and given us some confidence that it was a good investment of our resources. Obviously, with that type of revenue and opportunity it feels like a good bet for us. It's something that we're optimistic about, but I think the numbers are fairly small. It's not yet hundreds of customers for EnerNOC, so it's still in the tens and dozens. So that should hopefully give you a little bit of sense of what we're talking about as we talk about economic demand response potential, but still, something that's small in terms of revenue and customers. In terms of the incremental auction, this year's auction has provided some upside, some meaningful upside to EnerNOC this year. We tend not to disclose the specifics around our auction strategy, almost exclusively for competitive reasons. But we have been able to manage our portfolio effectively. As you remember, and others probably recall as well, there was a significant rule change in PJM that made it so that we needed to go and look at the incremental auction, probably more than we have in the past, as a mechanism to make sure that we were able to deliver the zonal capacity in each zone that we needed to deliver, in light of some of our customers looking very different to us after that rule change, than they did originally, and looking at the time that we had to deliver those megawatts and so forth. Just to be clear though, our intention, the reason that we built the company and the reason that we've built the technology that we've built is because we intend to deliver megawatts to the marketplace when we go out and take capacity obligations in the initial BRA or in other auctions where we bid our capacity, or under our agreements with utilities. That's why we have the infrastructure that we do. That's why we develop the marketing plans that we do. And so, while the incremental auction has been used as a mechanism to feather in some capacity and prices where we're trending high relative to our original marketing plan or to make sure that if there are other generator out there that need our capacity for their opportunity, we can go and do that at any point in time. We've done it historically. But the focus of the company continues, and will remain, to go deliver megawatts to the marketplace. In this particular auction, we had some incremental benefit that benefited us in 2012, and is -- or financially benefiting us in 2013, already, as well. And it's getting us to the right level of the portfolio in light of the market rules that have taken place in PJM.

Patrick Jobin - Crédit Suisse AG, Research Division

Great. That makes sense. And then just last question from me. I guess, what would have to transpire to hit either the high end or low end for '13? And I guess for David, you mentioned that you had evaluated some different options as to what the EPA RICE ruling ultimately comes out as. Can you maybe give us a sense of what variables you're flexing?

David B. Brewster

So, the two of us will both tackle that. One of the things that EnerNOC embarked on early this year, that was germinated late last year but then put some muscle behind it this year, was a profitability initiative at EnerNOC where we put a few folks, a small team, really looking hard at what EnerNOC has been doing historically, what we are doing currently and what our future looks like, in order to try to drive more profitable results across, as we mentioned today. There are basically 46 different markets that we operate in today for demand response, and then you combine that with energy efficiency products and solutions that we're offering to the market, you suddenly probably have a little bit more complex business than your average $250-million to $300-million revenue company. And we looked at where should we invest resources, where we're getting the highest return on those invested resource dollars, what things should we contract or put on hold or otherwise change our strategy in. And that's resulting in, number one, some really good data flowing to management, to give us a better understanding of cost allocations, a better understanding of where we're most profitable, where we and our customers are not making as much money as we would like in certain energy efficiency or demand response initiatives. And it has allowed us to identify some profitability that -- or opportunity, that we're very optimistic, starts to flow, has already flowed in 2012, and we expect some of these initiatives to carry into 2013. But there's also more there. There are some initiatives that it's going to take longer for us to achieve some of those profitably opportunities. And so one of the ways for us to have a really successful 2013 is to continue to keep our eye on the prize for some of those high-level meaningful initiatives that we've undertaken. They're everything from operational to selling the right way, to changing certain incentives across the organization. They result in the organizational changes, the way we manage regionally and look at the profitability by region, and look at what we can do. They involve aspects of the right size customers, the right types of customers, the right strategic customers that want more than just one product from us, so that we can really leverage the investment we make, both in the hardware and in time with the customer up front, a more valuable customer or those customers that may want to buy more products, more quickly with us. And we've really taken that initiative to heart. So that's certainly a part of the high-end of 2013 versus the low-end of 2013, in part also, Patrick, because a lot of 2013 is already written. We know what a lot of our obligations are. We have a lot of that capacity and management and a lot of the prices are already determined in a lot of what we're projecting for 2013. So it comes down to how do we operate and then how do our resources perform. And then I think there's a regulatory, an approved...

David B. Brewster

Yes. And certainly, with all regulatory matters, we're going to try and incorporate them to the best of our ability into our forward guidance, specifically with regard to the EPA, Patrick, that we spent some considerable time on our Q2 call discussing the topic, so we wanted to follow up on it. Just to really reiterate our position supporting the EPA and to update folks that we don't see any change, any material change, in the dialogue. We're confident that it's going to go in our favor. The EPA has spent 2 years studying the issue. They came to what we believe is a very thoughtful and well-reasoned ruling. It's a ruling that's supported by the vast majority of folks that file comments about the demand response component of it. So we're feeling good about it. And in terms of the range of outcomes, we've looked at all the way from 15 hours a year and 200 hours a year, which I think is what's been in play over the discourse of the ruling over the last couple of years. So we feel good, but again, we tried to incorporate all that into the guidance that we have.

Timothy G. Healy

And one more comment on that, Patrick. When you look at what we've been able to achieve in 2012, where we are trending very favorably to our initial projections, initial forecasts, those were based on our budget and based on our outlook for the year. One of the other things that we've been able to do is we have been able to enhance some investment opportunities along the way, particularly in our development resources, our engineering activity. That's a place that we've actually been spending a little bit more money. And some of those initiatives we hope are investments that pay off for us in the 2013 time frame and in the 2015 time frame. But I think it's notable to note that we've had the successful financial results, year-to-date, and that we're trending as favorably as we are in 2012 even with what for us is an internal increase in the investment dollars that we're spending in R&D and development activity. And we believe that the right thing for us to do and we're happy that we've been able to achieve both of those and hope for them to pay off in the future as well.

Operator

The next question is from Ben Schuman of Pacific Crest Securities.

Benjamin Schuman - Pacific Crest Securities, Inc., Research Division

Given that the big capacity markets are all locked in through 2015, in terms of the revenue side at least. Can you give us just some initial thoughts on 2014 in terms of trajectory? How that could drive some leverage on the bottom line, maybe at least qualitatively, unless you want to initiate 2014 guidance here in response to the question.

Timothy G. Healy

That's clever. But, no, we're going to stick with being one of the outliers that goes as far as issuing 2013 guidance this early in that period. As it relates to your first comment though, I guess, I wouldn't necessarily tend to agree that all of the big capacity markets already have their price and volume, and certainly not their volume components locked up. As David mentioned, Texas is a place where, right now, it's a relatively, I don't want to say inconsequential, but it's a relatively small amount of demand response, I think right around 3%. I'm not even sure if it's at 3% quite yet, but it's a little less than 3% of that market that is addressed by demand response. And I think it's widely known in energy market circles that Texas is spending a considerable amount of time, as David mentioned. It's not whether demand response is likely to be a big part of the solution in Texas, it's how it's going to be a big part and what those rules markets look like. But Texas is not one that has a 3-year forward capacity markets at this point in time. The demand response opportunity that they do have is done more on a month-to-month or quarter-to-quarter basis in the current year. So I think one of the things that is not in our 2014 guidance, at this point in time, is Texas upside beyond what we sort of have been projecting based on the current state of affairs in Texas, which is that it's a nice market, it's a relatively small market for us as it is for most demand response providers, but there's an opportunity there. I think there remains growth for us in demand response under our TVA contract. We believe that there's more growth in the Ontario Power Authority market even though there's been some mixed signals that have come out of Ontario Power. We still believe that that's a market that has more upside, and we intend to be very active in that market. We have people in that market on a regular basis and we will continue to work with the leadership in that region. California remains a viable market for us, with growth from where we stand today. Growth in our profitability especially, because I think we're getting better and better at managing one of the more complex demand response markets in terms of the way our contracts work there, in terms of the way the penalty provisions work there. That's been a part of our profitability initiative, to really look at making sure that we fulfill our obligations there, that our customers are well informed of how they can make more money in that market with us. And things that we think are big opportunities in that market as well. And then, certainly, we've talked about it, but probably not at length, one of the things that continues to impress us and continues to be an area of optimism for EnerNOC is that we have embarked on very disciplined, 1 or 2 markets at a time, international growth. And we've generated success with that. I would call our activities in Canada successful activities. I'd call our activities in the U.K., but the jury is still out at this point in time. There's things that have gone right and there's things that still need to be modified in terms of the market rules in the U.K. I'd call our Australian opportunity something that 2 years ago we were not really talking about, and now as David talked about, it's going to represent probably our second or third largest market opportunity next year, with well over $40 million. Because I think it's $40 million just from Western Australia alone, and Eastern Australia is much more sizable than Western Australia, at 7x the size, maybe even 10x the size of Western Australia. And certainly, our results in the U.S., as well as the success that we expect we will be able to achieve in Western Australia, give us at least a moderate amount of optimism that we could see things as early as 2014 and '15 in some of the markets I just described. So it may seem that the largest markets are clearly defined at this point. But I would say that we've got room to grow in some of our largest markets, as you see, because we've already indicated that there's tremendous growth between 2013 and '14 in PJM, in just the results of our bidding that we made public a couple years ago. We know that we've got some upside in our growth in PJM. But I actually think there's going to be the non-demand response part of our business, that we'll be pointing to as we look at what the 2014 story will be, and it could be from a few markets that we're not even talking about right now.

Benjamin Schuman - Pacific Crest Securities, Inc., Research Division

Okay, great. Just one more for me. For the Act 129 contracts, are you able to mostly leverage asset and end customers that are already in place through PJM programs or are these new customers, that you've built out, that you potentially won't be able to leverage once the Act 129 requirements expire?

Timothy G. Healy

It was a mixture. We were able to leverage a lot of our existing customers. We were working with some utilities that we hadn't directly worked with at all in the past. And they were able to share with us some of their large account customer lists and relationships, and we were able to leverage that. Certainly a combination, and it's not unlike the way we've done it in some other markets where we have layered programs or programs that try to leverage the existing infrastructure, that try to leverage the existing demand response market opportunity, but then need this resource to meet their own objectives possibly in a different time of system need. There are particular distribution system needs or there are other regulatory requirements that they might have. So this wasn't new to us. I think what was new to us in Act 129 was that this was a program that we were very cognizant of the potential for customer fatigue because of the 100 hours that we needed to operate certain resources or have the potential to meet. It was different because of the forecasting activity associated with trying to predict the top 100 hours and get that right. It was different because there were different -- in this particular case, there was a statewide examiner that was in charge of looking at customer performance and determining what determined that customer performance, granted they used similar performance measurement and verification performance rules as the PJM grid operator, but there were certain other elements that were new to this initiative. And I think, rightly so, we took a conservative approach to our forecasting at the beginning of the year, as it relates to Act 129. And we're very pleased that now, as we look at our performance and look at how we perform under those, that our financial performance wound up being better than we were forecasting at the beginning, which was probably, at best, a breakeven opportunity for us.

Operator

The next question is from John Quealy from Canaccord Genuity.

John Quealy - Canaccord Genuity, Research Division

So three quick questions for me. First, on the international front, I know U.K. publicized a DR trial with you folks. If you could give us a little bit of detail there. Also, what's going on in Japan? I know some things are going on, sort of under the waterline there. Question two, more strategically, you talked about billions of energy data points. I'm wondering if you can talk about how we should think about monetization of those. Any new partnerships, perhaps, as we go through '13, '14, as we get more towards the big data side? And then question three, with free cash ramping nicely, at least to our model in '13, can you talk about M&A potential?

Timothy G. Healy

So why don't we have David Brewster tackle the international since he, among many other things, has been leading the charge for us on a lot of our international expansion activity. And then I'll touch on the EE data points and then try to give you a little bit on M&A.

David B. Brewster

John, I'm not sure exactly what you're referring to in the U.K. Is it the U.K. power networks or what is -- what's the trial you mentioned?

John Quealy - Canaccord Genuity, Research Division

Yes, this is the Ofgem release, 1.5 week ago or something, David, that talked about tourist attraction that you folks are hooked up with, trying to do some DR.

David B. Brewster

Okay. Yes, yes. And I think that may be part of a program that we're into. But, as you know, we've been in the U.K. for some time now, maybe 2.5 years. And we, to guess to what Tim was talking about earlier, in terms of layered programs. We operate both at the transmission level with National Grid, as well as with some of the distribution utilities in the U.K., providing distribution load relief and other benefits to the distribution utilities. And we're continuing to ramp there. We're excited. I think, as Tim alluded to, there's work that needs to be done. But what we are very encouraged about in the U.K. is that, that work is being done by Ofgem, who has some of the leading regulation in the world in terms of how distribution utilities are able to get incentivized financially for demand-side management approaches. Basically they're held -- both CapEx and OpEx are treated equally, which is very, very encouraging for us, and something we are using as a template around the world. So that's exciting for us, and also, with the Department of Energy a privateer's [ph] deck in the U.K. They are working and looking very hard at implementing a capacity market in the U.K. So the U.K. is a market where it's not having a material impact on us yet, but we are optimistic about the potential in the future. We're continuing to diligently work on those rules. Related to Japan, John, Japan is one of many markets that we're paying a lot of attention to. I think you put out a report a few months back, or a few weeks back. We did a pilot with one of the 10 electric power companies in Japan this summer, and are very proud of our team that moved extremely quickly and the results that we delivered across this very small project. So it's very early innings for us in Japan. It's obviously a sizable market opportunity post the 3/11 Fukushima tragedy. But it's a market that we're monitoring and hope to have an opportunity to grow into. But we're not quite there yet, and with that, maybe I'll turn it over to Tim to talk about the billions of data.

Timothy G. Healy

Yes. I think David summarized that really well. Maybe one way to frame it, John, as it relates to the U.K., right now the work that we're doing in the U.K., as David described, is probably a lot more rule-work, helping the market develop the right set of rules versus customer recruitment and megawatt management work. I would say that there's probably a higher mix of rule-making, market-making work versus customer recruitment or megawatt management work going on in the U.K. And in Japan, I'd say it's probably closer to that market development work, right now, to try to work with utilities there to find a means for an EnerNOC to aggregate C&I load, to what effectively -- we've been able to take some of those initial steps. They approved that we can deliver megawatt capacity. And the customers there, like here, respond to financial incentives, respond to electronic signals and so on and so forth. But there still is yet to be a clear path to where we can switch from that work to the heavy lifting of customer recruitment and megawatt-under-management type work. So you talked about the fact that we have roughly 50 billion energy data points now at our database at this point, and that's growing by about 1 billion data points a month and what opportunity is there. That's what we are spending a lot of time, ourselves, reflecting on and determining where we go from here. We're encouraged by a few things. We're encouraged, one, that there seems to be an ecosystem developing, of technology companies that want to leverage that data and create applications that benefit end users, particularly commercial, industrial and institutional end users. With certain reporting tools, certain analytical software, compare-and-contrast applications, things that we think have value to end-use customers. And we've seen this ecosystem start to emerge for the first time. And what's interesting to us is when they look at what utilities or entities they might want to partner with, we are very logical, if not one of the most attractive or the most attractive entity to partner with because we, and probably a handful of utilities in the U.S., have the largest repositories of interval meter data. And we have something that goes beyond that in our building management system data, where we're collecting thousands of energy points at a site, not just the master meter data. So we think we're in a unique position to be in that ecosystem and to benefit from it. I think it's still too early to figure out exactly what those economic business models are, but I think we're encouraged that there are more players in that market. You can look at probably 1/2 dozen venture capitalists' portfolio, and you'll find 1 or 2 firms that sort of fit that description. And these are some interesting companies that are building some interesting technology, that could leverage the data and energy expertise that we bring to the table, and we are optimistic about that. It kind of leads into the M&A category. We have spent the last year, plus, integrating the 4 acquisitions that we made, basically, in the first and second quarters of 2011. I'm probably off by a few months in that, but it was about 4 acquisitions that we made. We made a couple in Australia. We made a technology acquisition out in Boise, Idaho. And we also made an energy efficiency company acquisition in California. And we're extremely pleased with those acquisitions, by and large. Obviously, our results in Australia are in part because of the inorganic growth that we've experienced and the success bringing those acquisitions into our fold. Still some more work to do on that. They're not fully integrated. There are systems that are planned to be more fully integrated, and there's still work to be done. But I think the people feel a part of EnerNOC more than ever before. The teams are organized around common goals and common initiatives. And I could see us getting more active in the M&A sector as we continue to be able to focus our resources, both financial and people resources, on finding the right opportunities. Thankfully, we have a very sizable working capital base of the amount that Kevin talked about, which I think is $90-plus million dollars of cash with very little debt. And certainly, we are perceived more and more, and in a more clear fashion than probably ever than before, as the acquirer and the market leader right now. And we do see that it is potentially time to get more active in the M&A space. But beyond that, I think it's going to be similar to what we've done before. We've always been a very opportunistic group that tries to stay close to our knitting. And our knitting is data-driven energy efficiency, energy data analytics for energy efficiency. And we have found that buying a little bit of the supply consultant business has led to a nice match of our capabilities, particularly in the demand response area. So we may look at those companies again. But I wouldn't say that we are likely to go too far astray from our current focus, which is to just continue doing the business that we've been doing for the last several years.

Operator

The next question is from Andrew Weisel of Macquarie Capital.

Andrew Weisel - Macquarie Research

Just wanted to follow-up on the conversation about Texas. We're following those developments pretty closely. It seems like the Commissioners are very interested but maybe a bit reluctant around reliability concerns. If I heard you right, I think you said the DR market in Texas could potentially reach 10% of peak load. Just wondering if you had any thoughts on how quickly we can see that grow and whether it's a question of the next 6 to 12 months or more of a multiyear gradual build-out. And then maybe your thoughts on EnerNOC's competitive position in Texas and how you might take advantage of that versus some of your peers.

Timothy G. Healy

Sure. So, thanks for that question, it's a pretty timely one because you're exactly right, we are spending more and more time down in Texas than ever before. And by we, I mean EnerNOC's executive leadership as well as some of the folks that we have on the ground and in Texas, that work out of Texas every day, are spending more and more time with Texas regulators and ERCOT and others. We've seen estimates of 1,000 gigawatt per year growth in that market, from a demand -- sorry, 1,000-megawatt, 1 gigawatt per year growth in the overall market in Texas, sort of on the low end. And I think that came from an industry coalition of demand response providers, and others with interest in demand response. And we certainly look at other markets. In PJM, they grew by 4,000, 5,000, 6,000 megawatts a year in the early days. And we say that it has the potential to probably be somewhere in between those 2 measurements. PJM is probably 2.5x the peak load of Texas. So you got to take their growth and maybe divide it by 2.5. So if they were growing at 5,000, 6,000, 7,000 megawatts a year, in the last 4 or 5 years, as they climbed up to as much as I guess 14,000 or 15,000 megawatts of demand response has been into future markets and PJM, gives you a sense of what the potential is. What determines that is probably a number of factors. Number one is not just price, but it's the set of rules under which demand response has to operate. How long are the program hours? Do the program hours match up with when the peak load is occurring? What is the duration of those demand response events? What type of penalties are associated with the demand response events? Measurement and verification rules, and those will play a factor. And I think what Texas has right now, as is it has a program called ERS, that interestingly enough, ERS has been around for a little while, it hasn't yet reached its maximum allowable under the ERS program because there are some basic caps associated with the amount of dollars in that program, and I think it's also capped by the megawatts as well, so that there is an implied dollars per megawatt range in that particular program. But it hasn't reached its peak not because of any one thing, I think it's a combination of -- if there were some tweaks done to the rules underneath the ERS program, and if we matched up customer reality, commercial industrial usage times, other factors that go into their economic decisions to help grid reliability, if we match that up, we could probably see a sizable growth without too much heavy lifting in what already exists there. And then you've got the combination of the fact that demand response continues to be a proven resource. It was proven to be reliable in Texas during the periods of time that Texas has actually dispatched ERS, and then you've got statistics like 104% and 102% performance statistics in PJM this summer. It just suggests to me that when they're looking at a reliably solution, they simply need to look at maybe 4 or 5 factors, try to match those factors up. And then I think you unlock 5,000, 6,000, 7,000 megawatts of demand response. And that's a number that we have gone down to ERCOT and to the Public Utility Commission and shared, both verbally and in written form, with the Public Utility Commission that we believe that there's that amount of demand response available to them, and at least 1,000 megawatts per year of overall market growth in that market

place accordingly.

Andrew Weisel - Macquarie Research

Just one last question. Any update on the CFO search?

Timothy G. Healy

Sure. We have had a search ongoing, with our partners at Russell Reynolds, for about 60 or 70 days, it's been in full swing. We have a suite of candidates right now, that we are very enthusiastic about. I would be surprised if our CFO is not in that mix. We haven't closed the search down at this point in time. We haven't offered the position to anyone and then declined. And in fact, we have been pleasantly -- I guess there's been a, not a pleasant surprise, but it's just been pleasant to receive a number of unsolicited candidates that we had never expected would want to leave their firms to come work at EnerNOC. But the comments that we continue to hear over and over again is that EnerNOC remains one of the most attractive technology companies for a public company CFO. We feel really good about it, and it's certainly our goal to have this search closed out by the end of the year. But at the same time, it's imperative that we find the right guy. And I would imagine that those on this call would agree that the amount of interesting financial complexity that exists in the EnerNOC business, because of the markets in which we operate, because of the way capacity markets and energy markets are structured in particular, means that this is a very meaty and interesting, intellectually rewarding role for somebody. And we're looking to find that person that wants to be here for the long term, and take advantage of what we think is a really unique opportunity. So we feel really good about it. We're encouraged. And if anything, we feel we may have, right now, an abundance of riches which I'm not sure we were feeling when we were doing this search on our own. So that's a plug for our colleagues at Russell Reynolds. Good for them, they've done a good job.

Operator

The next question is from Ahmar Zaman of Piper Jaffray.

Ahmar M. Zaman - Piper Jaffray Companies, Research Division

A lot of my questions have been asked already, but let me ask more of a strategic question. As you look to grow your capacity around the globe, into new markets, what are some of, would you say, the top challenges you face as you approach new markets? Whether they're outside of the U.S. or other markets in the U.S.

Timothy G. Healy

I think it remains pretty similar to what we've been facing since day 1. One of the main things that we need to overcome is just the reality that we built an electric infrastructure with a regulatory construct, which was the right regulatory construct at the time, which was a regulatory construct based primarily around building as much new infrastructure as possible. And in order to build that infrastructure and worrying about building that infrastructure, first and foremost, not necessarily worrying about optimizing that infrastructure in sort of the initial build-out of our electricity systems, we paid through a mechanism of a regulated rate of return on the capital invested. And that's something that, when you bring a demand response solution and you ask, isn't it time that we optimize the amount of infrastructure resources that we have. Well, what you need in that case is you need financial constructs that are basically different than the original financial constructs of, build it and we'll provide regulated rate of return on the capital invested. This is not unlike other industries that have gone through that type of transformation. We need to see regulatory bodies, public utility commissions, state or governmental public utility commissions understand that they can do more to incentivize utilities and create the right market structures that will provide value and a level playing field for demand response resources and energy efficiency resources. We're encouraged because the energy efficiency industry, particularly the energy efficiency industry that has existed with utility payments to those commercial industrial customers that invest in energy efficiency, to cover their cost of energy efficiency investment. That's existed and that's grown dramatically, and it's projected to be somewhere between $6 billion and $10 billion in the U.S., of energy efficiency dollars spent by utilities to drive energy efficiency into the market, which is all about optimization of existing utility resources. We think that same mentality, and that same attitude, is becoming more and more prevalent with certain regulatory bodies. And David Brewster touched on it today when he said that the U.K. is a market where they're looking at OpEx and CapEx as an equivalent means for meeting peak time usage on the electricity grid. That seems to be the number one thing that gets in the way of even more aggressive growth than the aggressive growth that EnerNOC has shown over the last 5 or 6 years.

Ahmar M. Zaman - Piper Jaffray Companies, Research Division

And if I may, given that the PJM region, specifically New Jersey, was heavily hit by Hurricane Sandy, any impact to you guys positive, or negative, from this event, near term or medium term?

Timothy G. Healy

Yes, it's too early to really get a sense of that. I think the one thing we can say is that our customers have shared stories with us, of them using our DemandSMART application, our energy management applications to track from their houses or from wherever they were, how their facilities were faring so that they knew what the electricity usage, what the effects of the storm were, whether their facilities were knocked out of power. In some cases, we were their lifeline to understanding what was going on in their facilities so that they could dispatch personnel to address certain power outages and certain power issues that they were having. Other than that, it's a little too early to tell. And I want to just thank you for the question. But, also, I should have said it at the beginning but, obviously, for those customers that are on this call, we care very deeply about them. They're part of our EnerNOC family, and we have heard stories of people being affected by this, and we send our best to all of them and hope for a speedy recovery. And, obviously, with a speedy recovery comes additional electricity usage that we can help them monitor.

So with that, I'd like to end the call. But before we close, we'd just like to clarify one guidance number that we gave for 2012, where I think we juxtaposed a couple of numbers. We may have misspoke. In our full year 2012 guidance, we expect to generate full year GAAP net loss of $0.80 to $0.95 per share on basic and diluted weighted average shares of 26.6 million. So that's an expectation of $0.80 to $0.95 per share of full year GAAP net loss for 2012, minus $0.80 to minus $0.95.

So with that, I want to thank, once again, all of the EnerNOC employees that helped contribute to another fantastic quarter at EnerNOC. As you can probably tell, we're extremely excited about our results this quarter, and optimistic about the ground we've laid for continued execution, particularly into 2013. We believe that smart energy management and the marriage of information technology with energy presents enormous opportunities for customers and utilities, and we're really excited to help continue to lead that charge. Hope everyone has a great night and thanks again for joining us. By now.

Operator

Ladies and gentlemen, this concludes today's program. You may now disconnect. Good day.

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