PROJECT EASY GREEN

EnerNOC has acquired Energy Response, the largest demand response provider in Australia and New Zealand. The purchase will increase its position in Western Australia and give the Boston-based company entry into Eastern Australia and New Zealand.

Energy Response is a player in multiple markets, including capacity, energy and ancillary services. Current customers will now be able to use EnerNOC’s full suite of applications. In Western Australia, the acquisition means that EnerNOC now has 240 megawatts under its control, up from 100.

“As Australia and New Zealand move toward a lower-carbon energy future, solutions like demand response, carbon management, and data-driven energy efficiency will become even more important, both to electricity users and the nations’ electricity grids,” David Brewster, President of EnerNOC, said in a statement.

EnerNOC made a move into the U.K. last fall and has 10 other acquisitions in total. Many of the purchases have been to broaden its offerings or strengthen its positions in different regions of the U.S., such as its purchase of M2M Communications, which delivers wireless, automated demand response solutions to the agricultural sector and primarily serves the Western U.S.

The M2M acquisition could also play into its intentions in Australia, as Tim Healy, EnerNOC’s Chairman and CEO noted that agricultural demand response is a huge untapped market worldwide. “The electricity markets in Australia and New Zealand present tremendous opportunities for EnerNOC and Energy Response to join forces to provide a broad range of demand-side resources,” Healy said in a statement.  

Down Under is a prime area for demand response with its extremely hot summers. But EnerNOC is also looking to move beyond event demand respond services, and the region could offer ample opportunity with its focus on energy efficiency, and Australia’s commitment to solar could open up demand response opportunities in the ancillary market to mitigate the intermittency of bring the renewable resources onto the grid.

Although Australia and New Zealand offer strong market opportunities unto themselves, there is also an appeal that they are relatively close to another key market: China. 

SAN FRANCISCO — Utility bills will likely rise over the summer months under dynamic pricing programs for electricity, but the overall impact on most people over the course of a year will be fairly contained.

"Ninety-eight percent of customers would see a gain or loss [in the size of their annual utility bills] of less than 20 percent," said Severin Borenstein, the Co-Director of the Haas School of Business at UC Berkeley, during a forum at the California Public Utility Commission. Borenstein recently conducted an analysis on the impact of different pricing programs.

In the study, Borenstein essentially created three hypothetical utility programs. In the first, consumers paid a flat rate of 16 cents per kilowatt-hour. In the second, consumers participated in a time-of-use pricing program where prices varied from 12 cents in the dead of winter to 39 cents in peak power periods. In the third, consumers were under a critical peak period program in which prices varied from 11 cents a kilowatt hour to $1.00 at critical peak power. (The critical peak power tariffs offer lower off-peak rates, but charge higher rates at critical hours.)

He then took four years' worth of actual data about utility bills from California consumers and ran the numbers. Here's what he found:

–There is a larger set of winners under the critical peak power program than the time-of-use rate program. However, there is also a larger set of people — 7 percent of the total — that will see their utility bills rise more than 20 percent.

–Under a basic program, lower-income consumers face slightly higher bills under dynamic pricing programs and rich people see their bills decline slightly. The aberration, however, is the result of geography. In short, wealthier people live on the coast in California and don't need as much air conditioning in the summer as their lower income counterparts in the sweltering Central Valley.

If you account for regional differences and compare what happens to lower- and upper-income customers within a distinct geographic belt, the bills of lower income customers actually go down slightly, while the upper-income households see a slight rise in bills. Thus, adjusting tariffs to account for the prevailing weather conditions would eliminate the inequality.

"Critical peak period [pricing] would be pretty close to neutral, but it would probably help poor people slightly," he said. (The Galvin Electricity Institute has found even higher gains in some studies.)

–Although bills would largely stay about the same for most consumers, bills in the summer would be higher than those in winter. However, this is the sort of thing consumers can probably anticipate. "Summer happens," he said. "It comes pretty predictably."

–To help offset any major problems, utilities could create "snap credit" programs. If a bill suddenly escalated, utilities could, hypothetically, allow customers to pay 50 percent of the total over the next few months. Credit, in other words, would be offered in a snap. Snap credit is better than existing programs that let consumers smooth out payments over an entire year because they can have the effect of reminding customers about how power consumption rises in the summer and about the need to conserve.

–Another program to help consumers understand dynamic pricing could be the practice known as shadow billing. In shadow billing, consumers under a flat rate program could be given an additional, hypothetical bill that would detail how much they would have spent (and saved) under a dynamic pricing program. Conversely, dynamic pricing customers could get a shadow bill of what a flat rate would do for them. Dynamic pricing doesn't work for every customer, so a program like this would help acclimate everyone.

–What would happen to flat rates if too many people joined dynamic pricing programs? Not much. If one-sixth of California utility customers went to a dynamic program, it could raise rates for flat payers by 1.92 percent.

–The big winners in dynamic pricing become the utilities. Once dynamic pricing gets accepted, there is evidence that these programs can help reduce peak power and hence the need for extra peak power infrastructure that helps a utility lumber through a hot summer's day. A few years ago, Georgia Power said that its peak pricing program has helped it reduce peak power by 16 percent, according to Borenstein.

–These programs may not make immediate economic sense if a region or utility has excess capacity. Singapore, for instance, hits 6 gigawatts at its peak but has a 10-gigawatt capacity. California has some excess capacity at the moment. Nonetheless, every region invariably hits a point where power production approaches demand, so it's good to get practice.

Earlier this week, EnerNOC had its largest ever demand response event, providing 1,200 megawatts from about 1,600 sites on the Eastern seaboard. Despite the growing role of demand response services, the companies that provide negawatts are defending their territory.

In an open letter to electricity customers on Wednesday, CEOs from EnerNOC, Comverge and Energy Curtailment Specialists (ECS) made their case against a proposed rule change in the PJM Interconnection that wouldn’t compensate negawatts contributed during a peak load event that were above and beyond a customer’s pre-defined peak load contribution.

If a company has been assessed as being able to provide 1.5 MW during a DR event, and then curtails 2 MW during an event, that difference would receive no payment under the proposed rule, according to R. Blake Young, President and CEO of Comverge.

“The demand response community advocates that if a customer is in fact providing more load reduction than their peak load contribution factor, then they should be compensated,” said Young, “especially in an emergency situation.”

Back in March, the Federal Energy Regulatory Commission ruled that demand response must receive the same payment as generation resources in wholesale markets. Curtailment service providers lauded the decision by FERC. But the decision was just the beginning of a more nuanced battle over how negawatts are measured and compensated in a changing landscape of energy sources and services.

The letter makes the case in more general terms, pitting DR providers against incumbent generators. They argue that demand response has earned its place at the table of capacity markets. The argument is not without merit. The 2014/2015 PJM capacity auction saw more than 14,000 MW of demand response bid into the market, more than a 50 percent increase over the previous year. “We see demand response continuously proving itself,” said Tim Healy, CEO of EnerNOC.

The megawatts that went to demand response have an estimated value of $650 million, according to Healy. “That’s 650 million reasons why generators are restless,” he said.

PJM is the largest and most mature capacity market for demand response, but all of the Independent System Operators are required to determine a price level at which demand response dispatch is cost-effective compared to generation. The tariff changes for all of the ISOs need to be established by July 22.

Of course, once all of the proposed tariff changes have been submitted, FERC will be able to approve or reject them. Although the decision in March was a final ruling, this is where the nitty-gritty work begins. DR providers are hoping that, like the decision that demand response should be compensated the same way as generation, FERC will again rule on the side of this relatively new resource.

Demand response may have arrived, but in PJM, it still only makes up about 10 percent of the capacity resources for the 2014/2015 market. “We realize we’re not as large a resource contributor as legacy generators,” said Young, “but that doesn’t mean the resource being provided isn’t as impressive.”

The voice of DR providers is already being heard at FERC, but this letter asks customers to also get more involved. “What’s most egregious is that because demand response passes cost savings on to electricity consumers, it is the electricity consumer who has the most to lose if the incumbents prevail in discrediting this resource,” the demand response CEOs wrote.

Ultimately, however, it will be FERC, and not the DR customers, that will decide whether the tariff changes fit the ruling to pay the full market price. Even after all of the filings in July, the debate is likely to continue as grid operators must also put together studies that look at the requirements for and the effects of this ruling and file the results in 2012.

OpenADR Alliance isn’t waiting for federal standards to push beyond the edges of California. In fact, it’s gunning to be the national standard. The nonprofit corporation, which fosters the development, adoption and compliance of the Open Automated Demand Response standard, is expecting to have certified interoperable automated demand response products by the end of this year.

The first version, OpenADR 1.0, was developed at Lawrence Berkeley National Lab, which is a member of the alliance. The products, however, will be based on OpenADR 2.0, which is being completed by the Organization for the Advancement of Structured Information Standards, or OASIS.

The second version will ensure interoperability between different software products and the utility’s back end. Having certified products should move the market closer to plug-and-play demand response, according to Girish Ghatikar, Demand Response Standards and Codes Lead at LBNL.

The alliance has more than 30 members in just six months, with Digital Lumens, an LED company, as the most recent addition. Although the standard is only mandated in California, national players, such as EnerNOC, are supporting OpenADR, likely because it is the front-runner to be a national standard.

“Members of the OpenADR Alliance are working quickly to get a testing and compliance program in place by the end of the year,” said Mary Ann Piette, chairwoman of the OpenADR Alliance and research director for PIER Demand Response Research Center at LBNL. “This program will help the National Institute of Standards and Technology (NIST) in the deployment of interoperable Smart Grid standards.

At LBNL, they’re confident that the standard is ready to break out. Sila Kiliccote, Commercial Sector Demand Response Lead at LBNL, said that she’s been traveling east to gauge and garner interest in the standard. NV Energy and Bonneville Power Administration have both identified OpenADR in their smart grid plans, while Con Edison is also using the standard in a demand response pilot that’s currently underway.

The U.S. Green Building Council is also looking into offering demand response credits for LEED-certified buildings, and Kiliccote has been talking with the organization to have OpenADR-based programs approved for those credits.

More than 60 companies have already built products using OpenADR and more will come once a standard is finalized within this year. Although demand response already seems like a busy space, there is a huge gap in solutions for the small commercial market and questions about how demand response will play in regulation and non-spin markets. For the researchers at LBNL, they’re hoping their research will answer some of those questions — and bring OpenADR to every corner of the market.

Powerit Solutions is on a roll lately. The automated demand management company, which focuses on heavy industry, raised an additional $5 million in funding in March and brought on a new CEO.

The double injection was geared to help the company expand its channel partners, the first of which was announced this week. Powerit has a new agreement with Inductotherm Corp., the market leader in equipment for the melting of metals and materials to take Powerit’s Spara system to the metals market.

The world of smart grid, and demand response specifically, feels a lot like a land grab there days, according to Bob Zak, General Manager and President of Powerit Solutions North America. Having strategic alliances is key if you’re going to plant your flag in some prime real estate.

There are about 3,000 metals melting foundries in the U.S., ranging from about 3 MW on the small end to about 40 MW for steel plants, according to Zak. The managers already have working relationships with companies like Inductotherm, and so Powerit is leveraging that domain experience to work with their customers.

“We want to have a relationship with one of the most important players in the business,” said Zak. “It drives deeper and wider customer relationships.”

Powerit is approaching the market by looking at verticals. It already has a foothold in the food and beverage manufacturing business and some presence in the metals market. Whereas other companies have found that heavy manufacturing does not lend itself well to demand response, Powerit has found that its automated, tailored solution to each industry can help those companies make the most out of demand response programs — including spinning reserves and, eventually, regulation services.

At one superalloy plant in Muskegon, Mich., Powerit helped cut the Cannon-Muskegon Corporation’s peak demand by 26 percent at that location.  Zak said that companies like Inductotherm find that having Powerit’s software as part of their offerings is a huge value-add in markets where energy bills are a risk factor to the business.

“You need a system that’s flexible so they can integrate it well with their process,” said Zak. “And if you can put those two together and scale it, now you have smart grid movement instead of a smart grid hobby.”

As far as future partnerships, of which Powerit expects to announce many this year, they might not all come from equipment makers. The Seattle-based company is also looking into commercial buildings — and could team up with a building controls player in the future. The company, which was founded in Sweden and then essentially exported to the U.S., is returning to its roots, looking at opportunities in Europe, where Zak said demand response is even less mature than in the U.S.