by Jeff St. John
September 19, 2016

Utility Hawaiian Electric has built one of the country’s most comprehensive technology platforms for managing an island grid with lots of solar and wind power as its chief source of supply. Now it’s getting ready to launch the plan that lies behind the meter, under customer control -- the demand side.

Late last month, Hawaiian Electric filed an implementation timeline for its big demand response overhaul -- one that’s officially been underway since 2014, but which has been mired in a bit of a lull over the past year or so. That’s mainly because it’s been subsumed by larger issues, such as the Hawaii Public Utilities Commission’s demands for rewrites of the utility’s overarching power supply improvement plan (PSIP), and of course, its two-year, politically contentious courtship with its recently rejected suitor, NextEra Energy.

But with NextEra out of the picture, and work on the utility’s revised PSIP moving ahead, the way looks clear for an aggressive speeding up of Hawaiian Electric’s plan, according to this new timeline. By the end of this year, the utility wants to pick a handful of vendors to deploy multiple customer-side technologies, including a handful of “integrated demand response portfolio” demonstration projects, set to start installations and enrolling customers by year’s end.

By summer 2017, the utility plans to develop grid service purchase agreements with its vendors to standardize how it can offer the four grid services it has created as part of its new demand response vision. To procure these services, it will develop turnkey contracts with vendors under its GSPAs, as well as self-administer assets to be covered under its “rates and riders” proposals, due by mid-2017.

Over roughly the same period of time, it will be selecting and implementing a demand response management system (DRMS) software platform, to integrate all of these endpoints into its broader grid operations. The end goal, according to the timeline, is a “go-live date” of early December 2017.

By then, “all enrolled [demand response] resources will be migrated to the DRMS platform and positioned for flexible and dynamic dispatch,” the utility wrote. That’s only 12 months from the start of installing its first demonstration projects, putting a lot of pressure on the utility to move quickly.

For Rich Barone, Hawaiian Electric’s demand response manager, it’s an exciting time. Over the past year and a half, “We’ve been in a holding pattern -- no more program expansions, no more modifications unless we can’t avoid it,” he said in an interview last week. But Hawaiian Electric already has a range of demand-side resources to work with and ready to go, he said.

Those include old-fashioned curtailment deals with big industrial customers and load control switches for household air conditioners. But it also includes partners like Honeywell, Stem, Bidgely, Steffes and Sequentric, and a host of home-state startups with pilot projects using the latest technologies, like automated smart thermostats and office building HVAC systems, remote-controlled water heaters, behind-the-meter batteries, and electric-vehicle chargers.

With the implementation plan now back on track, it’s only a matter of months before the utility will ask a select few vendors from a shortlist of nine picked last year to start installing these kinds of technologies at their first sites. “We’ve got a little bit of everything,” he said, adding that the projects “are pretty cool.”

Building a demand response structure from the ground up

The whole thing got started back in 2014, when the PUC ordered Hawaiian Electric to “pursue the development of a holistic program that would deliver a whole suite of services,” Barone said. The utility responded with an integrated demand response portfolio plan, or IDRPP, a 155-page document (PDF) that took a first stab at fulfilling the PUC’s request for a top-to-bottom review of its demand-side management programs.

Still, the IDRPP was only one part of an even bigger wave of new energy regulations for the utility and the state coming at that time. These included the start of its eventual switchover from solar net metering to a new regime for compensating owners of rooftop solar, as well as broader smart grid investment plans.

Underlying all of it was the requirement from the PUC to include more and more renewable energy into the state's energy mix. Hawaii is saturated with rooftop solar, and it’s also well stocked with wind power. This influx of intermittent, weather-dependent energy is causing multiple challenges on Hawaiian Electric’s island grids, from localized voltage stability and back-feeding issues on solar-rich circuits, to system-wide supply-demand balance disruptions that hurt the bottom line at the islands’ central fossil-fuel-fired power plants.

But under the state’s 100-percent-by-2045 renewables mandate, Hawaiian Electric and the rest of the island state’s utilities will eventually have to manage a grid that’s completely fossil-fuel-free, much more reliant on inverter-based energy resources, and lacking much of the inertial stability provided by generator turbines. That’s a tall order -- and it can’t be done without enlisting customers’ help.

Hawaiian Electric is arguably ahead of most mainland utilities in setting the stage for customer-utility integration. For example, it’s been working since 2012 with Honeywell on implementing OpenADR, a key technology standard for communicating energy and pricing data and instructions between the two sides of the meter.

To date, the partners have connected some 30 buildings, representing 7 megawatts of load-reduction capacity, to test the ability of loads to respond within seconds to grid frequency regulation orders, said Yvette Maskrey, Honeywell’s smart grid solutions division manager for Hawaii.

Since that initial pilot ended in 2014, the buildings have served as operating reserves for the utility, while Honeywell has upgraded the demand response automation servers (DRAS) that control each building to run the latest version of OpenADR 2.0b, Maskrey said.

It’s also shown that it can operate with DRAS units from four different manufacturers -- IPKeys, Encycle, Universal Devices and GridLink -- which is an important step for a utility that’s being asked to open up participation to multiple parties. “I would say that the technology working right gets us to coming close to fulfilling the market potential,” Barone said.

From traditional utility to quasi-grid operator 

Beyond integrating different technologies, Hawaiian Electric is seeking to integrate a lot more than traditional, early-warning, manual-style demand response in its new platform. The utility’s new list of grid services, first laid out in its 2014 IDRPP, looks a lot less like traditional utility DR contracts, and more like a plan to transform each island’s grid into a miniature version of the regional transmission organizations and independent system operators that operate interstate grids on the mainland.

HECO’s grid service list does include old-fashioned capacity, and the ability to reduce energy consumption for at least three hours at a time to meet demand plus reserve margins. But it also includes fast-responding frequency regulation, fast-ramping non-spinning reserves, and even contingency reserve for the “sudden loss of the single largest on-line generator” on the island in question.

In the summer of 2015, Hawaiian Electric shortlisted nine vendors with a combination of “credible proposals” for projects meant to serve all of these different grid services, Barone said. According to the timeline, it’s planning this week to ask those vendors to submit demonstration project proposals, under an addendum to its original RFP filed earlier this year.

By mid-October, it expects to have determined which ones have won awards and begin contract negotiations, and by December, it expects to have “customer enrollment and hardware installation initiated for at least one demonstration project for each of the four grid services.”

While the utility hasn’t named its shortlisted vendors, it’s likely that some will include existing partners, such as Honeywell and its OpenADR-connected buildings. Those were designed to test the ability of HVAC systems and other loads to respond to so-called “fast DR” signals, which could make them available for fast-responding ancillary services as well as capacity, although they haven’t been actively used for that purpose yet.

Likewise, Stem’s megawatt-plus fleet of behind-the-meter batteries installed in commercial buildings in Oahu, part of an ongoing pilot project, could be a likely resource. On the residential side, Hawaiian Electric is working with Shifted Energy to deploy 499 grid-interactive water heaters at the Kapolei Lofts housing project being developed by Forest City, capable of turning off and on within seconds to respond to frequency regulation signals, as well as providing longer-term load reduction.

The next big steps come in February 2017, with the filing of a “revised DR portfolio” that will lay out the structures and tariffs for expanding this framework to more vendors. “We’ll take these nine listed vendors, and we’ll select the ones we like the best to be our first aggregators -- our first distributed services providers,” Barone said. At the same time, it will start accepting “information requests” from vendors about its new demand response plan in March, and have replies to those queries by April.

By the end of May 2017, the utility expects to have made the final selections of its “turnkey grid service providers,” under a request for proposals that will lay out contract terms for each of its four grid services -- albeit “roughly defined” ones, Barone said. These four- and 10-year contract structures will also serve as the starting point for designing the aforementioned grid service purchase agreements (GSPAs), to allow for some measure of apples-to-apples comparisons between widely varying types of resources.

Creating markets for distributed energy and establishing grid controls

All of this work is being done with the understanding that the PUC “is indicating it wanted to explore a market-based approach,” Barone noted. That’s why it’s working on the GSPA -- to make sure that its next round of demand response contracts can be repeated on a predictable pattern for years to come, and open the market to competition.

At the same time, “the market itself told us that might not be fantastic” right now, with a limited number of vendors ready to meet the utility’s short-turnaround timeline, he said. “I’m not sure until you have market liquidity whether or not you want to do that.”

For that reason, Hawaiian Electric is also planning to “self-administer” some DR programs, although the rules for this distinction are still being worked out. Some of the load-shifting and capacity-enabling the utility is after will also be accomplished by changes to rate structures and time-variable pricing, he added.

The utility will also shift over its existing demand response programs, which account for about 35 megawatts of capacity, into its new grid services framework.

Finally, Hawaiian Electric will need its demand response management system (DRMS) software up and running to coordinate all of these new resources within the framework of its larger smart grid operations. In a Sept. 2 filing (PDF), Hawaiian Electric did ask for regulator permission to extend its contract with Omnetric, the joint venture between Siemens and Accenture, for DRMS software integration -- and Siemens has been a partner on the utility’s cutting-edge grid technology rollouts.

We’ve been paying close attention to Hawaiian Electric’s comprehensive approach to distributed energy integration. It includes the utility's foundational Distributed Resource Energy Analysis and Management System (DREAMS), which involves solar and wind power-related weather forecasting, distribution automation and control systems integration, and its Sustainable and Holistic Integration of Energy Storage and Solar (SHINES) effort under DOE’s SunShot program.

The demand side of the equation, meanwhile, is being handled under its Integrating System to Edge-of-Network Architecture and Management project. That’s the natural interface between grid operators and their distributed and the demand response partners and customers providing behind-the-meter grid services.

“We’re going with a system-of-systems approach,” Barone said. “Our distributed energy resource management system [DERMS] will be the head-end for a number of systems,” including the DRMS, and “all the other companies’ engines that aggregate portfolios of things.”

That, in turn, could allow grid operators to tap these third-party assets, not just for system-wide needs, but also for location-specific needs as well. “You could have locational issues handled by any one of those services,” he noted. “Capacity, for example, is really supply-demand balancing, using shifting curtailment or load building to help manage that.”

“That’s one that clearly has system value. An ISO has to do that -- but you could also see that being very highly valuable at the substation-down level -- or the transformer-down level.” Concepts like these aren’t specifically covered in Hawaiian Electric’s new big push for redesigning its demand response programs, but they’re part of the broader set of issues the utility is facing.

It’s important to note that Hawaiian Electric’s new demand response timeline hasn’t yet been approved by regulators, leaving many of the specific dates and implementation steps open to change. But as Barone noted, the utility has been waiting a long time to get its demand-side work up to speed. “Let’s get the show going here,” he said. “Let’s not sit in a holding pattern. Let’s do something.”