Hawaiian Electric arguably faces the toughest renewable and distributed energy integration challenge of any utility in the country. But that doesn’t mean state regulators are giving the company a blank check to charge its customers for managing the technology shift — or allowing the utility to leave customers out of its green energy transition.
On Friday, HECO submitted its second attempt at a grid modernization plan that will have to pass muster with state regulators. The new plan calls for spending about $205 million over six years, a steep drop from the approximately $340 million plan that was rejected by the Hawaii Public Utilities Commission in December.
In its December order, the commission noted their concerns about the cost-effectiveness of the proposal and its potential lack of flexibility to adopt emerging technologies. They also highlighted that it did “not specifically address how the companies intend to integrate customer-sited assets in the near term and long term.”
HECO acknowledged those concerns in its new draft plan, which includes months of outreach with some 200 customer and stakeholder groups, and is now open for public comment in advance of final submission in August.
At the same time, the utility serving five of Hawaii’s islands is facing “a much different starting point for modernization than any other state,” with a greater proportion of renewable and distributed energy than any other utility in the country, combined with truly “islanded” power grids that rely largely on imported oil to provide core generation, according to the plan.
As of the end of 2016, about 26 percent of HECO's combined customer energy needs came from renewable sources, according to data released earlier this year. Of that, customer-owned solar dominated with 34 percent of the total, followed by wind at 29 percent and biomass at 19 percent. The share of energy provided by renewable was even higher outside the state’s most populous island of Oahu, reaching 37 percent on the islands of Maui and Molokai and 54 percent on the Big Island.
As for solar penetration on its distribution grid, about 80,000 customers, or some 15 percent of its total customer base, are equipped with rooftop solar, with the proportion rising to one in four for single-family homes. This is a higher percentage than any utility in the country, although changes in the state’s net metering policy have slowed PV growth in the past 18 months.
These are challenging factors for a utility that can’t draw from other regions for energy, capacity or grid stability — and they’ll only grow more pressing as the utility seeks to meet state renewable mandates of 48 percent by 2020 and 100 percent by 2045.
Rooftop solar isn’t its only distributed energy resource that HECO must manage. The utility expects nearly 90 megawatt-hours of customer self‐supply energy storage, and 115 megawatts of demand response resources — nearly all of it in the form of energy storage — to be integrated by 2021.
All of this requires HECO to consider the “DER energy export to the grid, DR programs, and potential for aggregated DER and DR services. We must also consider how they relate to the overall management of the grid, including all existing resources currently connected.”
Unfortunately, “traditional distribution engineering architecture and designs are inadequate to address these issues,” the plan states. Or, as HECO wrote, “the grid we have is not the grid we need.”
To build this new grid while meeting the terms of the PUC's December order, HECO’s new draft plan “focuses on near-term improvements that provide the most immediate system and customer benefit but don’t crowd out future technological breakthroughs,” it noted.
One big shift for HECO is to move away from its previous plan to deploy smart meters across its entire service territory, and instead to deploy them “strategically,” and “primarily for enhanced sensing and monitoring purposes.” That could include supplying meters to customers with private rooftop solar on saturated circuits, or those who want to participate in demand response or variable rate programs, and would likely use a hosted, software as a service option for the deployment at first.
Instead, much of its first phase would be aimed at “adding sensors and control systems onto circuits where the high level of private rooftop solar can produce potentially damaging variations in voltage and limit addition of new systems,” the utility wrote. That's something HECO has been testing with solar installers, “smart” inverter makers, energy storage providers and distribution grid power electronics systems.
Indeed, HECO’s new plan would include “reliance on advanced inverter technology to enable greater private rooftop solar adoption,” a move that could put Hawaii ahead of California in terms of adopting new smart inverter regulations for mass-market solar systems. However, HECO noted, the IEEE 1547 standard for smart inverters “leaves quite a lot of flexibility for manufactures to select different communications and protocols,” making it hard to put into practice today.
HECO’s plan would also emphasize sensors, automated controls and voltage management tools for specific solar-rich distribution circuits, as well as an “expanded communication network giving system operators greater ability to 'see' and efficiently coordinate distributed resources, along with smart devices placed on problematic circuits and automation for improved reliability.” To support this rollout of distribution grid devices, HECO is seeking to deploy a multi‐purpose mesh network capable of peer‐to‐peer traffic and using an open standard such as that being developed by the Wi‐SUN Alliance.
All of these efforts should be coordinated to ensure that spending on current technology doesn’t leave HECO stuck with stranded assets as new technologies come into their own, the draft plan noted. HECO has been working with research institutions and the Department of Energy on a long-running set of projects meant to understand, integrate and control intermittent, distributed renewable energy at island scale, as we’ve covered in some detail at Greentech Media and in the pages of GTM Squared.
At the same time, some foundational investments, in particular software systems (e.g., distribution management systems, demand response management systems and distributed energy resource management systems), “are necessary to initiate related services or programs,” it wrote.
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