Even in the most forward-thinking states, progress on folding DERs into the grid has been uneven at best.
Distributed energy resources (DERs) is an expansive term, including everything from backup generators to microgrids.
In some states with 100 percent clean energy mandates, like California and Hawaii, the focus is on solar — lots and lots of it — and the tools needed to integrate this massive new grid edge resource.
Batteries are another important tool in the kit, but so are air conditioners, water heaters, refrigerators, pumps, and other behind-the-meter flexible loads — not to mention electric vehicles.
Distribution utilities are going to need all of these DERs to manage the paradigm shift to come as renewables grow to a majority of the grid’s energy. But integrating DERs that are customer-owned and outside direct utility control is a challenge on many levels.
There are some commonalities in how utilities, regulators and DER providers are progressing in the most forward-thinking states. But the work is hard, it takes a long time, and it hasn’t yet yielded the expected outcomes in all cases.
California has been and remains at the forefront of the country’s DER revolution.
The Golden State is by far the biggest market for solar, behind-the-meter batteries and plug-in electric vehicles. And its ambitions are grand, with a mandate for 100 percent carbon-free energy by 2045 matched by an impressive quiver of policies supporting DER growth, from laws requiring solar on all new homes starting next year to multi-billion dollar EV charging infrastructure investments.
But the past few years have been spectacularly challenging ones for California energy policy, led by Pacific Gas & Electric’s bankruptcy and the threat of more wildfires leading the state’s other big utilities toward insolvency.
California has been canceling new natural gas plants in favor of cleaner alternatives, and plans to close its last nuclear plant by 2025, leaving state regulators worried about near-term shortfalls in capacity.
Then there’s the challenge of getting California utilities to include DERs in their multi-billion dollar annual distribution grid investment plans.
Prompted by a 2013 state law, this groundbreaking effort has yielded a host of metrics for measuring the capacity constraints and locational benefits of DERs. But the state’s efforts to turn these valuations into real-world non-wires alternative (NWA) projects has so far yielded only a handful of solicitations so far, with no winning bids yet announced.
Even so, California is taking important steps toward aligning its DER goals with the pressing goal of reducing wildfire risk from its energy infrastructure.
If Hawaii doesn’t top California on this list, it’s only because California is so much bigger.
Hawaii has become a poster child for how DERs at scale can transform a series of island grids powered by expensive imported oil. It also highlights the challenges of integrating renewable resources without the resources of a continental grid as backup.
Hawaii was the first state to adopt a 100 percent renewables standard, and it has since embarked on a wide-ranging set of policy reforms aimed at enabling DERs for grid services and customers as “prosumers” of energy and participants in the grid.
Hawaii’s renewable goals and unique geography are pushing the island utility into new territory, like the capacity-promoting features built into its recent spate of record-breaking solar-plus-storage contracts, or the mix of grid services, energy storage and dispatchable renewables RFPs it put out last month.
State regulators have been pressing utility Hawaiian Electric to engage with customer-owned solar, batteries, EVs and other resources in a major way. The utility has responded with a host of groundbreaking pilot projects featuring batteries from Stem and controllable water heaters from Sequentric.
But Hawaii’s record-setting rooftop solar growth has slackened significantly since it ended net metering in 2015 and replaced it with more complicated tariffs.
And state regulators and solar and energy storage companies have been at odds with Hawaiian Electric over its first efforts to integrate DERs as grid replacements.
New York’s clean energy push includes a Green New Deal that requires 70 percent renewables by 2030, a complete decarbonization of the state’s electricity system by 2040, and the near-elimination of carbon from New York’s entire economy by 2050.
The Empire State is rapidly growing its offshore wind capacity, and planning to back up its renewables growth with a mandate for 1,500 megawatts of energy storage by 2025.
But New York’s primary vehicle for DER-grid integration, its Reforming the Energy Vision (REV) initiative, hasn’t shown the kind of rapid progress on its multipronged goals that many stakeholders had hoped for.
Complaints have centered on the state’s non-wires alternatives efforts, which have seen limited success in opening the hundreds of megawatts of potential projects identified by utilities to third-party developers. While utilities have executed a few showcase projects, later opportunities have been pulled back or canceled.
Even so, the REV initiative has yielded a massive amount of work and data on how DERs can be integrated into future grid operations and investments.
One of the most ambitious parts of REV involves each utility creating a distributed system platform to integrate DERs and grid controls, not only to manage the grid but to reward DERs for their participation. National Grid’s Distributed System Platform pilot with the Buffalo Niagara Medical Campus and startup Opus Onebeing is the first to break ground.
New York City, which passed its own ambitious Green New Deal aimed at aggressive efficiency gains for its biggest buildings, has also seen customer-sited energy storage growth stymied by the Fire Department of New York’s stance on safety for indoor battery installations. Con Edison was forced to postpone its 4-megawatt-hour distributed solar-storage virtual power plant contract with SunPower and Sunverge, after it couldn’t reach agreement with state building officials and FDNY on how to permit its behind-the-meter lithium-ion batteries.
Massachusetts has set increasingly aggressive renewable energy goals in recent years, including last year’s comprehensive energy bill that created new policies driving DER growth in the state.
These include its Clean Peak Standard, to ensure a growing portion of peak-hour electricity comes from clean sources rather than gas peaker plants, as well as the Solar Massachusetts Renewable Target (SMART), which pays solar customers for each kilowatt-hour produced and incentivizes energy storage as part of the mix.
Massachusetts is also emerging as one of the earliest opportunities for DERs to participate in wholesale energy markets, under the groundbreaking efforts of regional grid operator ISO New England. We’ve been tracking some of the industry moves in response to these opportunities, including Sunrun’s 20-megawatt bid in ISO-NE’s forward capacity auction, NEC Energy Solutions’ 20 megawatts of projects for municipal utilities seeking to reduce transmission costs and capacity charges, Stem’s 28 megawatts of projects across the state, and Engie’s move to pay developers up front for dispatch rights to use their batteries in the ISO New England wholesale markets.
Still, Massachusetts has seen its share of challenges in implementing its clean distributed energy vision.
DER developers have complained that the state should get rid of the SMART program’s requirement of a separate meter to credit the batteries included in solar systems, noting that other states have been able to tap existing metrology or smart inverter data to fill the same needs.
Meanwhile, delays in a National Grid transmission grid study are threatening to push many megawatt-scale distributed solar projects past the deadline for receiving federal Investment Tax Credits.
Arizona differs from the rest of our states in that it doesn’t have a 100 perecnt clean energy mandate, at least not yet.
A ballot proposal calling for 100 percent clean energy by 2045 was defeated by voters last year after significant lobbying and advertising from the state’s utilities.
Arizona has been the epitome of anti-rooftop solar utility moves in the past. The Arizona Corporation Commission ended the state’s net metering policies in 2016 in exchange for a set of lower rates for compensating solar exports.
Utilities responded with programs that drew the ire of solar installers — Salt River Project’s demand charge and Arizona Public Service’s time-of-use rates for solar customers among them — but which helped boost the business case for solar-storage systems.
At the same time, APS, which has been adding massive amounts of battery storage to its utility-scale solar portfolio, has also been running some of the country’s most ambitious DER integration projects.
Its Solar Partners Program, launched in 2014, has made APS the first utility in the country to deploy and remotely control advanced inverters at customer solar sites to manage those resources for grid services.
And its pilot project with DER integration technology provider EnergyHub, launched in November, is integrating smart thermostats, water heaters and beind-the-meter storage in an effort to both decrease peak late afternoon and evening demand and actually increase load during midday solar peaks.