This is the second installment in a GTM Squared report examining the paths taken by different states to integrate distributed energy resources into their ambitious clean energy and carbon reduction plans. The first piece focused on California. This week, we’re looking at New York. The Empire State may not have the same massive share of rooftop solar, behind-the-meter batteries and electric vehicles as California, but it's pressing ahead with what may be the country’s most ambitious grid reforms.
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New York’s energy future is being driven by two key policies, both pushing distributed energy resources (DERs) onto the grid at unprecedented scales.
The most recent is the Climate Leadership and Community Protection Act, which sets a target of 70 percent renewable energy by 2030, 100 percent renewable energy by 2040 and economywide decarbonization by midcentury. New York has also set specific targets for technologies to get there, including 6 gigawatts of distributed solar, 1.5 GW of energy storage and 850,000 zero-emission vehicles by 2025.
But before the Climate Leadership and Community Protection Act, there was New York’s Reforming the Energy Vision initiative, launched in 2015 to remake the state’s energy policies and utility operation to support a grid that “encompasses both sides of the utility meter and relies increasingly on distributed resources and dynamic load management.”
After years of struggling with how to meet this mandate, New York’s Public Service Commission and the state’s investor-owned utilities have started to implement key parts of it. Utilities Con Edison, Central Hudson, National Grid, Orange and Rockland, NYSEG and Rochester Gas & Electric have released successive distribution system implementation plans with detailed plans for DER integration at large scale.
They’ve contracted a handful of non-wires alternatives using DERs to replace distribution grid investments, and they’ve piloted distribution system platforms to actively manage DERs as part of distribution grid operations.
Perhaps most important for DER developers and investors, however, are the value of distributed energy resources tariffs. VDERs incorporate wholesale market-based energy and capacity values, time and location-based distribution grid values, and environmental and social-cost-of-carbon values into a “value stack.” The goal is to tie DER costs and benefits not to static incentives, but to market-based referents of the needs of an increasingly decentralized and renewable-powered grid that change over time.
The VDER value stack: A work in progress
Today, VDER rates apply to larger-scale solar and battery projects, as well as some on-site generators and other DERs capable of grid export. In the coming years, as New York utilities finish deploying the smart meters needed to calculate VDER rates, they’ll start applying to net-metered solar, behind-the-meter batteries and aggregated DERs as well.
VDER has become “very instrumental in the deployment of primarily solar and storage projects in the state,” said David Sandbank, vice president of distributed energy resources for the New York State Energy Research and Development Agency (NYSERDA).
Of the roughly 2.5 GW of distributed solar deployed to date in the state’s NY-Sun program, and another 2 GW or so in interconnection pipelines, “the majority are community solar projects,” or community distributed generation in state policy parlance, “that are solely relying on the value stack to move forward.”
VDER has seen major improvements since 2017 when industry stakeholders feared it would undermine the value of solar, said Shyam Mehta, executive director of the New York Solar Energy Industrial Association. That’s largely because today’s VDER rates incorporate more predictability into their otherwise market-based, and thus changeable, values.
VDER’s wholesale energy and capacity components do fluctuate with prices from state grid operator NYISO, which have been falling this year as the COVID-19 pandemic has reduced energy demand. But the demand reduction value component, which changes based on the time of day and season of year that DERs generate energy, are set for 10-year periods to provide more certainty.
The demand reduction value also encourages community solar systems to store or shift export to when it’s more valuable. Only one community solar-battery project has come online so far, but about 50 are in NYSERDA's project pipeline, Sandbank said.
The locational system relief value, which encourages projects in energy-scarce grid locations, has been less valuable since it's limited to areas with higher development costs that would erode their value, though that could change over time, Mehta said.
Then there’s the “Value of E” incentive for clean power resources. That’s currently based on the higher of two values: the price of renewable energy credits in New York or the state-defined “social cost of carbon” value, minus that clean generation’s value in the Regional Greenhouse Gas Initiative market.
This complicated structure is flawed in NYSEIA's view, Mehta said. The New York Department of Conservation is reforming the social cost of carbon to inform a broad range of the state’s clean energy policies, from future VDER rates to state grid operator NYISO’s plan for pricing carbon in its wholesale energy markets, which could improve its value.
VDER’s growing pains: Depleting incentives
But critical parts of the VDER value stack are backed by fast-depleting state incentive structures, Mehta said. Over the past few years, community solar Market Transition Credits and Community Credits, which added a set value per kilowatt-hour of energy produced, have been tapped out and replaced with a Community Adder structure that offers upfront incentives based on system size.
“That impacted the net present value dramatically,” said Mark Richardson, CEO of solar developer U.S. Light Energy. Without values tied to future generation, “this market-driven VDER value stack they’re trying to get to is not sending the same market signal.”
Richardson added that VDER’s time-shifting values aren’t sufficient to encourage projects to add storage or realign solar panels westward to shift generation later into the day. “We’ve consistently run the numbers, and the advantages you’d gain on the revenue side essentially wash out on additional cost.”
That’s particularly true as incentives from NYSERDA’s Retail Energy Storage program are falling, he said. As of December, 60 storage projects in this program had built their business models around VDER, with 52 of them paired with solar, NYSERDA data shows. But the initial incentives of $300 per kilowatt-hour have been tapped out, and the lower $125 per kilowatt-hour incentives are being depleted quickly.
“The VDER rules have been relatively successful. We’ve had growing pains, but we’re now getting projects out there,” said Bill Acker, executive director of the New York Battery and Energy Storage Technology Consortium (NY-BEST). But with retail incentives close to fully consumed, the industry “really needs to see that extended.”
Interconnection bottlenecks, grid integration solutions
Interconnection bottlenecks are also slowing projects and increasing costs. DER developers around the country face lengthy grid hosting capacity analyses and risks of incurring expensive grid upgrade costs, and New York is no exception. And because NYSERDA incentives are tied to completing interconnection, projects that can’t be completed are tying up depleting funds that may not end up being paid out, Richardson said.
The New York Reforming the Energy Vision plan requires utilities to develop online hosting capacity maps. But as with similar projects mandated for California utilities, they can be short on data or lacking in detail. “Many utilities are not only still using very static values, but the assumptions going into those models are still very, very conservative,” said Shay Banton, an engineer with Borrego Solar.
Some utilities are doing better than others, notably National Grid, he said. Casey Kirkpatrick, National Grid’s distributed generation ombudsperson, noted that it updates hosting capacity down to the circuit node level, complete with backfeed protection improvements and other key issues for DER interconnections. It’s also working on a novel approach to sharing grid-upgrade costs among multiple DER projects, to avoid the “first-mover” disadvantage for those that trigger interconnection grid upgrade costs, he said.
Like other utilities, National Grid is also developing systems to integrate DERs into day-to-day grid operations. One project now seeking approval from the Public Service Commission, its Active Resource Integration pilot, will test DERs’ ability to modify their output from hour to hour to match changing circuit capacity, Kirkpatrick said.
Smart inverters that can respond to grid disturbances or utility commands will play an important role in this kind of DER-grid integration. NYSERDA is funding projects with Orange & Rockland, Central Hudson Gas & Electric and Con Edison to test smart inverter capabilities to manage DERs in ways that would avoid the need for costly grid upgrades.
The black box of marginal grid costs and non-wires alternatives
New York’s utilities are developing their latest studies on marginal costs of service, which assess the grid costs that DERs can either incur or reduce, depending on how they’re interconnected and operated. Better data on how DERs affect distribution grid operations could help reduce costs that may be discouraging development, NY-BEST’s Acker said.
“One of the main challenges we’re facing right now is the structure of standby charges from utilities,” he said. Those are designed to recover costs of wear and tear on grid infrastructure. But utility proposals from last year increase costs for batteries injecting energy onto the grid, with the highest costs ironically being assessed at the same times that VDER rates encourage batteries to supply power, Acker said.
More visibility into grid costs could also boost DERs as replacements for traditional grid upgrades, also known as non-wires alternatives. Under the Reforming the Energy Vision plan, NWAs were afforded a central role and several have been developed, including Con Edison’s Brooklyn-Queens Neighborhood Program and Central Hudson’s Peak Perks targeted demand management program.
But NWAs are problematic for DER developers and utilities alike. Utilities struggle to match DERs to the functionality and longevity of traditional grid upgrades. DER developers say opaque utility solicitation processes often lead to proposals being rejected.
“Utilities have gotten a lot of applications from batteries to solve NWA problems,” Acker said. “Our understanding is that there’s some traction happening there, but there aren't a lot of details.”
A similar challenge awaits New York’s push to close its dirtiest fossil-fueled peaker plants. In its November petition seeking $573 million more to fund clean energy projects through 2025, NYSERDA has proposed a plan to deploy DERs at substations across New York City to replace those plants’ peak capacity, Sandbank said.
Emerging models for demand-side participation
While VDER now applies to DERs that supply electricity, it’s meant to encompass DERs that control and reduce demand as well. New York has a significant demand response market, driven by grid operator NYISO’s Installed Capacity market and by utility programs, although the COVID-19 pandemic has caused big shifts in typical electricity consumption patterns in ways that have disrupted business as usual.
But the NY Reforming the Energy Vision initiative is considering a far more responsive and integrated approach — not just for traditional loads, but for the batteries, electric vehicles and electric heating systems it will need to reduce the carbon footprint of its transportation and building sectors.
That’s the goal of last month’s dynamic load management (DLM) rules from the Public Service Commission, which orders utilities to launch solicitations for contracts for at least three years in order to encourage investment in energy storage and other advanced assets. It also sets up an Auto-DLM category to increase incentives for resources that can respond within 10 minutes, rather than 2 hours.
The Advanced Energy Management Alliance trade group sees the new program as promising, although much will depend on how utilities construct solicitations due later this year, said Peter Dotson-Westphalen, senior market development director for demand response aggregator CPower. Notably, the rules allow assets under VDER tariffs to participate, although they’ll have to opt out of VDER’s time- and location-based demand reduction value and locational system relief values to do so.
DLM also credits grid export as well as load reduction, which avoids California’s barrier to batteries charging the grid under demand response rules. That allows DLM contracts to maximize the value of solar-battery systems that are growing in popularity for backup power.
New York hasn’t seen the same rush of activity as California in aggregating solar-battery customers for grid services. But some early-stage efforts are underway by utilities including Orange & Rockland and the Long Island Power Authority.
Con Edison’s residential solar-battery virtual power plant plans were put on hold after New York City’s fire department barred indoor lithium-ion battery installations pending regulations to manage their fire risks. That’s forced energy storage developers in the city to find outdoor options for batteries. While state agencies are working on allowing interior installations, “that’s pretty far into the future,” NYSERDA’s Sandbank said.
Electric vehicles are a big part of New York’s decarbonization plans, Sandbank added. The Public Service Commission’s July “Make Ready” order directs $1.5 billion in public and private investments to hit targets of 10,000 EV charging stations by the end of 2021 and more than 50,000 by 2025. Utility programs like Con Edison’s Smart Charge for NY provide price signals to ensure those EV chargers support rather that overwhelm the grid.
The future of wholesale-plus-retail market opportunities
Building a market-based structure for DERs is complicated enough on the state utility side. But NYISO’s new energy storage market rules that allow dual participation with state and utility retail programs opens the possibility for merging the two, at least for standalone batteries. NYISO’s rules for aggregating batteries or other resources for wholesale markets are expected to be ready by late 2021.
NYISO’s new rules are among the most advanced in terms of meeting the energy storage integration mandate set out by Federal Energy Regulatory Commission Order 841. Last month’s FERC Order 2222 extends the market integration mandate to DERs at large, and NYISO’s work on aggregating energy storage could serve as a model for that broader effort.
Whether or not wholesale market opportunities end up driving DER values will depend on many still-unknown factors, ranging from the complexity of complying with regulations to prevent “double-counting” of utility and NYISO-derived grid values to the price for varying wholesale market services.
“We do view the ISO aggregation rules in the future as important,” NY-BEST’s Acker said. “It does add a layer of complexity. The jury’s still out on how valuable that will be.”
