Pending legislation could expand scope of behind-the-meter and community solar and battery installations.
Colorado, the first state to pass a renewable portfolio standard and create a community solar program, is now host to another effort to expand the role of distributed energy. And as with similar efforts in many other states, it’s grappling with engaging utilities in the shift.
Colorado’s Senate Bill 261 would expand the range and size of solar and battery systems that can interconnect with power grids managed by the state’s investor-owned utilities. The legislation hasn’t gotten as much attention as the debate over the state’s broader decarbonization policy, but it underscores the changing nature of how utilities interact with customers that generate their own energy, and how those customers could become a more integral part of utility decarbonization efforts.
“The bill passed the Senate. It’s now in the House. And I suspect it will pass the House,” state Sen. Steve Fenberg, one of the bill’s co-sponsors, told Canary Media on Friday.
Rooftop solar and behind-the-meter batteries are costlier sources of clean energy than their utility-scale cousins. But they could also play a major role in reducing the costs of reaching a zero-carbon grid, particularly as more people install electric vehicle chargers and shift to electric building heating. In that light, SB 261 could “open up distributed generation to be more flexible for today’s energy landscape,” Fenberg said.
But distributed energy resources (DERs) like solar and batteries challenge the business model of regulated utilities that make money by building more infrastructure, and in many states still earn revenues based on how much electricity they sell to their customers. States with net metering policies that pay customers the full retail price of the power they generate in excess of their consumption also face the threat of falling revenues from solar-equipped customers. If enough customers go solar, that could force utilities to increase rates on non-solar customers to make up the difference — the key argument that’s playing out in solar-rich states like California, Hawaii and Arizona.
SB 261 will apply to investor-owned utilities in Colorado. The biggest of these is Public Service Company of Colorado, a subsidiary of Xcel Energy; it serves about half of the state’s electricity load to about 1.4 million customers, primarily in the greater Denver metropolitan area.
Xcel was the first multi-state U.S. utility to pledge to reach net-zero carbon emissions by 2050, and has been contracting for gigawatts of utility-scale solar, wind and energy storage resources in Colorado, driving the vast majority of the 1.7 gigawatts of solar installed in the state as of the end of last year.
Xcel’s latest Clean Energy Plan calls for 5,600 megawatts of additional wind, solar and energy storage capacity by 2030, which includes 1,300 megawatts of distributed solar.
Still, Xcel it faces the same kinds of disincentives to expanding customer-sited solar power as other regulated utilities. Fenberg said the utility is “not crazy about” some of the changes that SB 261 would enact.
Despite that, “we’ve had a lot of good conversations over the last six months, and they’ve come a long way,” he said. “They know we’re going to pass the bill, and they want to be part of the conversation.”
Xcel spokesperson Michelle Aguayo wrote in an email that the utility is “working with lawmakers to ensure this bill addresses customer choice for more distributed generation, the equity and cost to customers, as well as our resource planning to deliver 85% carbon free energy by 2030. It is paramount for us to keep customer bills low as we achieve our ambitious clean energy milestones. We are committed to finding a solution that benefits all of our customers.”
Expanding net metering for an all-electric future
“In Colorado we’ve had a good net metering policy for a while now,” Fenberg said. But current regulations do limit the size of a solar system to no more than 120 percent of a customer’s energy use in the previous year, he said.
“Back in the early 2000s it largely made sense to do that,” he said. “It’s supposed to be offsetting your energy use, and you’re not supposed to be overproducing energy.” But “these days, it’s a little bit different, because now people have electric vehicles, and we’re encouraging them to buy them in the future. We also have a lot of policies now that promote electrification — people are putting in heat pumps and things like that. So their energy use is growing.”
At the same time, batteries are being added to solar systems to shift excess midday generation to later in the day, when solar fades away and leaves the grid facing systemwide peak demands that must be met by “peaker” resources — usually natural gas-fired power plants financed and built for that task. But limiting the size of a net-metered system “based on what you used last year doesn’t provide you much room to produce energy to put into a battery,” Fenberg said.
There are good reasons to discourage customers from installing solar systems that generate far in excess of their own consumption, of course. To avoid this, SB 261 would limit the size of solar-battery systems to 200 percent of a customer’s projected future energy use, to “add some parameters” to its expansion, Fenberg said. It would also limit the amount of net-metering credits that can be rolled from one year to the next to no more than 100 percent of the current year’s energy use. And the bill would allow that overproduction to be donated to low-income utility customers, he said.
More sharing of distributed energy
That’s not the only part of the bill designed to share the solar wealth with customers who lack access to rooftop solar under current net-metering policy. Another section directs the Colorado Public Utilities Commission (PUC) to create rules that can allow tenants and landlords of residential and commercial buildings to share the costs and benefits of distributed solar and batteries. Rental properties are a tricky market for solar and batteries, since landlords bear the costs of systems but the benefits mainly go to tenants who pay the electricity bills.
“The other exciting part of the bill is to allow virtual net metering,” Fenberg said — a system that would enable owners of multiple properties to offset one property’s energy bills with the on-site generation from another property. This could serve as an alternative approach to Colorado’s current community solar programs, he noted.
Colorado was one of the first states to pass a community solar law a decade ago, jumpstarting similar laws that now allow some form of the practice in 20 states. But much like similar policies in other states, Colorado’s program has undergone significant changes since since then, which has spurred disputes over how to expand solar access while at the same allowing a utility to recoup the costs of delivering electricity to all its customers.
Finding the shared grid benefits of distributed energy
Another important aspect of SB 261, Fenberg said, is a provision that will would put Xcel and fellow investor-owned utility Black Hills Energy on a path to tapping the flexibility of these DERs to support the grid. Specifically, the bill calls for utilities to “develop programs and tariffs to support the adoption and use of dispatchable renewable distributed generation and storage resources to provide grid benefits.”
This builds on a bill written by Fenberg and passed in 2018 that ordered the Colorado PUC to examine ways to incorporate DERs’ values into the distribution system plans filed by Xcel and Black Hills. The goal is to find ways for DERs to play a role in augmenting or reducing the cost of annual grid investments, most often by using customer-sited solar, batteries and controllable loads to shave peak demand on constrained circuits and avoid expensive upgrades, a use case commonly referred to as non-wires alternatives (NWAs).
Similar distribution planning efforts underway in California, Hawaii, New York, Nevada and Minnesota (the latter aimed specifically at Xcel Energy, as the state’s largest utility) generally start with ordering utilities to analyze and share data on the capacity of their distribution grids to support new DERs from location to location. Most envision expanding to actively enlist DERs for their positive grid contributions and pay DER owners for that service.
That’s been a slow and complex process, however, with utilities loath to rely on DERs beyond their direct control to replace reliable, if costly, grid upgrades. Outside of a few showcase projects, only a handful of NWA opportunities across the country have led to contracts with DER providers.
Colorado’s implementation of its distribution grid planning process has been criticized by pro-DER groups for not mandating the detailed grid capacity and load forecasting data needed to identify the locations most likely to yield the greatest grid benefits. Fenberg said he’s looking forward to Xcel’s next distribution resource plan being filed later this year to see how much data it reveals.
At the same time, building the utility capability to actively dispatch DERs for grid needs is an important step in realizing the goals of the 2018 bill, he said. Batteries in particular can be actively controlled to discharge energy to help relieve specific parts of the grid. That’s a more reliable mode of delivering grid relief than the time-of-use rates that encourage solar-equipped customers to reduce energy use during the hot summer afternoons that tend to drive peak grid demands across the system at large.
New tech to connect utilities and customers
A lack of reliable utility-to-customer DER communications channels can be a barrier to this kind of pinpoint dispatch capability. Xcel hasn’t yet deployed smart meters that could help coordinate that information sharing with its Colorado customers, although it’s in the midst of seeking regulator approval to do so.
In the meantime, SB 261 would mandate that Xcel allow its customers to install “meter collar” devices that can both reduce the cost of connecting solar systems, and provide data on what’s happening with those systems.
“Allowing a meter collar could bring the cost of solar installation down a couple of thousand dollars,” Fenberg said, by bypassing the need to upgrade electrical service panels and switchgear to support the additional electric load that comes with a new installation.
Whit Fulton, CEO of ConnectDER, a company that makes these meter collar devices, noted that Colorado is the first state he’s aware of to consider legislation that would specifically mandate that utilities create standard rules for how customers can use his company’s product. Most of ConnectDER’s other customers are utilities themselves, looking for tools to gain insight into behind-the-meter DER impacts on the grid.
That would open up opportunities to serve both customer needs and utility needs in Colorado, Fulton noted. Utilities are looking for technology “that allows them to build load in a managed way, so that it doesn’t overload the grid in one fell swoop.”
Interconnection rules and incentives for energy storage
Speaking of grid interconnections, the Colorado PUC took a separate step last week that is being hailed by solar and storage advocates: It released new rules to make it faster and easier to connect DERs to the grid. The new interconnection rules were finalized after two years of wrangling. Similar contentious and complicated proceedings have been going on in solar-rich states like California and Arizona.
Sean Gallagher, vice president of state and regulatory affairs for the Solar Energy Industries Association (SEIA), said the Colorado PUC’s new policy brings more flexibility and transparency to the “highly technical” rules for how utilities permit DERs to join the grid. Theose changes include expedited “fast-track” processing for installations of up to 25 kilowatts of solar plus 25 kilowatts of batteries, as well as allowing customers to configure their solar-battery systems for different charging parameters.
Colorado’s time-of-use rates in place since 2016 have made it more lucrative for solar systems to store midday power in batteries and discharge it during high-price afternoon and evening periods. Similar time-based rates for net-metered solar customers in California have driven more of them to add batteries to their systems. The percentage of solar customers choosing to buy batteries is growing to up to one in four customers in California, Gallagher said, and “we don’t expect Colorado to be much further behind.”
Gallagher noted that SB 261 could also free up funds from the state’s Renewable Energy Standard Account (RESA), which are now dedicated to solar incentives, to also fund an energy storage incentive program being planned by Xcel Energy.
“If we’re going to meet our clean energy goals, we’re going to build a lot of solar and a lot of wind, and storage helps you balance that out,” he said.
Jeff St. John covers technology, economic and regulatory issues influencing the global transition to low-carbon energy. He is former managing editor and senior grid edge editor of Greentech Media.
South San Francisco adopts natural gas ban
- By Austin Walsh Daily Journal staff
- Jun 1, 2021
Natural gas will be banned in new residential construction in South San Francisco, as officials joined the growing regional move toward adopting reach codes requiring future development to be powered entirely by electricity.
The South San Francisco City Council unanimously adopted Wednesday, May 26, a proposal to disallow gas hookups in future housing development under the effort to limit the city’s dependency on natural gas resources.
The decision makes the city the latest in a growing group of local communities to take such a step, though the decision blessed by South San Francisco officials stopped short of some of the more aggressive policies elsewhere on the Peninsula.
To that end, officials noted that the potential ban would only be applied to future construction and that existing buildings would be allowed to keep their natural gas connections. Additionally, they limited the requirement to residential construction, keeping the commercial sector unregulated.
Councilmember Flor Nicolas, who spearheaded the city’s effort, acknowledged that the reach codes adopted are not as ambitious as some members of the local environmental community had hoped.
“This doesn’t go as far as some would want, but I think it’s a step in the right direction,” she said.
Councilmember James Coleman shared a similar perspective, while expressing optimism that the issue could be reconsidered for further action sometime down the road.
“This is a really good first wave of reach codes,” he said.
Further, Coleman said that he would be in favor of looking to expand the natural gas ban into some portion of the commercial development sector. Acknowledging such a move would not be possible in the life sciences industry that relies on natural gas for testing, he suggested office buildings could later be eligible.
Terry Nagel, chair of the Sustainable San Mateo County Board of Directors, urged officials to seek ways to expand the initiative.
“This measure is really the first step and I hope you will follow through with a commercial resolution that will address the commercial sector,” she said.
Beyond incompatibility with the biotech sector, some officials had previously shared reticence to expand the ban to the commercial sector for fear of harming local restaurants and eateries that rely on natural gas for appropriately preparing food.
The code adopted by South San Francisco contains additional carveouts for large, residential developments already entitled or within 6 months of receiving final approval. Officials supported the exemptions because they did not want the potential additional costs associated with meeting the all-electric mandate to stem housing development.
Alongside the natural gas ban, officials also approved a mandate for electric vehicle charging stations to be included in new residential development. Single-family homes would be required to install both a level 1 and 2 charger in new construction. Multifamily developments with fewer than 20 units would be required to install one of each sort for each unit. And multifamily developments with more than 20 units would be required to have 75% of the units as level 1 chargers, with 25% as level 2 chargers. Exceptions in the multi-family developments would be made for units without parking. Level 1 is the slowest EV charger available.
To further limit the local dependence on fossil fuels, the move to reach codes is often paired with an increased investment in electric vehicle infrastructure built into new residential developments as the auto industry moves away from gas.
Berkeley became the first city in the country to ban natural gas in new construction in July. There are close to 35 local cities that have explored of approved reach codes of various kinds, including San Mateo, Redwood City and unincorporated segments of San Mateo County. Because local officials can propose ordinances more stringent than the state’s Energy and Green Building codes, the policies are dubbed “reach codes.”
Nicolas lamented that South San Francisco was not on the local forefront of adopting the reach codes, but said that she felt the move was due.
“I think it’s about time for us to do something about this,” she said.
Councilmember Eddie Flores enthusiastically supported the decision as well.
“This is unquestionably a wonderful and much-needed initiative,” he said.