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TRANSMISSION: A federal appeals court ruling likely removes the last major obstacle for a $1.5 billion transmission line project that would import hydropower from Canada into the New England grid. (Utility Dive)
NATURAL GAS:
HEATING: In Vermont, draft rules for a system to incentivize lower-carbon heating sources propose counting biomass, renewable natural gas, and hydrogen as clean fuels, sparking objections by climate advocates. (Canary Media)
BUILDINGS: Maryland advocates say legislation passed this year slowing down implementation of clean building standards is “a significant setback” for the state. (Maryland Matters)
SOLAR:
STORAGE: The Rhode Island Energy Facility Siting Board rules it has jurisdiction over large battery storage developments, allowing it to overrule local permitting decisions for these projects. (RTO Insider, subscription)
ELECTRIC VEHICLES:
TIDAL POWER: Despite local objections, a proposed tidal power project in Maine receives a key early permit from federal regulators, resurrecting a nearly identical plan that fizzled out in 2016. (Bangor Daily News)
COMMENTARY:
GRID: The U.S. Energy Department will release a massive transmission study today that maps how the grid can be expanded to make way for more clean energy and shored up to withstand increasingly dangerous storms. (E&E News)
ALSO:
SOLAR: The U.S. Commerce Department says it will raise tariffs on solar imports from four southeast Asian countries, though it’s still determining how much those imports affect domestic manufacturing and how much to charge. (Utility Dive)
NUCLEAR: The owners of Pennsylvania’s Three Mile Island nuclear plant are seeking a $1.6 billion, taxpayer-backed federal loan guarantee to help finance plans to restart its reactor and sell electricity to Microsoft. (Washington Post)
MINING: Companies running quartz mines in a small North Carolina town say they’re trying to restart operations, but say Helene’s damages to the mines and employees’ homes may hold them up, further stalling production of a critical semiconductor component. (CNN)
CARBON CAPTURE: A recent leak discovered at an Illinois carbon capture and storage well, and the lack of communication about the incident to the public, raises concerns from advocates about whether the technology is ready to be scaled up. (Inside Climate News)
ELECTRIC VEHICLES:
HYDROPOWER: A contractor completes the removal of four hydroelectric dams on the lower Klamath River in California and Oregon, giving fish free run of the stream for the first time in over a century. (Hydro Review)
This article was originally published by the New Jersey Monitor.
After a scorching summer that saw electricity bills soar, experts told lawmakers Wednesday that they should eschew costly utility mandates, invest in technology like carbon capture, and avoid shutting down power plants before replacement power sources are up and running.
Wednesday’s hearing of the Assembly’s utilities committee was called to address complaints from South Jersey residents about dramatic electric bill spikes, and it came in the midst of New Jersey’s push for broader electrification that could push power demand yet higher.
Jason Stanek, executive director of government services for PJM Interconnection, the grid operator for New Jersey and 12 other states, said New Jersey should not advance policies that shut down power sources unless they have replacements that are operating.
The state’s last two coal-fired power plants closed in 2022, and wind projects meant to boost its generation capacity have faced cost and other hurdles.
“To minimize rate impacts, we would respectfully request avoiding any policies that are designed to push resources off the system before we have an equal and equivalent amount of replacement resources,” Stanek said.
Swings in energy supply and demand can put pressure on rates, especially when supply falls as demand rises.
Stanek noted electricity prices at its annual July capacity auction surged nearly nine times higher than the previous year. Utilities procure electricity through the auction and sell it to ratepayers at cost but can generate a profit from transmission, among other things.
Rate Counsel Brian Lipman said the higher auction prices would add between $12 and $15 to customers’ monthly electricity bills beginning in June.
Improvements to energy efficiency had helped tamp down on demand for more electricity generation in recent decades, though that trend has since reversed, Board of Public Utilities President Christine Guhl-Sadovy told the committee.
Growing electrification, increased uptake in electric vehicles and their charges, and surging demand for data centers spurred by a boom in artificial intelligence are set to push New Jersey’s energy needs up significantly, said Assemblyman Wayne DeAngelo (D-Mercer), the committee’s chairman.
“If you have a quick charging station, they use 100 amps. That’s the amount of power that’s in a small residential house,” said DeAngelo, an electrician by trade. “As we’re moving New Jersey across and increasing our bandwidth and the need for data — be mindful as AI is coming into the picture and becoming more prominent — one data center that they’re talking about building is going to need 800 (megawatts).”
That data center alone would consume nearly a quarter of the electricity produced by three nuclear power plants in South Jersey that, according to the U.S. Energy Information Administration, accounted for 43.5% of the state’s energy generation in 2022. Combined, the plants produce 3,457 megawatts of electricity.
Some suggested New Jersey’s ambitious renewable energy goals, which call for the state to draw 100% of its power from renewable sources by 2035, wouldn’t help the state meet electricity demand in the short run.
“We need to be moving towards that clean energy future, but we also need to be investing in some of the technologies of where we are today. There are technologies that can help out the use of natural gas, like carbon capture,” said Rich Henning, president and CEO of the New Jersey Utility Association.
Others suggested regulatory changes would push power prices down.
Lipman, the rate counsel, said changes to federal rules that would include more electric capacity in PJM auctions would push down rates, and he urged an end to legislative mandates that forced utilities to invest in infrastructure or raise other costs passed along to ratepayers, like a $300 million annual subsidy to the state’s nuclear plants that is due to lapse on June 1.
In New Jersey, most utilities can earn 9.6 cents for every dollar invested in addition to recouping their expenses. Those costs are typically borne by ratepayers.
“We’re forcing them to invest, and they’re not doing that for free. They’re coming back and they’re seeking their money,” Lipman said, adding new oversight of transmission could also control costs.
GRID: New Hampshire utility regulators decide not to allow consumer advocates from that state and Maine to intervene in the review of a widely criticized $385 million transmission line upgrade project because it is an “asset condition” project. (InDepth NH)
SOLAR:
AGRIVOLTAICS: At an orchard at its Hudson Valley research campus, Cornell University plans to experiment with raised solar panels that can be adjusted to shade apple trees during hot weather. (Cornell Chronicle)
TRANSPORTATION: Oral arguments begin today on two lawsuits aiming to restart momentum on the Manhattan traffic congestion tolling program, with one of the involved attorneys saying it’ll be difficult to reduce transportation emissions in New York City without it. (The City)
ELECTRIC VEHICLES: Revel opens its first 24/7 public electric vehicle charging station in Manhattan, with 10 fast chargers offering charge rates up to 320 kW. (electrek)
WORKFORCE: Massachusetts Gov. Maura Healey discusses growing the climate workforce in her state, quipping that “whoever figures out this workforce component first, wins.” (Boston.com)
PIPELINES: In Connecticut, environmental activists call on the state’s governor to block a proposed upgrade to a 1,100-mile natural gas pipeline while the expansion plan is still in its early stages. (Fox 61)
FOSSIL FUELS: Stakeholders at a Northeast fuels conference offered differing views of the future role of natural gas, with some claiming it will be “here for the long-term” and others predicting “a future where we are less reliant” on it. (RTO Insider, subscription)
GRID: A PJM Interconnection executive says the pace of new capacity is “nowhere near where we need to be,” with only 2 GW added last year compared to 5 GW the year before. (Utility Dive)
ALSO: Grid operator MISO advances plans for a $21.8 billion portfolio of transmission projects that analysts say could produce up to $23.1 billion in net benefits, partly by limiting the need for new generation. (Utility Dive)
OIL & GAS:
CARBON CAPTURE: U.S. Sen. John Barrasso, a Wyoming Republican, introduces a bill that would increase subsidies for using captured carbon dioxide to stimulate oil and gas production from aging wells. (E&E News, subscription; news release)
CLEAN ENERGY:
WIND: The state of Iowa sues a Washington-state company for allegedly dumping tons of old wind turbine blades around the state, in violation of solid waste laws. (Iowa Capital Dispatch)
SOLAR: University of Pittsburgh researchers interview four dozen rural people, including many farmers, about their views on rural solar development and find that smaller projects that work with the landscape would be more readily embraced. (Inside Climate News)
NUCLEAR:
POLITICS:
ELECTRIFICATION: The Biden administration awards nine tribal nations in Western states nearly $42 million to electrify homes with clean energy. (news release)
Across California, the companies that are trying to build charging stations for electric trucks are being told that it will take years — or even up to a decade — for them to get the electricity they need. That’s because utilities are failing to build out the grid fast enough to meet that demand.
This poses a major problem for a state that’s aiming to clean up its trucking industry. California has the most aggressive set of truck electrification goals in the country, and compliance deadlines are coming up fast.
State legislators did pass two laws last year — SB 410 and AB 50 — ordering regulators to find ways to speed up the process of getting utility customers the grid power they need, and last week the California Public Utilities Commission issued a decision meant to set timeframes for this work.
But charging companies, electric truck manufacturers, and environmental advocates are not happy with the result. They say the decision does next to nothing to get utilities to move faster or work harder to serve the massive charging hubs being planned across the state.
“It’s shocking how little the commission did here. They basically adopted status quo timelines across the board,” said Sky Stanfield, an attorney working with the Interstate Renewable Energy Council, a nonprofit clean energy advocacy group.
California’s struggle to deal with this issue is raising doubts about not only whether the state can meet its own climate goals but also whether truck electrification targets are achievable at all. States in the U.S. Northeast and Pacific Northwest with transportation-electrification targets will also need to build megawatt-scale charging along highways. Those projects will likewise require grid capacity upgrades that take a much longer time to plan and build than charging sites for passenger vehicles.
Stanfield and IREC believe that the CPUC’s decision both is inadequate and runs counter to clear instruction from California law. SB 410 orders the CPUC to craft regulations that “improve the speed at which energization and service upgrades are performed” and push the state’s big utilities to upgrade their grids “in time to achieve the state’s decarbonization goals.”
But the state’s electric truck targets simply won’t be met if charging stations aren’t built more rapidly, Stanfield said. “No one’s going to buy a fancy EV truck that costs well over $100,000 if they can’t charge it.”
IREC isn’t alone in this perspective. Powering America’s Commercial Transportation, a consortium of major EV charging and manufacturing companies, wrote in its comments to the CPUC that the decision “does not comply with either the requirements or legislative intent” of the law.
PACT asked the CPUC to set a two-year maximum timeline for utilities to build new substations and complete the more complex grid upgrades required by large EV charging depots.
But instead, the CPUC simply had Pacific Gas and Electric, Southern California Edison , and San Diego Gas & Electric report how long these major “upstream capacity” grid projects are taking today and then used the lower average of that historical data to set maximum timelines that utilities should meet in the future.
Those timelines are much, much too long, electric truck manufacturers, charging-project developers, and clean transportation advocates say. They stretch from nearly two years for upgrading distribution circuits and nearly three years for upgrading substations to nearly nine years for building the new substations that utilities say they’ll need to power truck-charging depots currently being built.
“We’ve put in millions of dollars in the facilities we’ve already upgraded, and more that are in motion,” said Paul Rosa, a PACT board member.
As senior vice president of procurement and fleet planning at truck leasing company Penske, he is responsible for the company’s transport projects, including truck-charging projects in Southern and Central California.
But those projects represent just a fraction of the 114,500 chargers required to support the 157,000 medium- and heavy-duty vehicles that the California Energy Commission forecasts the state will need by 2030.
“If we can’t get the power, this all comes to a screeching halt,” Rosa said.
The slow and burdensome process of getting new customers connected to the grid — “energization” in CPUC parlance — isn’t a problem for just EV trucks.
PG&E has been under fire for years for failing to deliver timely grid hookups to everyday commercial and residential projects — a result, critics say, of poor planning and resource management.
The CPUC’s new decision does set a 125-business-day maximum timeline for these less complicated energizations. If those targets are met by utilities, “maximum timelines for grid connections could be reduced up to 49 percent compared to current operations,” the CPUC noted in a fact sheet accompanying the decision.
“I think the commission got it right” on these less complicated energization targets, said Tom Ashley, vice president of government and utility relations at Voltera, a company building EV charging projects across the state.
But how the commission handled the larger-scale grid upgrades — the kind needed to get EV truck-charging stations up and running — is a different story, he said. “That is where the industry is really frustrated that we didn’t get the help, and the utilities didn’t get the direction.”
The state’s Advanced Clean Trucks rule requires truck manufacturers to hit minimum targets for zero-emissions trucks as a percentage of total sales over the coming years, ratcheting from 30% of all medium- and heavy-duty vehicles by 2028 to 50% by 2030.
And California’s Advanced Clean Fleets rule requires the state’s biggest trucking and freight companies to convert hundreds of thousands of diesel trucks to zero-emissions models over the next 12 years, with earlier targets for certain classes of vehicles, including the heavy trucks carrying cargo containers from California’s busy and polluted ports.
Right now, many of the plans to build charging hubs for those trucks are stuck in grid-upgrade limbo — and the CPUC decision offers little indication it will get them unstuck.
“We’ve submitted for well over 50 projects in the past two years, looking for the right property to acquire,” said Jason Berry, director of energy and utilities at Terawatt Infrastructure. The startup has more than $1 billion in equity and project finance lined up to build large-scale charging hubs, including a network that will stretch from California to Texas along the I-10 highway, a major trucking corridor.
But of the sites Terawatt has scouted in California, “about 95% of those do not have the power we’re trying to request,” Berry said. To serve proposed charging hubs in California’s Inland Empire, utility SCE has said that it will need to expand existing substations, which takes four to five years, or build a new substation, which takes at least eight years, Terawatt said in May comments to the CPUC.
Terawatt is far from the only company facing delays. In testimony to the CPUC, Berry pointed out that Tesla has told the agency that 12 Supercharger sites with 522 charging stalls are facing delays because of capacity issues in SCE territory. A state-funded electric truck-charging project in the Inland Empire is also held up due to similar constraints.
The main problem is that large-scale charging sites can be built much faster than utilities are used to moving, Berry said. “We’re building projects, maybe ideally starting at 10 megawatts and then going to 20 megawatts,” Berry said. That’s about the same load on the grid as would be caused by an entirely new residential neighborhood or big commercial or industrial site.
But while those sites typically take years to plan and build, a new truck-charging site can go from planning to completion in less than a year.
“They have to have a mechanism to start on those things, or every single project is going to be four to five years out — which is what we’re being told on so many of these today,” he said.
The same point was made by Diego Quevedo, utilities lead and senior charging-infrastructure engineer at Daimler Truck North America, which joined fellow electric truck manufacturers Volvo Group North America and Navistar to weigh in on the CPUC proceeding.
“Trucks can be manufactured by OEMs and delivered approximately six months after receiving an order,” Quevedo said in testimony before the CPUC. But fleets won’t order trucks if they lack the confidence the utility grid infrastructure will be built and energized when the trucks are delivered.”
Utilities’ grid-capacity additions are taking from seven to 10 years to “plan, design, budget, construct, and energize,” he said. Unless those capacity expansions can be sped up significantly, “electric trucks become expensive stranded assets that are unable to charge,” he said.
California’s major utilities have a different perspective. They’ve argued in comments to the CPUC that it may be difficult or impossible to move more quickly on such complicated work.
First, as utilities have pointed out, many of the things that can slow down major grid projects are beyond their control. In a filing with the CPUC, PG&E noted that “one capacity upgrade project may face an extended timeline due to lengthy environmental assessments and permitting processes, and another may encounter challenges in acquiring materials in a timely manner due to manufacturer issues.”
IREC’s Stanfield conceded that equipment backlogs and environmental and permitting reviews are barriers to moving more quickly. “But we have to make it go faster if we want to hit our climate goals, if we want manufacturers to build clean trucks.”
And there’s an even bigger challenge to making major changes to the grid in anticipation of booming demand from EV charging: the cost involved.
“Lack of funding is the big block to meet the anticipated load growth,” Terawatt’s Berry said.
California’s utilities are already spending more than they ever have on their power grids, for myriad reasons. They are passing the costs of grid-hardening investments and integrating new clean energy into the power system on to customers in the form of electricity rates that are now the highest in the continental U.S.
Electricity rate increases are an economic and political crisis in California. Keeping them from rising any further has become the chief focus of lawmakers and regulators in the past several years. Any proposals that could raise customer bills even more face a tough battle — including plans to build grid infrastructure for electric truck-charging hubs.
SB 410 does give the CPUC permission to allow utilities to increase their spending in order to meet tighter EV-charger energization timelines. But the bill also calls on regulators to subject these requests to“extremely strict accounting.”
PG&E was the first utility to submit a ratemaking mechanism under SB 410 earlier this year. The Utility Reform Network, a ratepayer advocacy group, quickly filed comments protesting the utility’s plan to create a “balancing account” that would enable it to recover as much as $4 billion in additional energization-related spending from customers — a structure that falls outside the standard three-year “rate case” process for California utilities.
“PG&E’s electric rates and bills are now so high that they threaten both access to the essential energy services that PG&E provides and the achievement of the state’s decarbonization goals, which rely in part on customers choosing to electrify buildings and vehicles,” TURN wrote in its comments.
TURN wants the CPUC to limit the scope of SB 410’s extra cost-recovery provisions to “specific work needed to complete an individual customer connection request,” rather than the kind of proactive upstream grid investments that truck-charging advocates are calling for. TURN would prefer that those projects remain part of general rate cases, the sprawling proceedings that determine how much utilities spend on their grids.
But those general rate cases can take up to five years to move from identifying the broader, systemwide analyses of how much electricity demand is set to rise to winning regulatory approval in order to build the expensive grid infrastructure needed to actually meet those growing needs. That’s too long to wait to fix the problem, charging advocates say.
At the same time, ratepayer advocates are challenging utility efforts to expand the scope of their larger-scale plans to meet looming EV charging needs. In SCE’s current general rate case, TURN and the CPUC’s Public Advocates Office, which is tasked with protecting consumers, are protesting that the utility is overestimating how much money it needs to spend to prepare its grid from growing EV-charging needs.
Terawatt and other charging developers and electric truck manufacturers argue just the opposite — that the utility isn’t planning to spend enough over the next three years. In his testimony in the rate case, Terawatt’s Berry complained that TURN and PAO are challenging utility and state forecasts of future charging needs based on outdated data, and that failing to approve the utility’s funding request will “ensure that California fails to achieve its zero-emission vehicle goals.”
Charging advocates have also asked the CPUC to create a separate regulatory process to consider the grid buildout needs spurred by large-scale charging projects. But the CPUC rejected that concept in its decision last week, stating that “preferential treatment based on project type is prohibited by California law.”
All these conflicting imperatives leave the CPUC with tough choices to resolve the gap between charging needs and grid buildout plans, said Cole Jermyn, an attorney at the Environmental Defense Fund.
The CPUC “can and should do more here. I don’t think the timelines they set here are as strong as they could have been,” Jermyn said.
At the same time, “the commission had an incredibly difficult job here. The targets are not easy to set, and they had a very short timeline to do it.”
That’s why multiple groups have asked the CPUC to focus its next phase of work on implementing SB 410 and AB 50 on a key issue: aligning grid planning and EV charging needs.
“Part of the work here is figuring out what that proactive planning looks like,” Jermyn said. “The utility cannot wait around for customers to come to them and say, ‘We need 5 megawatts of capacity.’ They need to be looking out into the future to start proactively preparing their distribution grids for all this electrification.”
At the same time, “how do you balance that need for proactive planning and investment with ratepayer investments along the way to make sure this isn’t building assets that won’t be used and end up on someone’s bills?” Jermyn asked. That will be complicated, but, he added, “I think it’s doable — especially for a state that has such clear goals.”
SB 410 also specifically called on the CPUC to take California’s decarbonization goals into account in tackling energization delays — but last week’s decision “was relatively silent on that issue,” Jermyn said.
“This is something we think is incredibly important to be in the next phase of this proceeding, because it wasn’t in this one,” he said. “We don’t know if the timelines they set are meeting that goal or not. We should figure out if they are.”
EDF has advocated for years for utilities and regulators to approve grid spending in advance of EV charging needs, noting that such spending will end up reducing costs for utility customers in the long run.
That’s because California’s utilities don’t earn profits directly through electricity sales. Instead, their rates are structured to repay their costs of doing business. More customers buying more electricity can spread out the costs of collecting the money that utilities need to operate and invest in infrastructure, which can reduce the rates per kilowatt-hour that utilities must collect in future years.
This isn’t just a California issue. Nearly a dozen states — including Massachusetts, New Jersey, New York, Oregon, Vermont, and Washington — have adopted advanced clean truck rules. They’re not as aggressive as California’s rules, but meeting them will still require grappling with the same challenges around proactive grid planning.
Voltera’s Ashley worried that the CPUC’s decision may set a bad precedent for other state regulators on this front. “The commission has a really hard job. They’re tasked with a lot of complicated policy and execution,” he said. “And at the end of the day, they have some overarching mandates, including affordability for ratepayers,” that complicate the task.
But California also has “the most aggressive targets, goals, and statutory requirements around not just electrification of transportation but electrification of other segments” of the economy, he said. “If California doesn’t get this right, who will?”
CLEAN ENERGY: Environmental and health groups call on Microsoft to power a planned Wisconsin data center with clean energy instead of We Energies’ current proposal to build new natural gas power plants. (Wisconsin Examiner)
HYDROELECTRIC: Midwest states are largely missing out on historic federal funding to shore up aging hydroelectric dams compared to other regions that tend to have larger facilities with more residents living nearby. (Inside Climate News)
SOLAR:
COAL: Two southern Illinois coal mining towns will share $200,000 in federal funding to help prepare for installing renewable energy projects. (Southern Illinoisan)
BATTERIES: Four projects across Michigan will share $355 million in federal funding to boost the domestic production of advanced batteries and battery materials to reduce dependence on foreign suppliers. (Crain’s Detroit, subscription)
GRID: A new report calls for interconnection changes in grid operator PJM’s that would expedite battery storage projects and potentially unlock thousands of megawatts of much-needed capacity. (Utility Dive)
ELECTRIC VEHICLES: Two companies will partner to install 73 electric vehicle charging stations, including 19 fast-charging stations, in the Cleveland area by the end of the year. (WKYC)
EFFICIENCY:
BIOFUELS: A new $375 million soybean crushing plant in southeastern Kansas will also produce renewable biodiesel. (Kansas Reflector)
CLIMATE: A new digital tool from the University of Minnesota allows users to map out climate predictions based on emissions scenarios, such as how much snow cover could be lost in the coming decades. (Spokesman-Recorder)
NUCLEAR: Connstellation announces a 20-year agreement with Microsoft to buy power from Unit 1 of the Three Mile Island nuclear plant in Pennsylvania, which the company says it will restart without any public subsidies. (Philadelphia Inquirer)
ELECTRIC VEHICLES:
UTILITIES: A New York lawmaker proposes a publicly owned power utility for Erie County to lower energy costs, although incumbent utility NYSEG claims the move would result in higher costs for ratepayers. (WIVB)
RENEWABLE POWER: Ten Republican governors, including New Hampshire’s Chris Sununu, band together to oppose renewable power mandates; an advocate says the group’s call for “energy choice” is “thinly veiled code” for natural gas. (The Hill)
SOLAR: A developer wraps up the installation of a two-part rooftop solar array totaling almost 1 MW at a Windsor, Connecticut, business park. (news release)
STORAGE: The American Council on Renewable Energy says PJM Interconnection should reform an accelerated process for adding capacity to let battery storage assets tap in. (Utility Dive)
EQUITY:
BUILDINGS: Former President Donald Trump has stakes in buildings that could collectively owe millions of dollars in penalties if they don’t comply with New York City’s local building emissions law. (City Limits)
TRANSPORTATION: In the Connecticut cities of Hartford and New Haven, almost a third of households don’t own a car, leading state and local officials to issue more e-bike vouchers and consider policies that encourage more bicycling. (CT Mirror)
AFFORDABILITY: In Maine, a return to pre-pandemic funding levels for a low-income household heating bill assistance program and higher fuel prices could limit how many households can receive help. (Bangor Daily News)
GRID: The federal Bureau of Land Management greenlights the controversial 350-mile Greenlink West transmission project and advances another proposed line; both are expected to expedite solar development in Nevada. (Nevada Independent)
ALSO: Experts urge California regulators and lawmakers to craft policies aimed at better leveraging distributed energy resources, including electric vehicles, rooftop solar and residential battery systems, to reduce power costs. (Canary Media)
SOLAR: The federal Bureau of Land Management approves the 700 MW Libra solar-plus-battery storage project in western Nevada and seeks public input on the proposed Bonanza solar array in the southern part of the state. (news release)
POLLUTION: Colorado advocates criticize the U.S. EPA for backing off on ordering state regulators to obtain corporate polluters’ records and make them public. (Colorado Sun)
OIL & GAS: A government watchdog agency calls on the U.S. Interior Department to tighten oversight of federal land oil and gas royalty payments. (Oil & Gas Journal)
UTILITIES:
BATTERIES:
NUCLEAR: A Bill Gates-backed company hopes to spark a U.S. nuclear plant building boom with construction of its proposed advanced reactor in a Wyoming coal community. (Laramie Boomerang)
MINING: The federal Bureau of Land Management will begin notifying tribal nations when mineral exploration work is proposed for federal lands and preemptively identify and address potential conflicts. (news release)
BIOFUELS: A Hawaii petroleum company proposes a biofuel production facility at the site of its oil refinery in Oahu. (Honolulu Star-Advertiser, subscription)
COMMENTARY:
California policymakers are searching for ways to rein in the cost of expanding the state’s power grid, which is necessary to combat climate change. Experts warn they’re missing an opportunity that’s right in front of them — taking advantage of the growing number of clean energy technologies owned by utility customers.
California ended its legislative session last month unable to pass a proposed legislative package to address rising electricity rates for customers of Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric, which serve about three-quarters of the state’s residents.
Lawmakers also failed to pass several bills aimed at boosting the role battery-backed rooftop solar systems, electric vehicles, and electric heat pumps and water heaters can play in balancing the power that’s available on the grid.
Replacing fossil-fueled vehicles with EVs, and gas heating systems with heat pumps, will increase statewide electricity demand, requiring utilities to invest billions of dollars to upgrade their grids. But those same technologies can shift when they use power to avoid the handful of hours per year when demand spikes. That’s important, because the cost of building power grids is largely determined by the size of those spikes — and in turn is a core driver of California’s energy affordability crisis.
If the state can use distributed energy resources to shave a bit of demand from grid peaks, it stands to save big. One example: In an April report, consultancy Brattle Group projected that virtual power plants, which can shift when EVs and electric appliances draw from the grid or tap into customer solar and battery systems, could provide more than 15 percent of the state’s peak grid demand by 2035. That would amount to around $550 million per year in consumer savings.
About $500 million of that would flow directly to the customers who own the devices, which could help defray the cost of buying EVs and heat pumps, two technologies that need to be rapidly adopted to meet climate goals. But because tapping into those devices would cost less than making large-scale investments, utilities — and by extension all of their customers — would save about $50 million per year by 2035, Brattle found.
“California’s affordability challenges are years in the making and are worsened by climate-driven impacts like heat waves and wildfires,” said Edson Perez, who leads trade group Advanced Energy United’s legislative and political engagement in California. “However, there are critical steps we can take now: optimizing our existing grid, maximizing the cost-effectiveness of essential grid upgrades, and fully leveraging available technologies like distributed energy resources.”
But as it stands, California isn’t putting the full weight of policy support behind these types of distributed energy programs.
Pilot programs have petered out, seen their budgets clawed back, or have been outright canceled. The scale of demand-side resources operating in the state has actually declined over the past decade, even as the state’s grid stresses have increased. And efforts to create statewide targets for distributed energy — like those that helped spur California’s rooftop-solar and home-battery leadership — have failed to gain traction, including a proposed bill in the state’s just-concluded legislative session.
Advocates say it’s time for the state to change that — especially since there’s an expiration date for capturing the value of DERs. Without policies to encourage utilities and customers to work together to realize the grid benefits of these technologies, utilities will simply build expensive, centralized infrastructure to meet rising electricity demand. Once that money is spent, potential savings can’t be realized, undermining the economic case for VPPs.
Unfortunately, utilities have clear incentives to discount the potential of VPPs as a money-saving tool, because they earn guaranteed rates of profit on capital investments like grid buildouts, but don’t for alternatives like VPPs. Plus, they’re held responsible for failing to keep pace with growing power demand — and are loath to rely on decentralized assets owned by customers in place of tried-and-true grid investments.
This utility reluctance may well explain why a roster of bills aimed at enlisting DERs to combat rising grid costs stalled in this year’s regular legislative session.
SB 1305 proposed requiring the California Public Utilities Commission to determine targets for utilities to “procure generation from cost-effective virtual power plants,” and then mandate that the utilities meet them.
Similar targets for rooftop solar and batteries have been valuable for boosting early-stage deployments in California, said Cliff Staton, head of government affairs and community relations at Renew Home, the company formed by the merger of Google Nest’s smart-thermostat energy-shifting service Nest Renew and California-based residential demand-response aggregator Ohmconnect.
“If you set the targets, you begin to provide the certainty to the industry that if you invest, there will be a return for your investment over time,” Staton said.
An early version of SB 1305 set hard percentage targets for VPP procurements by 2028 and by 2035. Those percentages were stripped from the bill later in the session, leaving the final targets up to CPUC discretion. The bill failed to clear a key legislative committee anyway.
Another bill that died in committee, AB 2891, would have expanded options for VPPs to capture the value of the peak load reductions they can provide. The legislation would have ordered the California Energy Commission to create methods for VPPs to reduce how much generation capacity each utility in the state must secure to meet peak grid demands in future years.
Only a handful of California’s community choice aggregators — the public entities that supply power to an increasing number of customers of the state’s major utilities — are using this approach today. But those CCAs have been able to start paying customers with solar and batteries for the value they can provide by reducing reliance on increasingly expensive contracts with centralized grid resources — mostly fossil-gas-fired power plants.
For more than a decade, state laws have called on the CPUC to create programs that reward customers for the energy and grid values provided by their solar panels, backup batteries, electric vehicles, and remote-controllable devices like smart thermostats and water heaters.
But these efforts have been plagued by an on-again, off-again approach from regulators and utilities. The California Energy Commission set a goal in 2023 of achieving 7 gigawatts of load flexibility from VPPs and other customer-owned resources by 2030; two of the CEC’s key contributions to that effort saw their budgets slashed this year.
Meanwhile, many of the programs launched by the CPUC over the past decade have stalled out due to overly complicated structures, or had their budgets reduced or canceled due to concerns over their cost-effectiveness.
The CPUC and the California Independent System Operator (CAISO), the entity responsible for managing California’s transmission grid and energy markets, argue that these programs have failed to perform as promised. Relying on them more would run the risk of eroding rather than improving grid reliability, they say.
But the companies engaging in these VPP programs — smart-thermostat providers like Renew Home and ecobee; solar and battery installers like sonnen, Sunrun, Sunnova, and Tesla; and demand-response providers like AutoGrid, CPower, Enel X, and Voltus — argue that overly complex and restrictive rules and compensation structures are to blame.
Adding to these challenges for would-be VPP providers is the declining value of rooftop solar. Major changes in California’s net-metering policies over the past two years have slashed the value of customer-owned solar systems, slowing the growth of the state’s leading rooftop solar market.
That’s a problem for VPP providers and advocates who see rooftop solar as an important way to help meet demand from households and businesses with EVs and heat pumps — and to charge up batteries with clean electricity that VPP programs can tap into later.
A host of bills were proposed to reset state policy to restore more value to customer-owned solar during this year’s legislative session. But only one — SB 1374, which restores compensation for schools that install solar — made it through.
California’s new rooftop solar regime does reward customers for adding batteries to store surplus solar power during the day and discharge it in evenings, when the grid faces its greatest and most costly stresses.
But solar and battery advocacy groups argue that those rewards haven’t counterbalanced the broader erosion of rooftop solar values — and that the VPP opportunities that have emerged in the state can’t yet be trusted to make up the remaining difference.
“It’s important for customers to find value in the investment they’ve made, and to help the grid and lower cost for all consumers,” said Meghan Nutting, executive vice president of government and regulatory affairs at Sunnova. “One of the problems with VPP programs so far is that it’s really tough to talk about that value proposition up front because programs are so short, you can’t count on them, or the funding isn’t there.”
At the same time, California policies that encourage people to buy other distributed energy resources — namely EVs and heat pumps — are under threat from rising electricity rates, which are eroding the benefits of switching from fossil fuels.
A controversial policy enacted this year to reduce the per-kilowatt-hour rates paid by customers of the state’s big three utilities in exchange for higher fixed costs may or may not ease that pressure. But both opponents and supporters of the policy agree that shifting the balance of fixed and variable electricity costs does little to address the underlying problems.
Programs that enlist those exact same distributed energy resources to ease grid stresses have a much clearer value proposition, on the other hand.
About half of the electricity bills of customers of California’s three big utilities is made up of fixed costs like grid investments. A majority of those investments are tied to building a grid robust enough to supply power not just for average needs, but during the few hours per year when electricity use peaks.
Those peaks are getting bigger as California’s climate goals encourage more EVs and heat pumps to come online, and the costs of dealing with that have only just begun to be built into utilities’ broader grid investment plans. A series of studies ordered by the CPUC found that adding demand from EVs and heat pumps to the grid could increase ratepayer costs by more than $50 billion by 2035 — or, depending on the approach taken, costs could be contained to less than half of that over the same timespan.
One key variable in those distinct cost forecasts is whether EVs can be programmed or incentivized to avoid charging all at once and overwhelming the grid. “Smart charging” programs that encourage EV owners to shift when they charge their cars could save California ratepayers tens of billions of dollars over the coming decade.
With the right policies and technologies in place, big new grid demands like EVs could actually become valuable resources for energy in their own right. SB 59, a bill that passed in this year’s legislative session after failing to make it last year, orders state agencies to study the proper role for regulation that could require automakers to enable their EVs to support “vehicle-to-grid” charging — sending power from EV batteries back to homes, buildings, or the grid at large.
The challenge for utilities and regulators is finding the right mix of approaches that can allow them to take advantage of EVs, heat pumps, residential solar and batteries, and other distributed resources such that they avoid either overbuilding or underbuilding the grid, said Merrian Borgeson, policy director for California climate and energy at the environmental nonprofit Natural Resources Defense Council.
“We have to be really careful with any new investment — but we do need to make new investments,” she said. “If we pull back too far on energizing loads like electric homes or EV trucks, we miss out on getting those loads connected.”
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