More than 1.5 million light-duty electric vehicles have now been sold in California, beating by two years the target set by a governor’s executive order in 2012.
The state reached the 1.5-million EV milestone during the first quarter of this year, according to data released Thursday by the California Energy Commission. And 21% of new cars sold in California in the first quarter were electric. The EV data include battery electric vehicles, plug-in hybrids and hydrogen fuel cell EVs.
In March 2012, Gov. Jerry Brown issued executive order B-16-2012, calling for 1.5 million zero-emission vehicles on California roads by 2025.
At the time, many viewed the target as a “moonshot,” or aspirational goal, state officials said during a media briefing on Thursday. At the end of 2011, only 6,743 EVs had been sold in the state.
“When Gov. Brown set this goal, people across the state and around the nation said it couldn’t be done,” said Lauren Sanchez, senior climate adviser to Gov. Gavin Newsom. “But here in California, we make the future happen. We don’t just set goals, we achieve them.”
California Air Resources Board Chair Liane Randolph credited the state’s zero-emission vehicle (ZEV) regulations for spurring ZEV technology and manufacturing.
“The industry has responded incredibly rapidly to the confluence of market pressures, consumer demands and regulatory requirements,” Randolph said during the briefing.
In 2012, CARB adopted its initial Advanced Clean Cars regulation, which requires an increasing percentage of zero-emission cars to be sold each year. In August, the agency adopted Advanced Clean Cars II, which requires all new cars sold in the state to be zero-emission or plug-in hybrid by 2035. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)
ZEV adoption in California also has been boosted by nearly $2 billion in purchase incentives, officials said.
“California is setting the bar for climate action,” Newsom said in a statement. “And we’re achieving our goals years ahead of schedule thanks to unprecedented investments secured in partnership with the Legislature.”
The 1.52 million light-duty EVs sold in California through the end of the first quarter of 2023 represent 42% of the 3.61 million EVs sold in the U.S.
“The transition to ZEVs is here, and it’s happening quickly,” California Energy Commission member Patty Monahan said during Thursday’s media briefing.
The CEC is playing a lead role in ensuring enough charging infrastructure and hydrogen-fueling stations are built to support the growing number of EVs. A 2021 analysis found that the state will need 1.2 million public and shared private charging ports to support 8 million plug-in electric passenger vehicles in 2030, Monahan said. The CEC expects to release this year an updated analysis of EV charger demand.
According to figures released Thursday, California had 87,707 EV chargers and 63 hydrogen-fueling stations at the end of the first quarter.
Monahan said efforts are also underway to improve the reliability of public chargers. Drivers often find that chargers don’t work at the public stations, or there’s a glitch in using their credit cards, she said. CEC is developing reporting requirements for the reliability of publicly funded chargers and will publish a report on the reliability of the state’s EV charging network.
In addition, Monahan said, EVs must be “good citizens of the grid.” An analysis found that EVs will account for less than 5% of peak load in 2030. But that demand must be managed wisely, she added.
“With the right incentives, vehicles could shift charging from peak times to the middle of the day,” Monahan said. “You could literally run your vehicle on sunshine, and we wouldn’t have to curtail renewable energy.”
NYISO on Tuesday announced that veteran energy regulator Sally Talberg had joined its Board of Directors as its ninth member.
Talberg has 25 years of experience in energy and environmental regulation and has served in multiple top-level capacities.
She was appointed by Michigan Gov. Rick Snyder (R) to the Public Service Commission in 2013, serving as its chair from 2016 to 2020. During that time, she was a member of both the National Association of Regulatory Utility Commissioners and the U.S. Department of Energy’s State Energy Advisory Board. In 2016, Talberg served as president of the Organization of MISO States.
Sally Talberg | Michigan Public Service Commission
Talberg left the Michigan PSC near the end of 2020 to join ERCOT’s Board of Directors, first as an independent director for the first month of 2021 and then as its chair beginning in February — just before Winter Storm Uri hit and nearly caused the collapse of the Texas Interconnection. She, along with three other independent directors of the board, resigned later that month after fierce criticism from state residents about ERCOT’s out-of-state leadership in the aftermath of the storm. (See ERCOT Chair, 4 Directors to Resign.)
Talberg did, however, begin her career in Texas, after graduating from Michigan State University. She worked at the Lower Colorado River Authority while pursuing her master’s in public affairs from the Lyndon B. Johnson School of Public Affairs at the University of Texas at Austin. She went on to work at the Texas Public Utility Commission as an electric policy analyst.
“As a former state commissioner and former adviser to commissioners at the Texas and Michigan commissions, she has a unique appreciation for the importance of market design, infrastructure planning, pragmatic regulation and stakeholder engagement,” NYISO said.
Currently, she runs her own consultancy, Talberg Policy Solutions, and serves as a senior policy fellow at Public Sector Consultants.
The NYISO board consists of 10 members; Talberg’s appointment leaves just one vacancy.
“It is a privilege to welcome Sally to the NYISO’s Board of Directors. Her extensive experience will be invaluable as the board guides the NYISO during this historic period of industry change,” Chair Daniel Hill said in a statement. “We look forward to Sally’s contributions as we work to meet the state’s climate mandates, ensure grid reliability and competitive wholesale markets during the grid in transition.”
AES (NYSE:AES) and FirstEnergy (NYSE:FE) announced an agreement Tuesday to terminate their power purchase agreement for the 205-MW Warrior Run coal-fired power plant almost six years early, with plans to shutter the western Maryland plant by 2025.
FirstEnergy subsidiary Potomac Edison has been buying the output of the plant for decades under the Public Utility Regulatory Policies Act (PURPA) and bidding its output into PJM. The utility’s ratepayers will be on the hook for another $357 million if the deal is approved by the Public Service Commission, but that would save them $80 million over the next seven years while helping Maryland reach its decarbonization goals.
The PPA, which obligated Potomac Edison to purchase up to 180 MW/hour through Feb. 10, 2030, would terminate at the end of May 2024 under the utility’s petition (ML# 302441).
“This agreement is another milestone in our journey toward decarbonization,” AES CEO Andrés Gluski said in a statement. “Following the contract termination, we see interesting opportunities to repurpose the Warrior Run site for low carbon solutions that continue to serve local communities.” No details were provided on those plans.
The plant would keep operating through at least May 2024 — the end of PJM delivery year 2023/24 — which is in line with AES’ corporate goal of exiting the coal generation business by 2025, FirstEnergy told the PSC.
Potomac Edison has been buying the plant’s output under PURPA since the state restructured in 1999 and has been selling its output into PJM’s market since 2008, which is the most cost-effective way of generating income for the plant. Through 2022, the utility has paid AES $1.3 billion in excess of its wholesale power revenues, FirstEnergy told the PSC.
That money has been recovered from customers under a surcharge that varies significantly depending on wholesale prices, but has made up as much as 15% of the average customer’s bill when wholesale prices are low, the utility told the PSC.
Even with recent wholesale market volatility, the two firms expect the early termination fees to be cheaper than what Potomac Edison would have to pay under the remainder of the contract.
The wholesale volatility has not all been to the benefit of the plant. During the winter storm in December 2022, it underperformed on one day and owes $2 million in capacity performance payments to PJM.
“While the events of December 23 and 24, 2022, are uncommon and excessive compared to normal conditions, removing these operational risks along with the market volatility risk can provide significant benefit and protection to PE’s customers,” the PSC filing said.
The firms asked the PSC to decide on their request to retire the plant early by June 30. If it is approved later, the consumer benefits will be lower as they will have to renegotiate, the companies said.
AES said it would work with the plant’s employees to manage a responsible transition and will maintain full operational control over the site after it is decommissioned.
LANSING, Mich. — Democrats introduced a package of seven energy and climate bills Wednesday that would end coal-fired electric generation in the state by 2030 and mandate 100% renewable electric production by 2035.
SB 276, introduced by Sen. Rosemary Bayer (D), calls for the state’s coal-fired power plants to be phased out by 2030, putting it at odds with DTE Energy (NYSE:DTE), which operates a 3,280-MW coal plant near Monroe.
According to the Sierra Club’s Beyond Coal campaign, the only other plant that might be affected by the bill is the 70-MW TES Filer City Station, which is owned in part by CMS Energy (NYSE:CMS).
Michigan greenhouse gas emissions by source | MI Healthy Climate Plan
“TES has a planned retirement date of 2025, according to [the Energy Information Administration], but Sierra Club has not counted it because their contract with Consumers Energy ends in 2025, and they haven’t made any solid plans for the future, which means theoretically they could sign an agreement with another power purchaser, retire or convert to gas,” the Sierra Club said.
CMS has announced it would close all three units at the J.H. Campbell coal plant in West Olive in 2025 in addition to two units at the D.E. Karn coal plant in 2023. (See Mich. PSC OKs CMS Plan to End Coal Use by 2025.)
Senate Democrats announced their legislative plans last week as some 600 people met in Detroit at the state’s first Healthy Climate Conference.
The other bills are:
SB 271, introduced by Sen. Erika Geiss, would mandate 100% renewable electric production by 2035.
SB 272, introduced by Sen. Sue Shink, would give the Public Service Commission authority to consider climate, public health, social equity and price affordability issues in integrated resource plans by regulated utilities.
SB 273, introduced by Sen. Sam Singh, would require municipally owned and cooperative utilities to continue participating in energy-efficiency programs (eliminating a 2021 sunset provision).
SB 274, introduced by Shink, would require the development of a plan to reduce greenhouse gas emissions from buildings, including a zero-emission standard for new construction after 2026.
SB 275, introduced by Singh, is intended to reduce the carbon intensity of transportation fuels to 25% below a 2019 baseline by the end of 2035. The bill, which would also establish a market for trading carbon intensity credits, would exempt aviation fuels from the clean fuels standard, although sustainable aviation fuel would be eligible to generate credits.
SB 277, introduced by Sen. Kristin McDonald Rivet, would allow farms enrolled in Michigan’s farmland preservation program to lease out land for solar energy projects.
None of the bills in the package are tie-barred, meaning if some bills are blocked from passage, the others could still take effect.
Lisa Wozniak, executive director of the Michigan League of Conservation Voters, praised the proposals, saying recent polling showed most Michigan residents want the state to take greater action to fight climate warming. “This legislation will set Michigan on a path toward cleaner air, good-paying jobs, lower costs and a healthy, livable future,” she said.
Singh said the bills will help the state meet the goals of the MI Healthy Climate Plan. Adopted by the administration of Gov. Gretchen Whitmer (D) in 2022, the plan calls for the state to build the infrastructure for 2 million electric vehicles by 2030 and achieve carbon-neutral status by 2050.
If approved, the bill package would be the most significant action Michigan’s legislature has taken on climate issues since 2016, when the Republican-controlled state government enacted a bill requiring utilities to produce at least 15% of electricity by renewables by the end of 2021.
Now, following the 2022 election, the governor’s office and the legislature is under Democratic control, albeit with Democrats holding narrow majorities in both the House of Representatives and Senate. Under Michigan’s constitution, bills passed this year with less than two-thirds approval would not take effect until March 31, 2024.
While Democrats’ legislative package matches proposals urged by environmental groups at the start of the climate change conference, Whitmer did not call for any specific plan of action in her keynote address to the conference. Instead she praised the progress the state has made thus far, noting it has increased its renewable capacity from 17 MW in 2009, to 3,554 MW in 2022.
Whitmer last week also promoted a plan in her proposed 2023/24 budget to exempt EVs from Michigan’s 6% sales tax for two years. That proposal could save motorists up to $2,400 on a $40,000 EV, while costing state coffers some $48 million.
DTE Opens 225-MW Wind Farm
Adding to the state’s renewable fleet, DTE on Tuesday announced that it has officially opened the state’s largest wind farm, a 225-MW project spanning sections of Saginaw and Midland counties. (There is actually one larger wind project in the state, also owned by DTE in Isabelle County, generating 383 MW, but it is split into two separate farms.)
Avangrid (NYSE:AGR) won another round Thursday in the long-running court battle over the $1 billion, 1,200-MW transmission line it is attempting to build in Maine.
A jury in Portland decided the developer had a right to resume construction of the New England Clean Energy Connect, which would bring hydropower from Quebec to Massachusetts.
Maine residents rejected NECEC in a November 2021 referendum, and groups such as the Natural Resources Council of Maine have mounted one legal challenge after another, stalling a project first floated in 2017.
The trial ending Thursday was held to resolve a question unanswered in the November ruling: Whether the developer had vested rights to complete construction of the line.
The jury unanimously decided that it does.
But that is not necessarily the final chapter in the saga, as NECEC opponents could appeal Thursday’s verdict to the state Supreme Judicial Court. The Portland Press Herald noted that NECEC still faces appeals in state and federal court of permits issued by the state Department of Environmental Protection and U.S. Army Corps of Engineers.
Nonetheless, Avangrid welcomed the verdict as a victory.
“The jury’s unanimous verdict affirms the prior rulings of the Maine Supreme Judicial Court that the New England Clean Energy Connect project may lawfully proceed,” Senior Vice President Scott Mahoney said in a news release. “Even after repeated delays and the costs caused by the change in law, the NECEC project remains the best way to bring low-cost renewable energy to Maine and New England while removing millions of metric tons of carbon from our atmosphere each year.”
“We are pleased that this project can continue to move forward,” Vice President Anne George said in a news release. “The New England states’ ambitious climate goals will require building significant amounts of new infrastructure in a region where building infrastructure has been difficult. ISO New England looks forward to continuing our work with the New England states and other stakeholders, to making a clean and reliable future grid a reality.”
NECEC would be part of the system operated by Central Maine Power, an Avangrid subsidiary. The roughly 145-mile line is expected to import approximately 9.5 TWh/year of electricity generated by Hydro-Quebec. Avangrid said it would save Massachusetts ratepayers $190 million a year while reducing emissions by the equivalent of 600,000 cars. Completion was initially projected in 2023 when work began in early 2021.
Fierce opposition erupted on multiple fronts in Maine, where some residents were concerned about the environmental impact of a project that would not directly benefit their state.
Other opposition was more subtle.
NextEra Energy (NYSE:NEE), whose 1.24-GW nuclear power station in Seabrook, New Hampshire, might suffer in competition with an influx of low-cost electricity, supported efforts to block the line.
NextEra and Avangrid also squabbled over a circuit breaker at Seabrook that would be necessary once NECEC came online. The matter went to FERC — which ruled that NextEra could not refuse to install it — but the two had worked out an agreement by that point. (See FERC Resolves NextEra-Avangrid Dispute over Seabrook Circuit Breaker.)
WASHINGTON — Democrats in Congress want legislation to streamline and speed up permitting for clean energy projects and transmission, while Republicans want it for mining and drilling on federal lands, and for pipelines for hydrogen and carbon capture projects as well as for oil and natural gas, according to Sen. Shelley Moore Capito (R-W.Va.), ranking member of the Senate Environment and Public Works (EPW) Committee.
And both sides know new laws will be vital for developing domestic supply chains for critical minerals, such as lithium, cobalt and nickel.
Somewhere between these “essential views,” Capito said Tuesday at a breakfast meeting at the U.S. Chamber of Commerce, is the possibility to “forge a compromise … to say to the Democrats on our committee and Republicans on our committee, we may be approaching this from a different angle on where our real needs are.
“Successful legislation is about not just getting but giving up the things that you really don’t want, and so to get there we’re going to have to have that mindset across the committee,” she said.
“Permitting reform,” as it is commonly referred to, has become a high priority for both parties in the 118th Congress and for the Chamber, which has launched its own lobbying campaign called “Permit America to Build.” Tuesday’s event was a kick-off for the campaign, timed to coincide with a fly-in lobbying effort by members of the American Clean Power Association.
The goal for a range of stakeholders is bipartisan legislation that will provide “meaningful” change and break through the congressional inertia that has long surrounded the issue, said Neil Bradley, chief policy officer at the Chamber.
“Unfortunately, this is one of those issues where failure doesn’t immediately lead to catastrophic consequences,” Bradley said. “When we push permitting reform, it’s easy to keep talking about it; it’s easy to keep insisting on one position — your side’s position — while the other side insists on theirs. … Maybe we’ll find a solution later; maybe we’ll get a better outcome after the next election.”
Leonardo Moreno, president of AES Clean Energy, said the lack of consistency in permitting processes is a key challenge for his company’s efforts to build new solar, wind and storage projects. “If you go to agencies in each of our regions in the U.S., the main agencies are the [Bureau of Land Management], the Army Corps of Engineers and Fish and Wildlife,” Moreno said. “They don’t apply [the National Environmental Protection Act] in the same way; each of them has their own way of applying the process.”
Staff turnover can also mean further delays, leading to requests for new studies on different issues, he said.
But if the passage of the Infrastructure Investment and Jobs Act and the Inflation Reduction Act has not exactly created a sense of urgency, they have at least prompted some serious momentum around the long-dormant issue. The two laws are pouring billions of federal funds into a range of clean energy and other infrastructure projects, and the byzantine federal permitting process is now seen not only as a roadblock for clean energy and other infrastructure but as a national security issue that is integral to building out domestic supply chains.
Exhibit A is the 732-mile TransWest Express transmission line, which filed its first application for a right-of-way on federal land back in 2007 and only recently received final approval from the Bureau of Land Management to start construction. Completion is targeted for 2027, when the high-voltage line will send power from Wyoming wind farms to Southern California. (See TransWest Express to Break Ground After BLM Approval.)
Both EPW and the Senate Natural Resources (ENR) Committee have scheduled hearings on permitting reform, with Sen. Joe Manchin (D-W. Va.) announcing that a Thursday hearing on the Department of Energy’s 2024 budget will take up the issue. Energy Secretary Jennifer Granholm is scheduled to appear.
EPW will hold a hearing specifically on permitting on April 26, as will ENR on May 11.
“These upcoming hearings are vital to understanding how we can achieve bipartisan consensus that makes it possible for America to build again and maintain our status as a global energy leader,” Manchin said in an email statement. “Americans cannot wait any longer, and neither can I.”
NEPA Not Sacrosanct
The question remains: Can a divided Congress pass substantive legislation on permitting, especially when the ruling parties in both houses have narrow majorities?
While Senate Majority Leader Chuck Schumer (D-N.Y.) pronounced the House Republicans’ energy bill H.R. 1 “dead on arrival,” both Capito and Manchin said its permitting provisions, which are almost exclusively focused on fossil fuels, could provide a starting point.
“Nothing should be dead on arrival,” Manchin said at the Chamber event, arguing that looking at the opposition’s proposed legislation allows for a process of improvement. “We’re not going to have a perfect piece of legislation, [but] we can have a piece of much better legislation,” he said.
Both Manchin and Capito introduced permitting bills after passage of the IRA. Capito’s Simplify Timelines and Assure Regulatory Transparency (START) Act (S. 4815), stalled out in the EPW Committee, while Manchin made repeated efforts to get his Building American Security Act into other must-pass legislation, such as the National Defense Authorization Act. (See Manchin Permitting Bill Falls Short in Senate.)
Capito laid out what she sees as the core components of any compromise legislation.
First, she said, the bill should be “technology- and fuel-neutral to benefit energy projects of all kinds,” as well as other infrastructure projects, including roads, water and broadband. Another key component would be “enforceable deadlines.” When federal agencies don’t meet deadlines, “what happens?” Capito said. “Basically nothing. … All it does is push more and more of the burden onto whoever the developer is, the builder is, the community is.”
A 60-day deadline for filing judicial challenges to an approved project is another must-have, Capito said. “We’re going to first ask for some substantive changes to the NEPA review, also to the Clean Water Act. … That may be too far of a stretch, but we’re going to try.”
But Rep. Scott Peters (D-Calif.), a former environmental lawyer, says NEPA is not sacrosanct. “That approach simply is not compatible with science [and] the time we have left to maintain a stable climate,” he said.
Peters has made permitting legislation his personal mission and is working across the aisle with Rep. Bruce Westerman (R-Ark.) to find bipartisan solutions. For example, Peters said, “we can reduce the level of review for climate projects on nonsensitive land. … There’s no reason a solar project on degraded land, miles away from people, should go through the same process as a community [solar] project in a local community.”
Judicial review processes should be tweaked “to protect vulnerable communities while preventing wealthy NIMBYs and bad actors from blocking central clean energy projects … and ensure the federal government has the authority to build a reliable, environmental grid,” Peters said.
“If 52 years after NEPA, we’re still complaining about the effect of pollution on underserved communities … it’s time to expand our conversation,” he said. “When there’s so much money out there to do clean energy, and whether you’re a climate activist or just a taxpayer, you don’t want to see that money wasted on process.”
Good Things Fast
The Chamber’s goal is to get a “durable, meaningful” permitting bill passed by the end of the summer, and it aims to keep up the pressure with its lobbying campaign, according to an organization spokesperson.
“In the coming weeks and months, we will hold additional events activating our vast state and local Chamber network,” the spokesperson said. “There will be many conversations both inside and outside the Beltway, and … we will work closely with members of the House and Senate on legislative language consistent with our principles.”
Similar to Capito’s core components, the Chamber is calling for permitting that provides predictability and transparency for businesses, better coordination between federal agencies and broad stakeholder input.
But Jason Grumet, CEO of the American Clean Power Association, believes a more basic shift in mindset is going to be needed. Focusing on national security, economic development and government efficiency have, to date, not gotten the job done on permitting because “there was a perception that this was trying to advance an energy system that was not consistent with environmental imperatives,” he said.
The inefficiency of permitting has been “weaponized” and used to slow down or prevent “high-target infrastructure,” Grumet said.
“There is absolutely no political coalition that can move forward legislation that is simply focused on fossil [fuels],” he said. “There is equally absolutely no possibility of moving legislation through a closely divided Congress that is only focused on clean energy. …
“There’s not a single piece of legislation that can pass this Congress that will be the end of the discussion,” Grumet said. “But it is the beginning of shifting our national consciousness to recognize that making good things happen fast is the future of the country.”
Capito would also like to see a bipartisan permitting bill passed before Congress adjourns for its August recess. While some House Republicans have suggested attaching H.R. 1 to any deal on raising the national debt limit, Capito said the priority should be getting the bill right.
“Get the policy right,” she said. “And then we’ll find the vehicle.”
FERC last week rejected SPP tariff revisions that would help transmission owners continue to self-fund network upgrades to interconnect generators (ER22-2968).
The commission found in a 3-1 decision on April 14 that SPP had not demonstrated that its proposed pro forma facilities service agreement and associated tariff revisions were just and reasonable and not unduly discriminatory or preferential (ER22-2968).
The grid operator sought approval of a proposal to allow TOs to self-fund the upgrades and recover their costs and a return on investment from an interconnection customer.
American Clean Power Association, Advanced Power Alliance, the Solar Energy Industries Association, the Natural Resources Defense Council and the Sustainable FERC Project all intervened against the revisions. They said the self-funding would heap costs on generation developers if they didn’t pay for the upgrades themselves.
FERC said SPP’s proposal ran counter to Order 2003, which established standard interconnection procedures to limit opportunities for transmission providers to favor their own generation and facilitate market entry for generation competitors by reducing interconnection costs and time.
The commission said the revisions could lead to “greater uncertainty” for interconnection customers that might not elect to a TO’s initial funding for upgrades, but then reverse course near the study process completion. It agreed with the clean energy advocates’ argument that such circumstances could lead to late-stage withdrawals and delays in administering the generator interconnection queue, further undermining Order 2003’s goals.
SPP and Xcel Energy subsidiary Southwestern Public Service contended that a non-binding indication provides an interconnection customer advance notice that a TO intends to self-fund prior to negotiation of generator interconnection. They also noted that FERC approved MISO’s request to require TOs to make binding self-funding decisions before GIA negotiations begin.
FERC disagreed, saying the non-binding self-funding election means a TO can make a choice when the study process begins and then do the opposite. The commissioners said they accepted MISO’s revisions to add deadlines by which TOs must make both non-binding and binding elections before the GIA negotiations. They said SPP’s proposal includes only the non-binding indication provision.
“Having more information earlier is beneficial not harmful,” the commission wrote. “By denying an earlier indication of the transmission owner’s potential election, interconnection customers will be denied access to information at an earlier stage under the tariff. That denial of information actually creates uncertainty; it does not protect against it.”
Commission Nixes PRM Waivers
The commission on Monday also rejected SPP tariff revisions that would allow load-responsible entities (LREs) to obtain two-year exemptions from deficiency payments assessed for not meeting the grid operator’s new resource adequacy requirement, finding the grid operator had not demonstrated the proposal was just and reasonable (ER23-636).
The commission found the RTO’s proposal would undermine the structure of deficiency payments, set out in a 2018 filing to establish the resource adequacy requirement. LREs unable to meet the requirement are subject to a deficiency payment equal to the payment amount multiplied by the cost of new entry and a multiplication factor of the footprint’s excess capacity relative to the planning reserve margin (PRM).
“The complete elimination of the deficiency payment, even under the criteria of the proposed exemption process, removes the incentive for LREs to procure the capacity needed to collectively ensure that the SPP footprint maintains resource adequacy,” the commission wrote.
FERC has said SPP’s proposed deficiency payment “provides a signal to LREs to plan ahead to satisfy the [resource adequacy requirement].”
The commission found that while the proposed exemption is limited to two hours each time the grid operator increases the PRM, LREs would be able to seek the exemption each time there is an increase. It said that, were SPP to make consecutive increases, deficient LREs with exemptions wouldn’t be required to meet their resource adequacy obligations for an extended time.
FERC also said the proposed tariff language is not clear as to how the proposed exemption process would work.
Evergy’s Denise Buffington, who warned last October that the proposal would fail at FERC, suggested SPP’s future tariff revisions should allow more time for compliance.
“It takes time to get steel in the ground, and if SPP continues to increase the performance or planning reserve margin on an annual basis, we’re never going to be able to meet it,” she said during a Resource and Energy Adequacy Leadership Team meeting Thursday. “When we think about setting out new requirements, we have to do them far enough in the future so that load-responsible entities can actually comply.”
Electrify Now, an organization trying to speed the electrification of the U.S., took the counterintuitive step of inviting a natural gas utility to one of its monthly webinars this week, giving it a warm welcome.
Vermont Gas Systems (VGS) serves about 55,000 customers in and near Burlington, the largest city in the state and its only large region with a concentrated population. VGS is the state’s only gas utility but is attempting to reposition itself as a thermal solutions utility offering customers multiple strategies for heating their structures.
VGS is actively marketing electric heat pump water heaters to its customers and planning to offer centrally ducted heat pumps as well. The strategy is to profit from the sale, lease and service of that equipment, even as the revenue from powering them goes instead to the local electric utility.
Eventually, VGS plans to move into ductless heat-pump systems because many of the houses in Vermont currently use hydronic systems, and retrofitting them with ductwork would be a major undertaking.
VGS also is pursuing a renewable natural gas (RNG) strategy that will keep it in the gas-delivery business for some time to come, even if it is not selling as much gas to as many people. Its proposed RNG import contract drew extensive negative public comments to the state Public Utility Commission and led to charges that VGS is attempting to greenwash its image with the electrification effort.
As he opened the online session Wednesday, Brian Stewart of Electrify Now took a swipe at RNG, framing it as expensive non-solution to the imperative for gas utilities to “decarbonize their business without going out of business.”
“So imagine our surprise and delight when we came across this,” he continued. “Could it be that a gas utility is promoting electric heat pump water heaters? What’s going on here? Are they embracing electrification as a way to decarbonize their business, rather than actively resisting it?”
VGS New Product Development Manager Morgan Hood explained that decarbonization is part of the goal, along with maintaining a revenue stream and relevance in a changing marketplace. For multiple reasons, VGS is likely to see its gas customer base shrink rather than grow.
Though its governor is Republican, the Green Mountain State is firmly Democratic in its politics and consistently ranks among the most environmentally conscious states. Gov. Phil Scott vetoed a clean-heat bill last year and has said the version working through the legislature this year looks too similar and too expensive. But there is popular momentum behind it and smaller steps toward the same goal.
There are no bans now on new gas connections or gas-burning equipment in the VGS service area, but the utility views bans as inevitable, Hood said. VGS abandoned a previous attempt to expand geographically amid controversy and has no expansion plans now, she said.
And while natural gas has historically been pitched as cheaper and cleaner than the heating oil that many Vermonters use during their long, cold winters, new heat pump technology can be less expensive to operate than either.
Then there is the climate crisis, which Hood said VGS, and many of its customers, believe is real. Heat pumps generate no emissions of their own, and if the electricity powering them comes from clean sources, the carbon footprint is radically smaller than gas-burning equipment.
“More and more of our customers are looking to decarbonize,” she said. “If we want to continue to serve our customers, if we want to continue to be a thermal solution provider — which we do — significant changes are necessary.”
VGS is one of the few utilities that still installs and services gas-burning equipment in customers’ buildings with its own personnel, Hood said, so adding the new electric equipment to its offerings is not a major stretch.
But swapping out furnaces and water heaters is only part of the solution. VGS began its energy-efficiency program in the 1990s and has in-house engineers and energy auditors to help customers improve their homes.
“Houses in Vermont tend to be older, and many are in desperate need of weatherization,” Hood said. “If we intend for heat pumps to carry the full heating load in this very cold state and displace fossil fuels effectively, affordably and efficiently, we need to set these homes up for success with air sealing and insulation.”
VGS is offering its services to non-customers as well. Hood said the PUC is amenable to this because of the scarcity of private contractors to do the work. But VGS has limited itself geographically to within 5 miles of its gas lines to control transportation costs.
Shortage of skilled labor and supply chain constraints are two potential obstacles to VGS expanding this initiative, Hood said, and both have already cropped up.
Ultimately, Hood said, the possibilities move beyond single-building heat pumps to local ecosystems of shared geothermal energy and recycled waste heat from commercial users.
Stewart asked: “Does VGS imagine a future where they’re a heat provider and not a fossil gas provider?”
“Yes, and it’s daunting,” Hood replied.
It is also early in the process. VGS does not know how it will accomplish its goal of achieving net zero by 2050, Hood said, adding that probably no single strategy — RNG, hydrogen or electrification — will carry it there.
Joe Wachunas of Electrify Now asked if VGS is expecting its income to decrease as it converts customers to electric heating solutions.
“These solutions we’re proposing, although profitable, aren’t profitable in the same way delivering natural gas is profitable,” Hood said. “We are learning to look at that.”
There likely will be a gradual rollout and a bit of a balancing act, as VGS works to reach its goals while keeping investors happy, she added.
Wachunas asked whether other gas utilities perceive VGS as a trailblazer or a turncoat.
“I think the industry in general still regards us as quirky,” Hood replied. “If we can model the business case, the financial case for evolving a gas utility in this way, then I think people’s ears will perk up; maybe we’ll be leaders.”
Stewart and Wachunas raised what may be one of the hardest aspects of electrification: how to engineer a smooth transition at an acceptable cost.
Hood listed several factors at play. One priority is not sticking lower-income customers who cannot electrify with a rapidly increasing share of the gas system’s costs as wealthier customers electrify. Another is not harming large commercial customers.
There may be future efforts to press for electrification of areas where gas service becomes uneconomical because expensive work is needed, or because there are too few ratepayers left. There currently are not any plans for such a shrinkage of the distribution network, but that does not mean there never will be.
On the positive side, VGS was only founded in 1965. Its infrastructure is much younger than many other gas utilities’ and unlikely to need a lot of expensive work any time soon.
“I don’t have any easy answers,” Hood said. “It’s really, really nuanced.”
New Jersey’s Board of Public Utilities and Department of Environmental Protection on Wednesday approved $2 million in funding to study the impact of offshore wind development on marine life.
The funds, part of the $26 million Offshore Wind Research and Monitoring Initiative (RMI), will pay for projects that include deployment of a whale detection buoy, as well as studies to evaluate general species diversity in offshore wind development areas and better understand offshore movement of harbor seals, the agencies said in a release.
The funds will additionally pay for the state to join the Responsible Offshore Science Alliance, a nonprofit organization leading a collaborative effort to advance fish and fisheries research related to offshore wind.
The RMI program is jointly administered by the two agencies and is funded with contributions of $10,000 for each megawatt of capacity from the two projects approved by the BPU in the state’s second OSW solicitation. The $2 million in additional expenditures take the total spent from the fund to $8.5 million.
The addition of the new projects comes as the state undertakes a third solicitation for offshore wind projects, with the potential to increase OSW project approvals to substantially above the 3.758-GW capacity already approved. The latest solicitation, opened on March 6, could award between 1.2 and 4 GW, and perhaps more, according to the BPU’s solicitation guidance document. (See NJ Opens Third OSW Solicitation Seeking 4 GW+.)
The advance of the projects has stoked opposition from commercial fishers, coastal residents and the tourist and other industries, with opponents seizing on a series of whale deaths along the New Jersey shore to raise concerns about the impact of the growing wind sector on marine life. Opponents have held several protests, and two of the state’s Republican congressmen, Reps. Jeff Van Drew and Chris Smith, held a hearing on the issue, calling for a halt to the offshore wind projects.
Although little work has started on the OSW projects, environmentalists concerned about marine life say the studies and ocean floor analysis advance work could have impacted the whales by generating noise undersea.
Responsible Development
Federal marine authorities have said they see no connection between OSW developments and whale deaths, and state officials have shown no signs of slowing the projects’ development.
The state, however, has paid increasing attention to efforts to gauge the impact on marine life, approving more than $3.4 million in March for three initiatives to research the impact on wildlife and fisheries. (See NJ Awards $3.4M to Study the Marine Impact of Turbines.)
Shawn M. LaTourette, the state’s commissioner of environmental protection, said the OSW projects are key to mitigating the effects of climate change, and the newly announced marine studies will work to mitigate any impact on marine wildlife.
“These projects will continue to advance the collection of baseline scientific information that will help ensure the responsible development and operation of offshore wind facilities that protect our coastline and its natural resources,” he said.
The whale detection buoy funded in the newly announced expenditure of RMI funds will listen for whales, and detections will be reviewed and used to mitigate risks associated with vessel strikes and future construction noise, according to the BPU and DEP.
Another study will look at environmental DNA (eDNA) to monitor species that “are protected or otherwise important to maintaining the ecological integrity of coastal waters and are important to New Jersey’s recreational and commercial fisheries,” the two agencies said.
A third study will collect data on the movement patterns and health of seals that spend the winter in the Great Bay area north of Atlantic City. “This study will tag and collect baseline health data for harbor seals, such as stress hormones, that should help assess the impacts of future OSW-related activities, including construction and operation, on harbor seals,” the agencies said.
BPU President Joseph Fiordaliso said the projects would “assist us in protecting the environment as we move forward to reach Governor [Phil] Murphy’s goal of 11 GW of offshore wind capacity by 2040.”
NERC’s Standards Committee moved forward Wednesday with four standards development projects, including one that could lead to new rules for inverter-based resources (IBR).
Vice Chair Todd Bennett from Associated Electric Cooperative led the relatively brief meeting, filling in for chair Amy Casuscelli of Xcel Energy who was absent.
The new IBR standard arose from Project 2021-04 (Modifications to PRC-002 — Protection and Control), which was initiated to update PRC-002-3 to account for the expansion of IBRs such as solar and wind farms. NERC said the standard needed to be revised to ensure that system planners could access data on grid disturbances for post-mortem event analyses.
Phase 1 of the project was based on a standard authorization request (SAR) submitted by Glencoe Light and resulted in PRC-002-4 (Disturbance monitoring and reporting requirements), which was approved by FERC last week (RD23-4). The committee voted Wednesday to begin Phase II, inspired by a SAR from the Inverter-base Resources Performance Task Force (IRPTF).
Rather than further modify PRC-002, Phase II aims to create a new standard specifically designed around IBRs. Southwest Power Pool’s Charles Yeung, who is currently serving as the Project Management and Oversight Committee’s liaison to the standard drafting team (SDT), explained that the team felt that this approach was the best way to adapt NERC’s standards to the arrival of new technology.
“One of the charges to the team — that’s not in the SAR — was not to upset the current methodology [for determining the] location of DDR [dynamic disturbance recording] data. And of course, that methodology is based on a system with synchronous generation,” Yeung said. “The addition of IBRs is really … about the black box performance of IBRs. So even though it is about data location … it’s really a very separate purpose.”
Participants in the meeting were supportive of addressing IBRs in a new standard. Philip Winston, formerly of Southern Co., called the drafting team’s plan “a much better approach than trying to shoehorn new technology into old standards.” He added, “The times, they are a-changing.”
The SAR passed unanimously.
New Ride-through SAR Approved
Members also agreed April 19 to move forward development on Project 2020-02 (Modifications to PRC-024 —generator ride-through), accepting the SAR as revised by the project’s SAR drafting team and appointing the team as the SDT for the project.
Some members expressed confusion at the history of Project 2020-02, for which the committee approved a different SAR almost a year ago. (See NERC Standards Committee Moves Projects Forward.) This new SAR was submitted by NERC staff last May after an analysis of system disturbances found that PRC-024-3 (Frequency and voltage protection settings) did not account for many causes of tripping detected in the analysis. The Standards Committee assigned it to Project 2020-02 because of the similarity in subject matter.
Latrice Harkness, NERC’s manager of standards development, clarified that the previous SAR is not “being disposed of,” but that the SDT will need to examine both SARs to determine how it wants to incorporate them.
While the motion passed without objection, Marty Hostler of the Northern California Power Agency reminded members to be mindful of the burden that frequent changes to standards places on industry.
“I remember there being a big push for PRC-024. Everyone had to get all the studies done, and then it got changed, and then it got changed again. And now we’re saying it’s not suitable, or may not be suitable,” Hostler said. “Industry groups like us and our members devoted a lot of time to complying with the standards … and now we’re going to possibly have to do the work again. So, let’s just keep that in mind and not just push a project through just for the sake of getting it done in a certain time frame.”
IBR Event Reporting, PRC Successor
The committee turned to the SAR drafting team for Project 2023-01 (IBR event reporting), which is intended to revise the reporting thresholds for generation loss events to account for the performance of renewable resources. NERC’s Reliability and Security Technical Committee endorsed the SAR at its December meeting, and the Standards Committee authorized the solicitation of drafting team members in January. Twelve nominations were received, all of them recommended by NERC for appointment. The committee approved them all unanimously.
Finally, members voted to post the draft standard PRC-005-7 for a 45-day formal comment period, with an initial ballot to be conducted in the last 10 days of the comment period. The standard is intended as a successor to PRC-005-6 (Protection system, automatic reclosing, and sudden pressure relaying maintenance) to provide clarity on the grid elements to which its maintenance and testing requirements apply.
