That is enough to outpace the national goals of many countries but not quite enough to meet the target established at the COP28 climate summit: tripling the capacity by 2030. However, the IEA said, tripling still is possible with bold near-term action by governments.
In “Renewables 2024,” its flagship annual report released Oct. 9, IEA projects more than 5,500 GW of new capacity coming online by 2030.
Photovoltaic panels and wind turbines account for the vast majority: 80% and 15%, respectively.
Hydropower capacity growth is expected to remain stable while renewables such as bioenergy, geothermal, concentrated solar and ocean energy are expected to decline without greater policy support.
IEA attributes the growth to climate and energy security policies in nearly 140 countries that, combined with favorable economics, have made renewables cost-competitive with fossil-fired generation and fostered new demand from the private sector.
The report projects that nearly 70 countries accounting for 80% of global generation capacity are on track to reach or exceed their 2030 goals.
China is the standout among them, expected to account for 60% of the global expansion through 2030 thanks to its comprehensive support for utility-scale and distributed generation across all renewable technologies.
In all, renewables would account for nearly half of global electricity generation by 2030.
Potential stumbling blocks include high cost of capital in developing economies, weak grid infrastructure, inadequate auction visibility, unstable policy environments and curtailment of installed resources due to lagging grid investments and system integration.
Also, at least 1,650 GW of renewable capacity in advanced stages of development is waiting for grid connection worldwide; some early-stage projects are dropping out of the queue due to lack of progress.
And kinks remain in the supply chain: Record-low prices, a supply glut and manufacturing overcapacity exist for the solar industry, while the wind turbine sector is crimped by limited investment in new capacity.
Finally, beyond power generation, fossil fuel demand continues to grow in the transport, industry and buildings sectors, the report states; almost 80% of total energy demand worldwide still will be met by fossil fuels in 2030, down from 87% in 2023.
In the news release, IEA Executive Director Fatih Birol said:
“Renewables are moving faster than national governments can set targets for. This is mainly driven not just by efforts to lower emissions or boost energy security — it’s increasingly because renewables today offer the cheapest option to add new power plants in almost all countries around the world.
“This report shows that the growth of renewables, especially solar, will transform electricity systems across the globe this decade. Between now and 2030, the world is on course to add more than 5,500 gigawatts of renewable power capacity — roughly equal [to] the current power capacity of China, the [EU], India and the United States combined. By 2030, we expect renewables to be meeting half of global electricity demand.”
A new report argues that discussions about building electrification largely leave out one key issue: how to prepare the grid for the higher demand and new consumption patterns associated with the shift.
The Energy Systems Integration Group’s (ESIG) “Grid Planning for Building Electrification” report seeks to start that conversation, with a focus on the increasing share of home heating being served by the grid, which has the biggest impact on overall demand patterns.
“Building electrification gets a lot of attention in the industry, but little information is available about what grid planners should do about it today,” said Sean Morash, chair of ESIG’s Grid Planning for Building Electrification Task Force. “This report bridges the gap between building energy modelers and grid planners, providing insights that will shape the distribution and bulk power systems that support our energy transition.”
The effects of load growth on the distribution system are often only a minor consideration, but the long lead time and extended life of power infrastructure means that decisions today will support society into the 2060s, the report said.
“Load impacts from building electrification will increase the seasonality and weather dependence of loads, as well as increase the vulnerability of the power system to extreme weather, largely due to heating demand,” the report said.
Building electrification promises one major shift for the grid: as electricity is increasingly used for heating, many regions will shift from summer to winter peaks. Increased adoption of heat pumps, which tend to be more efficient than air conditioners, mean that summer peaks could decline in some regions. And while solar output aligns with gross peaks in the summer, winter peaks happen just before the sun comes up.
The report cites priority areas to improve distribution system planning in the face of growing electrification.
The first is to improve forecasting because the load shape impacts of building electrification will vary by location.
Areas such as the Southeast and Texas, where a lot of heating is already electrified, could see overall use decline as more energy-efficient heat pumps replace less efficient older units, or resistance heaters. But when it comes to winter peak demands for those states, cold snaps plus even more electrified homes could cause them to be higher.
“On the other hand, the adoption of electric heating in areas predominantly served with fossil fuels could result in a doubling of electricity use, affecting both peak power and total electricity needs,” the report said.
Distribution system planners will need a more granular understanding of technology adoption, such as the rates of electrification, what kinds of heat pumps are being adopted, and what that means for the local climate zone. Planners should also develop a solid baseline of current building demand broken down by end use because electrification will impact some significantly and others not at all.
Increased Winter Risk
Because electrification will make the grid more vulnerable to extreme temperatures, planners must consider extreme events, which includes factoring how climate change can impact those events over time, according to the report.
Traditional planning has centered around one peak demand event, but severe weather — especially in winter — can cause longer-duration stress by increasing loads for prolonged periods. Electrification of heating will exacerbate that stress, but it can be planned for by switching to a “time-series analysis” that assesses risk across multiple hours of the year and the efficacy of solutions for those intervals.
Distribution system equipment has some universal engineering standards, but local utilities embed their own assumptions about system conditions, demand diversity and load growth.
“However, past practices may not be well suited for electrification-driven load growth, which may have different hourly load impacts,” the report said. “Distribution system planners will need to reevaluate the underlying assumptions that drive equipment standards.”
The shift to longer-duration winter peaks can impact grid-edge equipment, which is typically designed to serve peak demands for short durations and can lead to component failures.
“Overload failures can occur throughout the grid, including in distribution systems, where equipment is often unmonitored,” the report said. “Grid failures during extreme winter weather events pose much more risk to human health and wellbeing than do summer peaks.”
The industry could avoid the largest impacts from electrification by relying more heavily on energy efficiency and demand management practices, the report said.
“In the context of building electrification, the most important energy efficiency measures are those that maintain building temperature with minimal input from the grid, because of the long duration of winter reliability events,” the report said.
Thirty percent of thermostats are “smart,” and actively tapping those and other demand resources can greatly help in reliably electrifying buildings, the report said.
To some extent, utilities can predict when some areas in their service territories are going to electrify because some programs target specific neighborhoods or are focused on low-income customers. They should then plan ahead and upgrade infrastructure with an eye to growing future demand.
Washington’s Department of Ecology kicked off its first virtual electricity forum Oct. 3 to provide updates on recent electricity-related rulemaking efforts related to the state’s carbon market and to give stakeholders a chance to discuss those initiatives.
The state’s Cap-and-Invest Electricity Forum aims to allow parties to discuss policy issues related to Washington’s cap-and-invest program and greenhouse gas emissions reporting programs.
The Ecology Department has moved forward with amending several electricity provisions in its rules. The rulemaking closest to completion concerns centralized electricity markets, such as CAISO’s Western Energy Imbalance Market/Extended Day-Ahead Market and SPP’s Markets+.
The rule establishes a framework for accounting for “specified” electricity imported through centralized markets and defines the electricity importer for specified electricity imported through a centralized market. The update is anticipated to go into effect in January.
The agency is also working on “linkage” rulemaking to align cap-and-invest program regulations with California and Québec as Washington looks to join the larger shared carbon market. (See Calif., Quebec, Wash. to Explore Linking Carbon Markets.) The recently enacted Senate Bill 6058 allows Ecology to adjust the cap-and-invest program by, for example, aligning allowance purchase limits for auctions across jurisdictions and having the same compliance period dates.
“This rulemaking may also be used as an opportunity to address other electricity sector topics, including centralized electricity markets,” Camille Sultana, senior environmental planner at the Ecology Department, noted during the meeting.
Sultana added that Ecology will provide more information on the bill’s implementation later this fall. The goal is to publish a proposed linkage rule in spring 2025 and put it up for adoption later that year. However, the timeline is subject to change as the agency must consider anticipated updates to California and Québec’s respective cap-and-trade programs.
The department also opened the floor for participants to chime in on GHG issues related to centralized electricity markets, such as accounting for emissions from electricity from “unspecified” resources, emissions leakage and accounting for energy flowing from centralized markets with different operators.
Clare Breidenich, assistant executive director of the Western Power Trading Forum, said the agency should define surplus energy in the context of GHG accounting in centralized markets.
“I think by establishing clear requirements and conditions for what Ecology thinks is appropriate for those markets, that will give the guidance to the market operators and help them to align their approaches,” Breidenich said.
Participants also discussed emissions reporting requirements and the transition from netting to a wheel-through framework under SB 6058.
As defined in the bill, “‘electricity wheeled through the state’ means electricity that is generated outside the state of Washington and delivered into Washington with the final point of delivery outside Washington including, but not limited to, electricity wheeled through the state on a single NERC e-tag, or wheeled into and out of Washington at a common point or trading hub on the power system on separate e-tags within the same hour.”
Alisa Kaseweter, climate change strategist at Bonneville Power Administration, said the definition “seems to conflate what the industry would think of as a standard wheel-through which happens on a single e-tag with perhaps some netting.”
Sultana noted that SB 6058’s definition of a wheel-through “might not directly align with industry standard.” She added that Ecology’s “ability to modify this definition in ways that are not aligned with what’s already there in statute is beyond our authority.”
The Vermont Public Utility Commission has published a draft of the Clean Heat Standard mandated by a landmark decarbonization law but declined to include the specified credit-trading system.
In a report accompanying the draft, the PUC said it makes no sense for a single small state to create such a costly and complex system. It is looking instead at other options to reduce the greenhouse gas emissions produced by heating fuels and will propose an alternative mechanism before the January deadline set by the legislature.
Act 18’s full title — “An act relating to affordably meeting the mandated greenhouse gas reductions for the thermal sector through efficiency, weatherization measures, electrification and decarbonization” — summarizes the intent of the 41-page measure.
There is much to reduce. Like residents of the two other northern New England states, Vermonters rely heavily on delivered fossil fuel to heat their homes. The U.S. Energy Information Administration reports that 59% of housing units in Vermont were heated with kerosene, propane or fuel oil as of 2020, compared with 13% nationwide.
But many people still rely on fossil fuels to heat their homes through what historically have been long, cold winters. As elsewhere, there are concerns about equity: Those unable to afford electrification of their homes may be most vulnerable to the added costs resulting from policies that attempt to speed electrification.
The legislature sent the matter to the PUC to research (23-2221-INV) and codify (23-2220-RULE). The commission issued its draft CHS rule on Oct. 1 and set an Oct. 30 public hearing on the document. Also on Oct. 1, the PUC issued a companion report explaining the 16 months of work that produced the draft.
After the hearing, the PUC must, by Jan. 15, 2025, submit the draft rule to the legislature, which then will decide whether and how to implement the CHS.
Central to the CHS’ goal of reducing greenhouse gas emissions from heating fuel is a requirement that entities importing heating fuel into Vermont reduce their emissions by generating or purchasing clean heat credits earned from delivery of clean heat measures. These can include weatherization, heat pumps, advanced wood heat and biofuels. At least 32% of annual clean heat credits were mandated to come from customers with low or moderate income.
Given the substantial cost and complexity of developing a credit management platform, the PUC did not create or recommend such a mechanism until the legislature decided whether and how to continue develop a CHS.
But the PUC’s companion report cast doubt on the very idea of a Vermont-based credit-trading system. Among other things, it would involve participation and regulatory oversight of hundreds of fuel dealers and other entities not historically regulated by the PUC, and the potential would exist for market manipulation or outright fraud, the authors wrote.
“Our work over the past year and a half on the Clean Heat Standard demonstrates that it does not make sense for Vermont, as a lone small state, to develop a clean heat credit market and the associated clean heat credit trading system to register, sell, transfer and trade credits,” the report says. “Because the Clean Heat Standard introduces these additional regulatory hurdles and costs, the commission is considering other options to achieve Vermont’s greenhouse gas emission-reduction goals for the thermal sector.”
The PUC said one of those options is a new thermal energy benefit charge on sale of fuel oil, propane and kerosene, with proceeds going directly to fossil fuel-reduction efforts such as weatherization and electrification.
Jackie Roberts, federal policy adviser for the West Virginia Public Service Commission and a pillar of PJM’s relationship with state consumer advocates and regulators, announced her retirement Oct. 8, capping a 14-year career with the state.
Roberts has worked for the PSC since January 2021, when she joined after serving as the West Virginia consumer advocate for more than a decade. Her final day with the PSC is Nov. 12.
The hallmarks of her career, Roberts told RTO Insider, include her work establishing the Consumer Advocates of the PJM States (CAPS) and breaking PJM’s internal market monitoring unit off as an independent company, Monitoring Analytics.
The creation of CAPS, and the funding that came with it, has improved consumer advocates’ participation at PJM and allowed them to take a more proactive role in the stakeholder process, she said.
Greg Poulos, executive director of CAPS, said Roberts has a gift for bringing people together and has made a positive impact on consumers through her advocacy.
“Throughout the time I’ve known Jackie, she has been a strong advocate, with an incredible wealth of knowledge, passion and strong communication skills,” Poulos said. “For me, her efforts to connect and collaborate with all parties that are interested has helped create many successful outcomes. Her efforts to encourage collaboration have made her involvement in stakeholder processes at state, regional and federal levels incredibly valuable.”
The Independent Market Monitor has also been a success, Roberts said, preventing undue RTO influence on the monitoring role.
She expressed concern, however, that the Monitor’s work could be jeopardized by contract deliberations that have been ongoing for more than a year regarding the future of the position. “It causes disruption for the Market Monitor and his staff and considerable angst on behalf of the commission,” she said.
Surveying the challenges facing the PJM region, Roberts said resource adequacy is a growing concern, as well as the cost of electricity, noting a significant increase in Base Residual Auction prices with the potential for another fourfold increase in the auction scheduled for December. (See “Price Cap Increases in 2026/2027 BRA Planning Parameters,” PJM MIC Briefs: Sept. 11, 2024.)
“Many people will simply not be able to afford electricity. I know PJM will say, ‘That’s not what we do; that’s what the states do,’” she said. But she argued that PJM plays a role in the costs for retail ratepayers.
State utility commissions are on the front lines of managing rising rates, but PJM has not given their recommendations the proper weight when making decisions about capacity market design and the generation interconnection queue, Roberts argued. She pointed to a protest the PSC filed with FERC seeking participation in PJM’s Liaison Committee. (See FERC Rejects Complaints from IMM, W.Va. PSC Arguing for Access to PJM Liaison Committee.)
“I think it takes good leadership at PJM to balance and implement the appropriate stakeholder input,” she said. “I’m concerned that PJM is just managing those stakeholders and not taking leadership to incorporate really good suggestions into their operations.”
Roberts has held positions on the National Association of State Utility Consumer Advocates, NERC’s Member Representatives Committee, the Keystone Policy Center’s Energy Board and the executive committee of Edison Electric Institute’s Critical Consumer Issues Forum. She continues to serve on the U.S. Commodity Futures Trading Commission’s Energy and Environmental Markets Advisory Committee.
Prior to her time in West Virginia, Roberts worked as an attorney at the Ohio Consumers’ Counsel and as corporate counsel for electric and natural gas utilities in New England.
PJM Senior Vice President of Governmental and Member Services Asim Haque, also former chair of the Public Utilities Commission of Ohio, said Roberts will be missed.
“Jackie has been not only an important voice in this industry, but she’s also been a friend to me going back to my Ohio days,” he said. “She will definitely be missed professionally, and I’ll miss her personally.”
West Virginia PSC Chair Charlotte Lane said Roberts “brought a lot of knowledge and insight into her position as our federal liaison. She will be missed.”
Emile Thompson chair of the District of Columbia Public Service Commission and current OPSI president, said of Roberts’ retirement: “Jackie has been an amazing colleague to work with over the past few years. She has been a fierce advocate for the citizens of West Virginia, the W.V. PSC and OPSI. Whenever Jackie spoke, I was sure to listen, and her institutional knowledge will certainly be missed.”
“Jackie Roberts has been an important participant in the PJM stakeholder process in a range of capacities,” said Joe Bowring, independent market monitor. “Jackie has been a strong and effective advocate for customers, for the role of state public utility commissions, for rational PJM governance, for efficient and competitive markets, and for a truly independent market monitor.”
The complex, challenging work found in the electric sector, as well as the opportunity to work with a diverse range of stakeholders, has kept her interested for nearly 20 years. Roberts said she hasn’t decided what her future in the electric sector may look like, but she plans to spend much more time riding her horse.
“It has been a great privilege to work on PJM issues for the last almost 20 years. I’ve learned a lot. I appreciate the professional relationships I have developed through that process, and I appreciate what could be robust differences of opinion. What’s important is we move forward with what’s in the best interest of retail and wholesale customers.”
Xcel Energy has reached a settlement with clean energy nonprofits that further swings the utility’s integrated resource planning toward zero-carbon resources.
The utility and Clean Grid Alliance, Fresh Energy and Minnesota Center for Environmental Advocacy announced a settlement agreement in early October that will nudge Xcel Energy’s Upper Midwest Energy Plan to zero carbon emissions sooner. Other parties to the settlement include the Minnesota Department of Commerce, labor unions and generation developers.
The agreement affects both Xcel’s integrated resource plan (24-67) and its Firm Dispatchable Resource Acquisition (23-212) dockets before the Minnesota Public Utilities Commission. Now Xcel’s Firm Dispatchable Resource Acquisition is open not just to gas, but also to renewables and storage. Xcel also has pledged to better use existing gas plants to avoid the need for multiple gas peaking plants in its IRP.
In the firm dispatchable docket, Xcel has agreed to build more than 300 MW of new storage across two standalone projects, as well as an additional 230 MW in the form of a wind-and-storage hybrid project and a 170-MW solar-and-storage project. Xcel also will extend two power purchase agreements with existing gas plants and build just one 374-MW peaker gas plant in Lyon County that also will be hydrogen-capable. The settlement negates the need for a second natural gas plant Xcel had proposed for Fargo, N.D.
In addition to the resource acquisition docket, the settlement dictates even more wind, solar and storage through 2030 via the IRP, including: 600 MW of standalone storage; 400 MW of new solar connecting to the grid at the A.S. King plant site in Oak Park Heights, Minn.; and 3.2 GW of wind additions, most of which will use the Minnesota Energy Connection transmission line.
Xcel also agreed to plan for longer lifespans of its nuclear plants. It will use a 2050 retirement date for the Monticello Nuclear Generating Plant and 2053 and 2054, respectively, for Prairie Island Generating Plant Units 1 and 2.
An earlier version of Xcel’s IRP assumed a little more than 2.2 GW of new gas peaker capacity by 2030, spread across six or more new plants. The settlement terminates all but the Lyon County plans. Xcel also agreed to explore thermal battery options with Rondo Energy and file a pilot proposal with the Minnesota PUC by the end of 2025.
As part of the settlement, another filing with state regulators will come due in late 2025. Xcel agreed to devise a new model for planned and scaled distributed solar and storage capacity procurement and file it at the commission by Oct. 3, 2025.
Finally, Xcel and parties agreed the utility would try to bolster rates of participation in its energy efficiency programs for its low-income customers, track data and report on results in its next IRP.
Xcel said the agreement will allow it to reliably ensure an up to 88% carbon emissions reduction by 2030 from a 2005 baseline. The company also said the new plan unlocks tax credit savings from the Inflation Reduction Act for renewables and energy storage.
Xcel said it expects a final decision on the settlement from the Minnesota PUC in early 2025.
Leadership at the clean energy nonprofits had good things to say about the shift in resource planning.
“This joint effort marks major progress in Xcel’s and Minnesota’s energy transition,” Fresh Energy Executive Lead of Policy Allen Gleckner said in a press release. “All the parties involved are working [toward] the same goal: reliably decarbonizing our state’s electricity.”
“In addition to the 3.6 GW of new clean energy projects in the short term, we are very excited to see significant battery storage projects be selected. Storage is a real game-changer,” added Peder Mewis, Clean Grid Alliance’s regional policy director. “Among other things, it will help during extreme weather conditions and is critical for maintaining reliability and meeting Minnesota’s clean energy standard.”
Minnesota Center for Environmental Advocacy Climate Program Director Amelia Vohs called the settlement a “great outcome for the climate.”
“This plan invests in innovation that maximizes value for customers, creates jobs and supports the communities we serve,” said Ryan Long, president of Xcel Energy in Minnesota, South Dakota and North Dakota. “We’re making great progress toward our vision for reliable, affordable, 100% carbon-free electricity, and we appreciate the support of our stakeholders on an agreement that allows us to keep building the clean energy economy of the future.”
Nearly a decade on, the saga over Dynegy’s manipulation of MISO’s capacity market continues, with FERC denying the company’s asks for procedural changes that might have softened repercussions in the case.
FERC dismissed all four of Dynegy’s rehearing requests related to evidence, intent, a report on remand, and the bounds of FERC’s jurisdiction in an Oct. 4 order (EL15-70).
The latest order is part of FERC’s yearslong inquiry into Dynegy’s apparent manipulation of clearing prices in MISO’s 2015/16 capacity auction. This year, the commission directed hearing and settlement procedures. (See FERC Sets Dynegy’s MISO Market Manipulation Case for Hearing.)
Approximately eight years after the auction, commission staff unwound FERC’s original conclusion that Dynegy — now owned by Vistra — conducted itself appropriately in the auction. That’s due to a D.C. Circuit Court of Appeals 2022 ruling that FERC hadn’t sufficiently supported its decision to accept the $150/MW-day Southern Illinois capacity price produced in the 2015/16 auction. (See FERC Staff Finds Dynegy Manipulated 2015 MISO Capacity Auction.)
This time, FERC rejected Dynegy’s fresh argument that it didn’t know it was manipulating MISO’s capacity market by refusing to sell capacity at a loss ahead of the auction. The commission said Dynegy should have been aware the actions it took to make sure one of its resources set the clearing price for Southern Illinois to raise profits amounted to manipulation.
FERC also said Dynegy’s argument ignores intent.
“Dynegy’s argument that its pre-auction sales strategy was ‘driven by a desire to stop losing money’ misses the point because it ignores the broader question of whether that sales strategy was part of an intentional or reckless effort to set the Zone 4 clearing price in the auction,” FERC said.
Dynegy argued it “could not have known that [FERC’s] market manipulation rules would compel Dynegy to operate a charity — mandating that Dynegy donate its capacity to the market at prices that would not cover its going-forward costs.”
FERC declined to take up Dynegy’s claim that its alleged manipulation scheme might involve non-jurisdictional retail transactions in South Carolina rather than the MISO portion of Kentucky. The commission said it is best to “defer any legal determination as to jurisdiction until after the hearing because certain disputed issues of material fact are likely to bear upon the jurisdictional question.”
Dynegy also proved unsuccessful in persuading FERC to strike from the record its heavily redacted report from June 2022 that concluded that manipulation occurred.
FERC said the report is necessary to the case because the D.C. Circuit Court of Appeals ordered FERC to establish a public record in the case, which was lacking after the nonpublic investigation and a poorly explained decision in 2019 to accept the Zone 4 capacity price.
“[P]arties and participants are free to rely on the remand report in making their cases, and at that point, Dynegy is free to challenge the parties’ or participants’ use of the remand report. … In this way, information would be appropriately considered by the presiding judge in an evidentiary hearing encompassing allegations of market manipulation,” FERC said.
Finally, FERC rejected Dynegy’s claim that FERC didn’t share exculpatory evidence with the company during the nonpublic investigation.
Dynegy contended that it could have used nonpublic, video footage of testimony to help prove its innocence.
FERC countered that the investigation was closed without a show-cause order or sanctions and pointed out that it’s under no obligation to share exculpatory evidence in a Section 206 proceeding. Further, the commission said its staff combed through materials and didn’t find anything that could be deemed exculpatory.
At any rate, FERC said the footage Dynegy singled out is now part of the nonpublic record in the case and can be addressed during hearing proceedings.
Supporting President Joe Biden’s goal of electric vehicles making up 50% of all new light-duty car sales in the U.S. by 2030 will require the country to install more than 1 million publicly available Level 2 and direct current fast chargers in the next 6.5 years, according to a new report from the Alliance for Automotive Innovation.
That pencils out to 451 chargers per day or three chargers every 10 minutes through the end of 2030, AAI says in its Get Connected: Electric Vehicle Quarterly Report for the second quarter of 2024.
While those figures may not be attainable, both the District of Columbia and Maryland have been working on rules to encourage and accelerate the installation of EV chargers, especially at multiunit dwellings and in low-income neighborhoods, as EV sales continue to grow steadily both in the region and across the nation.
The D.C. Council on Oct. 1 voted unanimously to approve a new law (B25-106) that lays out requirements for the installation of charging infrastructure in new construction or major renovations in the nation’s capital. Beginning on Jan. 1, 2027, new single-family construction that includes private, off-street parking will have to be “EV ready” ― that is, include wiring ― for at least a Level 1 charger, which essentially would mean a regular plug in a garage or driveway.
The law also requires a new pilot program to install chargers in low-income, disadvantaged neighborhoods in the city and calls on the District’s Department of Transportation to develop a comprehensive plan for ensuring the city has adequate charging infrastructure, to be updated every three years.
The Oct. 1 order from the Maryland Public Service Commission is more narrowly focused on the rates utilities charge for the electricity used to power chargers installed at multiunit dwellings (MUDs). The PSC order (Order No. 91339) guarantees that charging rates for MUDs will be similar to residential rates, rather than commercial rates that typically include high demand charges.
While they may vary from utility to utility, demand charges tend to be based on specific times of a customer’s highest electricity use, and for some apartment building or condominium owners, the high rates involved could make installation of an EV charger financially unfeasible, local residents told the PSC.
Under the new order, the utilities must offer such customers an EV charging rate equivalent to residential rates — either standard rates based on the volume of power used, or time-of-use (TOU) rates based on whether EVs are charged during on- or off-peak hours.
“One of the major reasons people hesitate to get an electric vehicle is ‘range anxiety,’ or the fear that they can’t envision how they will keep their car charged at home or out and about,” said D.C. Councilmember Charles Allen, who first introduced the D.C. legislation late in 2022 and has shepherded it through committee hearings and final amendments.
“We don’t have that fear with gas-powered vehicles because the infrastructure is built out,” Allen said in a statement announcing approval of the bill on its first reading before the Council. “It’s time to do that for electric vehicles. This is an infrastructure bill that sets goals and clears red tape to get more chargers installed where people actually want them.”
The bill must still pass a second vote before the council and be signed into law by Mayor Muriel Bowser.
The push for more chargers comes as the EV markets grow in both D.C. and Maryland. According to the AAI report, both have joined 10 other states across the country where EVs represented more than 10% of new light-duty vehicle registrations in the second quarter of the year.
The U.S. Department of Energy reported that D.C. had 8,066 EVs registered as of the end of 2023, while the federal Joint Office of Energy and Transportation counts a total of 324 publicly available charging locations in the city, with 1,070 charging ports currently in operation.
The federal figures for Maryland are 72,139 EVs registered as of the end of 2023, and 1,844 charging stations with a total of 5,178 charging ports currently in operation.
DC Law in Detail
Both of the new rules are aimed at getting chargers into neighborhoods and locations that have significant populations that live in apartments and would have to rely on public chargers.
Maryland’s rule taking demand charges out of the equation should remove at least one barrier for more installations, while the D.C. law takes a more comprehensive approach.
New apartment houses with more than six off-street parking spaces will be required to make 25% of those spaces EV ready beginning in 2027, and those percentages will go up to 29% in 2031 and 33% in 2034. Chargers in apartment houses are typically Level 2 chargers, which require upgrades to standard residential electrical wiring to support the higher voltage these chargers use.
New commercial buildings with more than six spaces will have to install chargers in 15% of their spaces and have an additional 25% EV ready.
The law also prohibits apartment building owners or condominium associations from prohibiting individual residents from installing EV chargers for their own use ― for example, in a designated parking spot ― subject to some conditions. A resident would have to use licensed electricians or building engineers for the design and installation of a private charger and would be responsible for paying for the electricity used by the charger, as well as for its maintenance.
The law also requires the D.C. Department of Transportation (DDOT) to establish a Neighborhood Electric Vehicle Charging Infrastructure Pilot Program, which by Jan. 1, 2026, will install at least one Level 1 charger in each of four low-income neighborhoods in the city. The chargers will be sited at publicly accessible locations, such as on streetlamps or utility poles, or in public parking lots owned by D.C., and the DDOT will be required to post a list of the locations on its website.
The Department of Energy and Environment (DOEE) is tasked with publishing an Electric Vehicle Infrastructure Deployment and Management Plan on its website, with the first report due also on Jan. 1, 2026, followed by updates in 2029 and 2032.
The reports will include the number of EVs currently registered in D.C., a 10-year forecast of EV adoption and DOEE’s plans to ensure that “the number of electric vehicle charging ports in the District is equal to at least 5% of the number of electric vehicles DOEE forecasts will be registered.”
The DOEE report must also assess the city’s electric grid capacity and whether it will be able to “meet and sustain the demand for electric vehicles.”
Growth of Leasing and Used EV Markets
Despite often downbeat headlines and U.S. automakers’ retreat from their earlier ambitious EV goals, both the AAI report and a third-quarter market update from industry analyst Cox Automotive show that EV sales are rising across the U.S.
AAI reports EVs represented just under 10% of new light-duty vehicle sales in the first half of the year, while Cox Automotive’s Stephanie Valdez Streaty, director of industry insights, similarly pegged EVs with close to 9% of the market.
The sales figures in both reports include full battery EVs and plug-in hybrids, but not traditional hybrids.
EV sales in the third quarter showed “steady demand, a slower pace, yet record sales,” Valdez Streaty said. “We’re on track for another record-breaking quarter, with a forecasted EV sales volume at 338,844, reflecting an 8% year-over-year increase.”
She noted also that both the second and third quarters have seen consecutive months with over 100,000 EV sales. August’s sales of 119,652 EVs were a new record, and a 12.6% year-over-year increase.
But EVs’ upfront cost is still a barrier, with the average EV price, about $56,300, still 15.9% higher than the industry average as of June this year, according to figures from Cox.
Both reports highlighted some key trends.
The AAI report noted that sales of cars with traditional internal combustion engines (ICEs) have peaked. ICE vehicles represented 97% of new vehicle sales in 2016 but only 78% in the year to date in 2024. However, that decline in sales is being filled in large part by traditional hybrid vehicles, not plug-ins. The traditional hybrid market grew from 2% of the new sales in 2016 to 12.3% through the second quarter of 2024.
AAI also counted 117 different electric models sold in the second quarter, including 68 full EVs, 47 plug-in hybrid models and two fuel-cell vehicles. SUV models continue to lead the market, accounting for more than 70% of second-quarter EV sales.
Valdez Streaty pointed to the popularity of leasing as a more affordable pathway for EV adoption as well as a growing source of used EVs for the secondhand market.
“EV leasing remains highly attractive to consumers, offering benefits such as lower upfront costs, reduced financial risk, flexibility to upgrade to new EV models and elimination of residual value concerns,” she said.
Leasing accounted for 39% of new EV sales in June, which is about double the general industry average, she said. Third-quarter sales for used EVs could hit around 78,000, a 69% increase year over year.
With most leases lasting about three years, Valdez Streaty said, “a wider range of vehicles will soon come off lease and enter the market, offering consumers more affordable and diverse options as we move towards an all-electric future.”
The PJM Deactivation Enhancements Senior Task Force (DESTF) has delayed voting on five proposals to rework the RTO’s rules for the advance notification generation owners must provide before deactivating units and the compensation structure for resources offered reliability-must-run (RMR) contracts.
Following several major changes to proposals presented during the group’s Oct. 2 meeting, participants requested additional time to understand where each package stands. An additional DESTF meeting was scheduled for Oct. 17 to open the vote, which will be conducted on the PJM website after the meeting closes. The Independent Market Monitor, Sierra Club and Calpine have each sponsored proposals in the DESTF, while PJM has sponsored two packages, one of which was presented for the first time Oct. 2.
The most significant changes were made to the Monitor’s proposal, with new language added that would model the expected output of RMR units in the capacity supply stack — counting them toward meeting the reliability requirement without mandating that they offer into Base Residual Auctions (BRAs) and take on Capacity Performance (CP) obligations
Monitor Joe Bowring has argued that not including RMR resources in the supply stack is inconsistent with PJM’s practice of modeling their output when calculating the capacity emergency transfer objective (CETO) and limit (CETL) for different delivery areas. Under the Monitor’s proposal, RMR resources would not be included in the day-ahead or real-time energy markets nor ancillary services unless required to maintain transmission reliability or resource adequacy. (See PIO Complaint Faults PJM Treatment of Deactivating Generation.)
Anti-toggling rules were also added to the Monitor’s package, stating that if a RMR unit ultimately decides not to deactivate after the contract term has begun, it would be required to refund capital recovery for improvements and maintenance to the appropriate load-serving entity.
The compensation rate in the Monitor’s package was adjusted to be based on short-run marginal costs (SRMC) rather than megawatt-hours, and an applicable adder of 10% of the deactivation avoidable cost rate was also added. Actual revenues would be the market revenues the RMR resource receives, such as energy and ancillary service payments, minus the SRMC for the unit.
A limit to the duration of RMR contracts was proposed by the Monitor, capping them at five years with a possible three-year extension. Any requests for an extension would have to be presented to the PJM membership at least a year in advance, where practical, so stakeholders can explore alternative solutions to resolving the underlying transmission violations.
PJM’s Package A pointed to the IMM’s language defining the compensation rate and would allow generation owners to choose between the Monitor’s net revenue compensation approach or the status quo cost-of-service option.
All five proposals would require generation owners to provide PJM with at least one year’s notice ahead of their desired deactivation date, while the RTO’s proposals contain exceptions for units that must retire to comply with government policies and catastrophic failures. PJM also added language granting exemptions for the requirement that resources must offer into capacity auctions for years when the unit would be granted deactivation.
The Monitor’s proposal includes exceptions for failures and a “clear regulatory order to retire,” which is mirrored by the Calpine package. The Sierra Club would allow early deactivation, within the one-year notification period, if PJM determines that there would be no reliability issues created by the retirement, along with catastrophic failures and policies that would make the resource uneconomic.
PJM also introduced a new Package D aimed at compromising with some of the changes made to the Monitor’s proposal. It would remove the $2 million limit on project investment costs recoverable through the default compensation rate and rework the default avoidable cost credit (DACC) calculation when it is used for determining compensation. Other components are based on Package A.
David “Scarp” Scarpignato, of Calpine, said it would be inappropriate to move to a vote immediately after major changes were presented to proposals that could change stakeholders’ voting positions. Several changes would also need to be made to the Calpine proposal, which contained references to the original IMM and PJM packages for some components.
Calpine’s proposal would preserve the status quo compensation rate with a 20% applicable adder and adopt the Monitor’s components on actual revenues, RMR term limits and requiring RMR agreements to be public. The company copies PJM’s language on notification timelines. Calpine’s anti-toggling rules would require an RMR unit that reverses its retirement during the RMR term to refund LSEs for payments toward capital improvements. The requirement would also be effective for units that return to serve two years after deactivation.
The Sierra Club proposal largely mirrors the Monitor’s language, but it would subject RMR units to CP penalties for underperformance with an annual stop-loss set at the BRA clearing price per megawatt.
Package sponsors discussed both notifying other parties with proposals of any significant changes ahead of the Oct. 17 meeting and replacing cross-package references with specific language to avoid repeat conflicts. There were also requests for PJM to draft a document or presentation that details the differences between each proposal.
The Rhode Island Energy Facility Siting Board (EFSB) ruled Oct. 3 that it has jurisdiction over large battery storage projects, overruling precedent and giving the board the ability to override local permitting decisions on storage projects if it deems a project has met all the legal requirements (SB-2024-01).
In April, the Quonset Development Corp. (QDC) requested the EFSB declare a proposed 210-MW battery project is outside the board’s jurisdiction, arguing the EFSB has determined “it does not have jurisdiction over battery energy storage systems.”
The prior precedent stems from a 2019 EFSB ruling that a 180-MW storage resource is not under the jurisdiction of the board because the state’s Energy Facility Siting Act does not reference battery storage (SB-2019-02).
QDC also argued the EFSB does not have jurisdiction over a substation, tie line and switchyard needed to connect the battery to the transmission system, writing that the 115-kV tie line “is not a transmission line” and instead is “a line that connects a non-generating battery energy storage system for the purpose of storing and discharging electricity.”
The EFSB wrote in its ruling the question of jurisdiction hinges on “whether the project itself or any component thereof falls within the definition of a ‘major energy facility,’ as defined by the Energy Facility Siting Act.”
The definition includes “facilities for the generation of electricity designed or capable of operating at a gross capacity of forty (40) megawatts or more.”
While QDC argued this definition does not apply to battery storage, the EFSB disagreed, highlighting language from ISO-NE and FERC that categorizes battery storage as a type of generation.
“It would be illogical for the state and federal definitions to collide with each other, especially when the energy industry is inherently interstate in nature and Rhode Island is inextricably dependent upon the regional electric system for continuous reliable service,” the EFSB wrote.
Regarding the precedent set by its 2019 ruling, the EFSB wrote that it “respects the importance of following the reasoning of prior cases and adhering to settled rules,” but added it ultimately is “not bound by its prior decisions and can depart from its own precedents, as long as the agency explains why such a departure is reasonable.”
The EFSB also highlighted the implications the ruling could have on the state’s clean energy goals. This year, Rhode Island set a target of installing 600 MW of storage by the end of 2033; the project at issue in the ruling would meet over a third of this goal. (See RI Sets 600-MW Energy Storage Target.)
While no local permits would be required for this project, which would be in an industrial park, local permitting could pose “an insurmountable obstacle” for future battery projects in the absence of EFSB jurisdiction, the board wrote. The EFSB can overrule local permitting decisions for projects under its authority.
The EFSB similarly found that it has jurisdiction over the infrastructure needed to connect the battery facility to the transmission grid.
“Given the numerous FERC cases unambiguously illustrating that generator tie lines are jurisdictional transmission facilities, the claim made by petitioner that the 115-kV Generator Tie Line is not serving a transmission purpose is contradicted by FERC precedent and, therefore, is unsustainable,” the EFSB found.
It added that a lack of EFSB jurisdiction over interconnection infrastructure “could have been devastating to the ability of an offshore wind developer in the future to interconnect its project to the transmission system within or through Rhode Island, given the potential for local opposition.”
The EFSB said the project developer must submit an application for the battery facility and its associated electric infrastructure.
