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October 11, 2024

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NYISO Extends Reliability Needs Assessment Comment Period

In response to stakeholder criticism, NYISO has updated its draft Reliability Needs Assessment to include an executive summary and appendices, and extended the comment period on the report to Oct. 14.  

“We definitely heard stakeholders’ concerns about not having enough time to review the complete report with the executive summary,” Ross Altman, senior manager of reliability planning for NYISO, told the Transmission Planning Advisory Subcommittee on Oct. 9. “So, we tried to shift the schedule up a little bit on that.” 

Altman said NYISO would try to address the comments for the next version of the RNA, to be presented Oct. 21 to the Electric System Planning Working Group meeting and Oct. 24 to the Operating Committee. 

“As one of the people who asked for more time, I want to say thank you for giving us a little bit more time; it’s appreciated,” said Kevin Lang of Couch White. 

Stakeholders spent most of the meeting discussing the results of the RNA, which predicted that on a peak summer day with expected weather conditions (95 degrees Fahrenheit), New York City would be deficient by 17 MW for one hour in 2033, rising to 97 MW for three hours in 2034. The analysis suggests that the ISO needs to declare an official reliability need for the city’s capacity zone. (See NYISO Draft RNA Finds Reliability Need for New York City.) 

The discussion focused on whether that was actually significant, or if it was a result of uncertainties in NYISO’s data and assumptions. 

“So the results point to a 17-MW, one-hour deficiency 10 years from now?” asked Marc Montalvo, CEO of Daymark Energy Advisors. “Is that statistically different from zero?” 

Montalvo pointed out that the given the magnitude of the system and the uncertainties, 17 MW might just be statistical “noise.” He asked Altman how to interpret that “in an actionable way.” 

“Do we run out and do something, or do we say, ‘Look, this needs five more years of information before we even start to worry about it’?” he asked. 

Altman said that before any solution was solicited, NYISO would re-evaluate if the need still existed based on updated information. He pointed out that there were resources in development that could come online in the next 10 years but were not far enough along to meet NYISO’s base case assumptions. 

“We have an opportunity to re-evaluate next year to see if the updates would make the problem go away,” Altman said. “And then in the evaluation of solutions, we do consider which solutions are best suited for meeting this need, but we have to have a solution. … We can’t just show there’s a reliability violation and do nothing about it.” 

Crypto Companies Pivoting to AI

Stakeholders also revisited NYISO’s assumption about the flexibility of cryptocurrency mining and hydrogen-producing loads.  

The ISO had issued a preliminary finding of a statewide shortfall of as much as 1 GW by 2034, but it revised its assumptions about the flexibility of such large loads during peak hours, which reduced the loss-of-load expectation to below 0.1. (See NYISO: Large Load Flexibility Eliminates 2034 Shortfall Concern.) 

But there is a very real possibility that these loads will not be as flexible as NYISO assumes. Cryptominers are increasingly shifting their facilities’ operations to training artificial intelligence. 

“There is an increasing interest among cryptocurrency mining facilities to actually switch over to doing AI, which, because of their service level agreements, is much less flexible,” one stakeholder noted. “Their willingness to do one and not the other depends on, to a large extent, the price of Bitcoin or whatever other cryptocurrency they’re mining.” A data center’s stated purpose as a cryptomining operation had very little bearing on whether it would remain as one in the future, they said. 

Reuters reported in August that technology companies are seeking the energy assets held by crypto miners as they race to secure electricity supply for AI and cloud data centers, estimating that about 20% of cryptocurrency could pivot to AI by the end of 2027. 

“We do monitor [that], but we do recognize that we don’t know exactly how they continue to evolve,” Altman said. “Any specifics you have on that, or research you’d like to share, please email” the ISO. 

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NERC Examining Lessons from IBR Standard Development

NERC’s staff are working on a “postmortem” examining the development of the ERO’s recently approved reliability standard setting ride-through requirements for inverter-based resources to identify lessons for the future, the organization’s vice president of engineering and standards told its Board of Trustees. 

“We’re trying to comprehensively map out a plan forward for the next year,” Soo Jin Kim told trustees at a special board meeting Oct. 8, referring to the work needed to meet the next milestone in FERC Order 901. The order, passed last year, requires NERC to submit standards to improve the reliability of IBRs in three tranches between 2024 and 2026. According to Milestone 3, the ERO must file standards addressing data-sharing and model validation for all IBRs by Nov. 4, 2025. (See NERC Submits IBR Work Plan to FERC.) 

Milestone 2 covered performance requirements and post-event performance validation for registered IBRs, and the standards for this segment must be submitted to FERC by Nov. 4 of this year. Those standards were the main reason for the Oct. 8 board meeting, with trustees unanimously voting to adopt the standards: 

    • PRC-024-4 — Frequency and voltage protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers.  
    • PRC-028-1 — Disturbance monitoring and reporting requirements for inverter-based resources.  
    • PRC-002-5 — Disturbance monitoring and reporting requirements.  
    • PRC-030-1 — Unexpected inverter-based resource event mitigation. 
    • PRC-029-1 — Frequency and voltage ride-through requirements for IBRs. 

All five standards will be submitted to FERC for final approval. 

Kim said NERC’s developers will look to streamline the development cycle for the upcoming milestones by examining their experience on the Milestone 2 standards — especially PRC-029-1, which met significant opposition by industry stakeholders in multiple formal ballot rounds.  

The standard’s failure to achieve the required two-thirds segment weighted approval led the board to exercise for the first time its authority under Section 321 of NERC’s Rules of Procedure to streamline the stakeholder approval process. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) Trustees directed the ERO’s Standards Committee to convene a technical conference to hear feedback from industry, use that input to revise the standard and post the updated standard for another ballot round.  

Board Chair Ken DeFontes praised the work of NERC’s staff adapting to these directives, which required the entire process to be carried out within 45 days (though NERC did extend balloting for PRC-029-1 to give industry more time to review the changes, meaning the results came in several days after the 45-day limit).  

Kim said NERC found the technical conference helpful to identify issues that kept industry from supporting previous versions. She suggested that when developing the Milestone 3 standards, the ERO will proactively call for similar gatherings to “get ahead of several of the technical issues that we see, particularly with regard to modeling.” 

“We’re going to try to have, not just a technical conference, but a working session where we will have breakouts, learn from what transpired during the second milestone, and try to get to the heart of the matter with regards to certain changes that need to be applied to some of the standards,” Kim said. “We agree in concept on what needs to occur with regards to modeling, [but] there’s going to be several technical sessions.” 

The board also voted to accept revisions to the charter of NERC’s Reliability and Security Technical Committee that are intended to improve the balance of industry representation at committee meetings. 

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Panel Calls for Greater Interregional Planning Across the Northeast

Unlocking the full potential of Quebec hydropower to balance renewables through the Northeast will require major efforts to overcome barriers to transmission planning and development, speakers at a webinar led by the Acadia Center emphasized on Oct. 9.

While studies have shown increased bidirectional transmission capacity between the Eastern Canadian provinces and the Eastern U.S. could significantly reduce the costs of decarbonizing the grid, such transmission projects so far have struggled. (See Québec, New England See Shifting Role for Canadian Hydropower and National Grid Backs out of Twin States Clean Energy Link Project.)

The webinar kicked off with pre-recorded remarks from U.S. Sen. Ed Markey (D-Mass.), who said “the clean energy revolution is here at our doorstep,” but “our grid is an inaccessible, one-lane road from the Model T era.”

Markey highlighted his proposed legislation that would direct FERC to require RTOs to regularly engage in interregional planning and establish independent transmission monitors. (See Dems Introduce Bill on Transmission Planning, RTO Transparency.)

Despite the significant up-front costs of major new transmission lines, grid modeling indicates that “in a low-carbon system in New England and Québec, building more bi-directional transmission lowers the cost of electricity,” said Emil Dimanchev, a research affiliate at the MIT Center for Energy and Environmental Policy Research.

Increased bi-directional transmission would reduce the need to curtail renewables during periods of excess generation, Dimanchev said. It also would reduce reliance on gas resources by enabling hydro to take a greater balancing role paired with intermittent renewables.

Along with cost savings, increased interregional transmission also could provide significant reliability benefits.

“Transmission gives us this ability to combine wind resources from both sides of the border, which together are much more reliable,” Dimanchev said.

Adrienne Downey, principal engineer at the floating offshore wind developer Hexicon, said offshore wind pairs particularly well with hydropower when there is enough transmission capacity to enable hydro to firm up the intermittencies of wind.

“Offshore wind is pretty much a match made in heaven with this load growth, these winter peaks … and looking at hydro and the opportunity to replenish reserves,” Downey said.

Hexicon is part of a coalition that has proposed a “shared offshore backbone transmission corridor” to connect offshore wind resources along the northern Atlantic coast, reaching shore in both New England and Nova Scotia.

The proposal likely would pay for itself through reduced power costs but remains “really a question of proactive planning,” Downey said.

Additional interregional transmission capacity also would help to even out localized weather patterns as weather-dependent renewables make up a larger portion of the generation mix, said Hannes Pfeifenberger of the Brattle Group.

About 4 GW to 7 GW of transmission capacity likely will be needed and would be “cost effective” between Canada and both New England and New York, but “the reality is there are significant barriers,” Pfeifenberger said. A lack of trust between regions, inadequate planning tools and regulatory constraints all pose challenges.

“You need everybody at the table, which is why it’s so challenging,” Pfeifenberger said. He emphasized the need to build understanding around the importance of interregional planning to lay the groundwork for agreements regarding specific transmission needs and cost allocation frameworks.

Downey said grid operators, lawmakers and officials must work to expand beyond often-ingrained habits of hyper-focusing on the local grid, while also respecting the cultural differences in how regions approach their power system.

“To bridge that, and to have these broader regional discussions, there’s some cultural sensitivities,” Downey said. “It’s important that we think about this as a social and cultural exchange with related co-benefits.”

Beyond just adding new lines, transmission planning could help identify opportunities to increase line capacity when conducting asset condition upgrades, Pfeifenberger said.

Costs associated with maintaining the aging New England grid have accelerated in recent years, putting pressure on ratepayers and causing friction between the states and transmission owners, who have proposed several infrastructure projects costing hundreds of millions of dollars. (See New England States Raise Alarm on Eversource Asset Condition Project.)

Increasing line capacity could cost more in the short term but could provide significant long-term savings, Pfeifenberger said.

“We have an existing grid that was built in the ’60s and ’70s,” Pfeifenberger said. “We can save money and reduce community impacts by better planning.”

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EIA: Colder Weather and Lower Fuel Prices Likely Mean Flat Bills This Winter

The U.S. Energy Information Administration expects consumers will spend roughly the same on winter heating this year as they did last year, according to its Winter Fuels Outlook. 

“Overall, we expect that there’s going to be, generally speaking, lower fuel prices that are going to be offset by higher consumption this winter,” EIA Administrator Joseph DeCarolis said in an Oct. 9 webinar. 

The two biggest sources of space heating across the country are natural gas and electricity, at 45 and 43% of all households. On average, bills for both sources should go up slightly this winter. 

The Midwest is expected to see higher bills than last year, as consumers there are expected to spend 11% more on natural gas, compared to the 1% national average, and 6% more on electricity, compared to the 2% national average. The Midwest had an exceptionally mild winter last year, so the return to more normal temperatures in the region is expected to lead to a bigger jump in demand for heating, the outlook said. 

While wholesale prices have fallen this year, weather forecasts call for more cold, with EIA expecting heating degree days to tick up 5% compared to last year. But it still is expected to be a generally mild winter, with the forecast calling for heating degree days to be 2% below the average of the previous decade, DeCarolis said. 

For the first time, EIA broke out the share of the average bill for each fuel that goes toward space heating. While customers spend more on electric bills overall, the space heating portion of EIA’s estimates are almost the same as those for natural gas, though the South has the biggest share of electric heating. 

Temperatures can have a big effect on winter prices, though when it comes to electricity and natural gas, the effect is felt more in the wholesale markets. The impact lags on retail prices because, for the most part, they are overseen by state regulators, EIA analysts said in the webinar. 

The prices for propane, which is used by 5% of households concentrated in the Midwest, and heating oil, used by 3% of total households almost entirely in the Northeast, vary more significantly with temperature because wholesale prices are more closely linked to residential prices. 

Some five major storms have led to major effects on natural gas and power systems over the past 15 years, but those are difficult for EIA to predict. (See Déjà Vu as FERC, NERC Issue Recommendations over Holiday Outages.) 

“Something like a major winter storm or an acute weather event is difficult to build into our forecast because the impact on price is of something like that would be highly dependent on where the storm hits,” EIA’s Corrina Ricker said. “For example, if it were to impact production, or if it’s close to large demand centers, those types of factors would really play into how the natural gas price would be impacted.” 

Winter storms can cause major price spikes, but those are short-lived, and their effect on residential prices usually is felt later when regulators allow utilities to recover costs from such events, she added. 

A major trend in home heating is the adoption of heat pumps. But given how many other factors beyond the equipment can affect a home heating bill, EIA wasn’t able to tease out any differences between that technology and traditional electric heating. EIA said it was working on how to isolate the effect of different heating equipment on consumer utility bills.  

“The consumption and expenditures associated with these technologies depend to a large extent on household characteristics and the climate in which they are located,” the winter outlook said. “For example, an electric resistance heater used in a small, well-insulated home in the South could result in lower expenditures than an air source heat pump placed in a larger, drafty home in the Northeast.” 

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IEA Expects 5.5 TW of New Renewables by 2030

The world is on track to expand its renewable energy capacity 2.7 times by 2030, the International Energy Agency reports. 

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.” 

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Report Examines Grid Planning for Building Electrification

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.

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Wash. Kicks off Cap-and-Invest Electricity Forum

Washington’s Department of Ecology kicked off its first virtual electricity forum on 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.”

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Vermont PUC Rejects Heating Fuel Credit Trading Concept

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. 

Vermont Act 18 became law in May 2023 when the legislature overrode a veto by Gov. Phil Scott (R), who cited cost concerns. (See Vermont Governor to Veto Building Decarbonization Measure.) He had vetoed a similar measure in 2022. 

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. 

The use of electric heat pumps is gradually increasing in Vermont. (See Vermont Heating Fuel Sales Decreasing in Recent Years and Vermont Gas Utility Explains its Effort to Electrify Customers.) 

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. 

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W.Va. PSC Adviser Jackie Roberts Announces Retirement

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.”

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IRP Settlement Accelerates Xcel’s Clean Energy Transition

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, build 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 gigawatts 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.”