Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
B. Endorse proposed revisions to Manual 01: Control Center and Data Exchange Requirements that would specify that entities may have multi-layered communication methods and are required to notify PJM of a failure only if all modes have failed and only alternates remain. The revisions arose from the manual’s periodic review. (See “Stakeholders Endorse Manual Revisions Related to Communication Failures,” PJM OC Briefs: Sept. 7, 2023.)
C. Endorse proposed revisions to Manual 12: Balancing Operations that aim to clarify that reserve resources should respond to a synchronized reserve deployment when they receive notification through any of the existing Energy Management System datalinks. (See “Stakeholders Endorse Quick Fix on Synchronized Reserve Dispatch,” PJM OC Briefs: Sept. 7, 2023.)
D. Endorse proposed revisions to Manual 28: Operating Agreement Accounting adding clarifying language, grammatical updates and removing terminated business rules.
Endorsements (9:10-10:30)
1. Enhancements to Deactivation Rules Issue Charge (9:10-9:45)
PJM’s Chris Pilong will review a problem statement and proposed issue charge that address possible enhancements that can be made to deactivation rules. The problem statement lays out concerns PJM has identified with how compensation is determined under reliability-must-run contracts and the timeline for when generation owners must notify PJM of their intent to retire a unit. (See “Stakeholders Defer Vote on Generation Deactivation Issue Charge,” PJM MRC Briefs: Aug. 24, 2023.)
The committee will be asked to endorse the proposed issue charge.
2. Reserve Certainty Issue Charge (9:45-10:30)
PJM’s Donnie Bielak will review a problem statement and proposed issue charge that would create a new senior task force to explore reworking several areas of the reserve markets, including performance and penalties, aligning offers with resource capability and fuel procurement and reserve procurement targets. (See “PJM Provides First Read on Reserve Certainty Issue Charge,” PJM MRC Briefs: Aug. 24, 2023.)
Independent Market Monitor Joseph Bowring and Deputy Monitor Catherine Tyler will review an alternative version of the issue charge, in which the Monitor has removed several key work areas and added specificity to others.
The committee will be asked to endorse one of the proposed issue charges.
Members Committee
Consent Agenda (1:20-1:25)
C. Endorse a proposal, with corresponding tariff revisions, addressing the amount of credit market participants must maintain to satisfy their peak market activity requirement. (See “Peak Market Activity Credit Changes Endorsed,” PJM MRC Briefs: Aug. 24, 2023.)
PJM’s Dave Anders will review the sector nominees under consideration for election to the 2023-24 Nominating Committee. The committee will be asked to elect the sector representatives upon first read.
MINNEAPOLIS — Amid the Independent Market Monitor’s denunciation of MISO’s fleet assumptions for long-term transmission plans, MISO lead planners last week defended their approach to planning for 2040.
Stakeholders, meanwhile, continued to debate whether it’s proper for IMM David Patton to deviate from markets to weigh in on MISO transmission planning.
MISO Vice President of System Planning Aubrey Johnson said MISO is seeking an “optimal, cost-effective expansion” in its second, multibillion-dollar long-range transmission plan (LRTP) portfolio that can hold up under several hypothetical circumstances.
That comes two weeks after Patton repeated criticisms of MISO’s future fleet assumptions behind its second LRTP portfolio. The IMM has alleged MISO is overestimating renewable additions and baseload generation retirements while underestimating future battery storage. He has said a transmission overbuild stands to harm market functions. (See Market Monitor Questions MISO Fleet Assumptions in Long-term Tx Planning.)
“We are not the resource planners,” Johnson told board members at a Sept. 12 System Planning Committee of the MISO Board of Directors meeting. “But what we do is take these plans and goals from our members and make a path that shows how they can be accomplished.”
Johnson said MISO “has not seen any indication” that members’ plans have changed. It remains that 70% of MISO load is associated with members’ decarbonization commitments, he said.
MISO hasn’t yet recommended any transmission projects under the second LRTP portfolio. That’s set to happen next year.
“This whole process has tension in it,” Johnson said, referring to “standing-room-only” stakeholder workshops full of members with differing views on generation and transmission expansion. He promised that MISO will run several analyses and stress tests against multiple planning scenarios and the IMM’s idea of the resource mix before recommending lines.
“We recognize that the portfolio we recommend, the state commissioners today might not be the commissioners that approve those projects,” Johnson said.
Some stakeholders said the IMM’s opinions on MISO’s future fleet deserves research.
Alliant Energy’s Mitch Myhre asked MISO to take the time to perform a sensitivity analysis that includes the IMM’s view of the future and “arrive at a set of projects that have good business cases.”
North Dakota Commissioner Julie Fedorchak said the expected second LRTP portfolio price tag at $20 billion to $30 billion warrants careful examination. She also said North Dakota supports MISO taking a deeper look at its battery storage projections.
“We are talking about extreme amounts of money, and that’s not even taking into account the generation, that will be borne entirely by ratepayers,” she said.
WEC Energy Group’s Chris Plante said while the first $10 billion LRTP portfolio was “low-hanging fruit” of known choke points on the system, the second LRTP portfolio is a more drastic investment.
But some MISO members took to the Sept. 12 Markets Committee of the Board of Directors to condemn Patton’s disapproval of MISO’s planning assumptions.
ITC’s Brian Drumm said the IMM has “repeatedly invoked the authority of his office in an attempt to force MISO and its stakeholders to implement one person’s vision for MISO’s energy future.”
“The IMM’s attempt to influence LRTP tranche two regional transmission planning is neither necessary, impartial, effective, market monitoring [nor] within the scope of the plan,” Drumm said.
Drumm said Patton’s “out-of-scope intervention” in LRTP planning is “disruptive.” He asked that MISO’s board intervene and prevent the IMM from attempting to undermine MISO’s fleet assumptions that “economically incorporate the letter and the spirit of the decarbonization and renewable energy goals of MISO’s members and states.”
Other stakeholders characterized the IMM’s recent involvement in the fleet assumptions underpinning the LRTP as an 11th-hour attempt at circumventing MISO’s second portfolio of long-term transmission planning.
Clean Grid Alliance’s Beth Soholt said she believed MISO and members are adequately capturing the most likely range of future fleet mix possibilities.
“We need a grid that can support all this uncertainty and all of these changes,” she said.
Soholt added that Patton’s inappropriate foray into transmission planning comes as MISO is reupping the IMM’s annual contract. She advised MISO not to expand monitoring duties to include planning.
Patton did not respond to RTO Insider’s request for comment on the divide. He did not respond in real time during the Markets Committee.
Sen. John Hickenlooper (D-Colo.) and Rep. Scott Peters (D-Calif.) on Friday introduced the Building Integrated Grids With Inter-Regional Energy Supply (BIG WIRES) Act, which would require minimum levels of interregional transfer capability between regions.
The two have been working on the bill for months. It was discussed during the debt ceiling negotiations earlier this year, but ultimately not included in the package that passed. (See Debt Ceiling Bill Provides ‘Mini-deal’ on Permitting.)
“If we want to maintain our national security amidst growing international conflict, make our power system more reliable and cut high energy costs for Americans, we can’t have a faulty, outdated electric grid,” Hickenlooper said in a statement. “Our bill advances two priorities simultaneously: Make electricity more affordable and build a power grid fit for the 21st century.”
The bill would direct FERC to better coordinate construction of an interregional transmission system by requiring each of its transmission planning regions (that date from Order 1000 and include jurisdictional ISO/RTOs) to be able to transfer 30% of their peak electric loads to their neighbors.
The lawmakers compared the current development of the transmission grid to building new highways that crisscross the country every time two towns need to be connected. They say their bill would close current gaps in the transmission network by doing the equivalent of “building new exit ramps off the existing interstate.”
“During a heatwave, hurricane or other natural disaster, the last thing you want is for the power to go out. It can be the difference between life and death,” said Peters. “There is no reason neighboring electrical grids should not have the capacity to share power during these situations to avoid blackouts. The associated buildout of electric transmission lines would greatly improve reliability and keep costs down for consumers. BIG WIRES will help get clean, reliable energy from where it is produced to where it is used by people, but above all else, it is an American energy security and independence bill.”
On top of the reliability benefits, the legislation also would reduce energy costs by allowing regions where power prices are cheaper to sell into regions where it’s more expensive and by allowing all regions to connect new, low-cost resources to the grid.
The bill aims to be technology neutral, allowing all types of generation to connect to the grid and relieve grid congestion where needed. The lawmakers said it would prioritize regional flexibility by allowing the FERC planning regions to decide how they will upgrade their systems.
The bill has a section devoted to ERCOT, which never has had much interconnection with the Western and Eastern Interconnections, giving the Texas PUC authority over its wholesale markets and transmission planning. The PUC “may, at its sole discretion” choose to support the reliability and affordability of the Texas grid by voluntarily complying with a minimum transfer capability equal to a percentage, determined by ERCOT, of its coincident peak load, the bill said.
The two offices released a suite of supportive quotes from clean energy groups, transmission supporters, environmentalists and some former regulators who were on the FERC-State Joint Task Force on transmission, where the idea of interregional transfer capacity was widely supported. (See States Back FERC Interregional Transfer Requirement.)
Former FERC Chairman Rich Glick noted that recent years have seen extreme weather test the grid and the bill would help deal with those situations by increasing interregional transfer capability.
“Utility customers are at greater risk of losing access to power during extreme weather events, and they are often forced to pay much more for electricity than they otherwise would with a more efficient electric grid,” Glick said in a statement. “Senator Hickenlooper and Congressman Peters deserve credit for elevating this important subject with the introduction of the BIG WIRES Act.”
The legislation also won praise from Glick’s former colleague from across the aisle, former FERC Chairman Neil Chatterjee.
“By requiring that FERC establish a minimum interregional transfer capability standard, this important legislation will dramatically improve our country’s ability to move power between regions where and when it’s needed most, enhancing grid reliability for all Americans,” he said in a statement.
Former Maryland PSC Chair and FERC-State task force co-chair Jason Stanek also gave the proposal a supportive quote.
“Increasing interregional transmission capacity will be critical to maintaining reasonable utility rates and sustaining a reliable bulk power system,” Stanek said. “This bill builds upon recent discussions by the Joint Federal-State Task Force which highlighted the important role that interregional transmission will play as we strengthen our nation’s power grid.”
Other backers of the legislation include Americans for a Clean Energy Grid, American Clean Power Association, American Council on Renewable Energy, Advanced Energy United, Business Council for Sustainable Energy, Clean Energy Buyers Association, the Electricity Consumers Resource Council, Environmental Defense Fund, Natural Resources Defense Council, Rocky Mountain Institute, the R Street Institute and the Solar Energy Industries Association.
The bill could become part of a broader effort on permitting, which has a chance of passing this year. On Thursday, Senate Energy & Natural Resources Committee Chair Joe Manchin (D-W.Va.) and Ranking Member John Barrasso (R-Wyo.) released a joint statement saying they agreed on the need to change permitting laws and regulations generally.
“We are in agreement that we must act to accelerate our permitting system and are committed to reaching a bipartisan solution that prioritizes American energy security, reliability and affordability,” the two said.
Members to Vote on Whether to Place Former Ford Exec on Board
MINNEAPOLIS — MISO’s Board of Directors next year likely will include a former Ford executive, directors announced last week.
MISO’s Nominating Committee interviewed eight candidates and two incumbents to fill three open slots on the board beginning in January. Current members Jody Davids, Theresa Wise and Robert Lurie are rounding out three-year terms and were up for re-election.
Davids ultimately decided not to seek a second term on the board. She joined the board at the beginning of 2021.
The opening likely will be filled by Jeff Lemmer, the former vice president and CIO at Ford Motor Co.
Jeff Lemmer | Jeff Lemmer via LinkedIn
The Nominating Committee — comprising two MISO members and three MISO directors — worked with search firm Russell Reynolds to select candidates for interview.
MISO Director Phyllis Currie said while at Ford, Lemmer supervised the inclusion of EVs in production.
Otherwise, current directors Wise and Lurie will stand for election.
MISO members now have about a month to vote electronically on the new appointment and incumbents; candidates must earn a majority of member votes to be confirmed.
MISO and its board still must decide which directors it might retain for an extra term through a waiver that allows them to stand an additional three-year term beyond the three-term limit.
The board has said it has multiple directors who will hit their three-term limit beginning next year and it may use waivers to preserve institutional knowledge. (See “Waivers May be Necessary to Retain Directors Past Term Limits,” MISO Board of Directors Briefs: March 23, 2023.)
MISO’s board consists of nine independent directors and the RTO’s CEO. The independent directors are limited to three three-year terms, but its bylaws allow some board members to serve an additional term under certain circumstances.
Directors Currie and Mark Johnson were re-elected to their final terms that began in 2022. They will hit their three-term limit at the end of 2024. Todd Raba, H.B. “Trip” Doggett and Barbara Krumsiek also were re-elected late last year. Their final terms conclude at the end of 2025.
Finally, the board selected Raba, the current board chair, to continue leading the board in 2024. Raba said the MISO board will remain his only professional commitment.
“Basically, I’m all in,” he said.
MISO Pursues $400M Budget for 2024
MISO says it likely will spend nearly $400 million over 2024, continuing a trend of budget increases year-over-year.
MISO is proposing a $370 million 2024 operating budget, which contains a nearly 15% increase in base operating spending over 2023. It also is eyeing approximately $27.3 million in capital spending.
MISO likely will up its $0.44/MWh tariff rate for members to $0.47/MWh next year.
MISO CFO Melissa Brown said increases to the member rate remain below nationwide inflation trends.
Brown said MISO’s total increase for 2024 is 9.1%, higher than the estimated tariff rate increase of 7%. The extra percentage over the tariff rate is from revenues MISO receives from the studies it performs for its generator interconnection queue and fees it collects to evaluate competitive transmission project applicants.
MISO said much of the jump in base operating expenses boils down to hiring and retaining employees.
The RTO said it soon will add nine new employees specializing in system planning and five new staff members to concentrate on MISO’s ongoing market redefinition, or how MISO will adapt its market design for more complex operations.
MINNEAPOLIS — MISO officials last week said they probably could have held off their decision to call a summertime emergency in late August.
MISO declared its lone summertime emergency and instated maximum generation procedures Aug. 24. (See MISO Calls 1st Summertime Emergency amid Systemwide Heat Wave.) However, the 123-GW peak under the widespread heat dome wasn’t the 127-GW peak MISO anticipated that morning. It also didn’t amount to the grim possibility MISO warned about ahead of summer, where it could exhaust all of its emergency reserves.
MISO’s summer peak demand of 125 GW interestingly arrived Aug. 23, a day before MISO called the maximum generation event. Intense heat struck multiple major cities in MISO simultaneously Aug. 23-24.
During a Sept. 12 Markets Committee of the Board of Directors meeting, Executive Director of System Operations Jessica Lucas said on Aug. 24, MISO worked to de-commit previously signed-on resource as load outlooks improved during the day. Lucas said in hindsight, MISO could have waited longer to make resource commitments to make sure they were necessary.
MISO CEO John Bear said it’s important to judge control room operators on what they saw in the moment and not by perfect hindsight. Multiple MISO executives said load forecasting and unit commitment during extremes is difficult, especially when fuel supply issues, low wind and other environmental limits related to heat hinder resource performance.
“We walked into that day knowing we had a high load forecast,” Executive Director of Market Operations J.T. Smith said.
Smith said a more sophisticated forecast might better anticipate coming “cloud cover in Detroit” so operators aren’t forced to commit as many resources on the mornings of pervasive heat waves.
Lucas said it was the hottest summer — and resulted in the highest demand — in MISO South since its integration in 2013. Southern demand hit a new high of 35 GW on Aug. 23.
Heat map of departures from 30-year normal temperatures Aug. 23-24 | Midwestern Regional Climate Center
“This summer was marked by five major heat waves,” Lucas said.
Despite that, Lucas said MISO used its emergency procedures only once. She said average temperatures in MISO Midwest shook out about normal, while MISO South was above normal.
Independent Market Monitor David Patton said MISO’s forecast model overestimated load between 2-8 GW on the hottest days in July and August. He said the model may not be picking up voluntary actions of MISO market participants to reduce load and behind-the-meter solar generation that likely spikes as demand soars on hot days.
Patton warned MISO about creating “artificial surpluses” during hot days that mute real-time prices. He reminded MISO leadership that MISO has short-term reserves and often experiences a “wave of imports” from neighboring regions when its prices rise. He urged them to let MISO’s market dynamics do more of the lifting in a heat dome.
However, Patton lauded MISO operators for having the foresight to cancel resource commitments Aug. 24 when it became clear they would be unnecessary. He said the move saved MISO customers about $1.6 million, though some MISO suppliers were unhappy because they purchased gas in anticipation after being selected to generate.
“It’s much better that you do that instead of ride it out and have more resources than you need,” Patton said.
Patton urged MISO to hold out longer on resource commitment decisions and declaring emergencies. He said MISO shouldn’t allow its market “to work against us” in tight operating conditions. Committing so many resources that prices stay low at about $45/MWh might lead some resources to export their output, Patton said.
MISO Director Barbara Krumsiek asked if MISO would have enough transmission capability if “decisions were made differently” and MISO were more confident in imports. Patton assured her MISO is flush with import capability.
Patton also acknowledged that for control room operators, overseeing the situation in real time is much tougher than delivering after-the-fact analysis.
“I can sit here and say, ‘have faith in the markets,’ but when you’re an engineer sitting in the control room, that’s a hard thing to accept,” Patton said.
“Thank you! Thank you for saying that; I don’t think I’ve ever heard you say that,” MISO Director Phyllis Currie said, eliciting laughs from the audience.
MISO again prepared for near-record electricity demand and tight conditions this month as a lingering September heat wave settled on its Midwest region. It enacted a hot weather alert for its North and Central regions Sept. 3-5 when temperatures again exceeded 95 F in some parts of MISO Midwest. The grid operator handled those days without emergency procedures.
Executive Director of Market and Grid Strategy Zak Joundi said until recent years, MISO and members have been “fortunate” to preside over smooth operations and manage them with simpler market tools. However, he said a multitude of renewable resources and increasingly unstable weather is poised to further drive volatility and riskier operations.
“The world that we are operating is a lot more complex, so to maintain the reliability we’ve become accustomed to, we will need to adjust our markets and processes,” Joundi told board members.
Joundi said the weather years MISO has experienced recently are more indicative of what’s to come and should be assigned more weight in loss of load prediction modeling than other historic years.
Smith said MISO has a goal to set dynamic reserves, so the markets determine a greater share of the operations, rather than control room operators.
Smith said MISO is headed into a future where operators can’t feasibly consider all the “various inputs” to mitigate risk. He also said MISO is conducting “toes in the water” testing of machine learning in its markets to forecast risk.
VANCOUVER, British Columbia — Stakeholders got to enjoy sweeping views of Vancouver’s downtown and harbor from a top-floor conference room during WECC’s two-day annual member meeting, which on Thursday featured an election to fill the board’s two top spots. Following is some of what we heard.
WECC directors elected current board Vice Chair Ric Campbell to serve as the new chair. Campbell replaces Ian McKay, who finished his three-year term in the top role.
Campbell previously served as chair of the Utah Public Service Commission and director of the Utah Division of Public Utilities. He worked for Shell before joining state government.
Speaking of Campbell, McKay said, “I consider that we’ve been a great team together, and he’s taught me a lot as we’ve gone through the last few years. I’ve valued his guidance and sage advice.”
Campbell returned the compliments, saying McKay “served as chair during a very unprecedented time, because we had to deal with a pandemic and how we were going to operate as a board. He did a fantastic job with that. He’s a man of great integrity.”
The board also elected Director Jim Avery as vice chair. Avery previously worked for San Diego Gas & Electric, most recently as chief development officer.
Talent Competition
Branden Sudduth, WECC vice president of reliability planning and performance analysis, told the board that, while his staff was on track to complete certain transmission studies due later this year, staff turnover represented a “strain” on meeting deadlines.
“We do have new people in place to take over some of the studies that were left behind by my other employees, but that’s my only concern at this point,” Sudduth said.
CEO Melanie Frye added that WECC is struggling to retain staff because of the industry’s attention on transmission, in part because of recent funding from the federal government.
“There is a huge competition for talent in that space. I think it’s now a hot skill,” she said, noting that it added to the broader challenges in finding the right workforce over the next 15 years.
“In that area in particular we’re in an intense competition to attract and retain talent,” Frye said.
But Frye also noted WECC “is fortunate to have some very tenured employees” on staff. With employees now spread across almost 20 different states, WECC is trying to navigate the “new realities and expectations” among workers in the post-pandemic world, she said.
The RE recently brought all its staff together at its Salt Lake City headquarters for “WECC Week.”
“It was a combination of self-awareness training, relationship-building, employee recognition and discussion around the vision and mission of the organization so that we’re all aligned going forward,” Frye said.
More Robust Oversight
Staffing isn’t a problem for WECC’s Oversight department, according to Steve Noess, vice president of reliability and security oversight. Noess, who joined WECC from NERC in April 2022, said his staff has doubled over the past year.
In August, Noess said, Oversight “retooled” how it presents registered entity compliance metrics by providing a quarterly report to the board instead of just making a presentation. The new report is more “robust” with the inclusion of more metrics and will be posted to WECC’s website to make the information available to a wider set of stakeholders.
“We think this also serves this drive to be more transparent because it’s hopefully easier to find and to access and reach a broader audience,” he said.
Noess said his team has grown to include “good analysts and engineers and lawyers” to help develop “a more case management approach” to WECC enforcement responsibilities. The team recently reached an “inversion point,” where it is processing more enforcement cases than it is receiving per month, chipping away at a large backlog.
“We targeted 30% reduction in cases that are two years old and older [in] the last several years,” Noess said. “We’ve come close, but we’ve not quite been able to meet that metric, and I’m happy to say that I’m confident that this year, we’re on track to meet that. Our target was 20% by the end of the third quarter … and 30% by the end of this next quarter.”
Noess also noted that NERC last week proposed new rules that would require owners of smaller grid-connected inverter-based resources (IBRs) to register with the agency, follow its reliability standards and respond to its alerts. (See NERC Seeks Comment on IBR Registration Proposals.)
“We’ve taken a lot of a lot of actions to try to prepare for that already, and we anticipate that should easily add more than 100 new registrations over time,” he said.
WECC Oversight has reorganized its staff to create three different monitoring teams focusing on high-, medium- and low-risk entities, Noess said. Staff already have begun developing plans for the expected rule changes, creating outreach materials targeted at new registrants.
WECC won’t have the capacity to audit all the small entities, “but we definitely, from a holistic perspective, have an obligation to make sure that we are well aware of their capability to address risks,” Noess said.
He said WECC has encountered “two flavors” of questions and concerns from the new IBR registrants.
“One is entities that haven’t had any experience with WECC or reliability whatsoever. So that’s the new population of folks who probably haven’t thought of WECC at all … So we have a very specific kind of targeted way that we want to approach those to set them up for success,” Noess said.
The second flavor consists of existing registered entities that have other assets that will be newly swept into NERC’s administration.
“So, there’s a familiarity with requirements and standards and obligations, but they have additional assets that they’ll then have to register for this new registration. And I think they’re understandably asking about what timelines will look like,” Noess said. “And so, this is a case where we should stay close to that, because there’s a process in place once the registration changes to do the modifications to meet the standards.”
Policy Risk
“There is a push for more market development in the West, perhaps leading to an RTO, and that occupies a lot of the time in our [Committee on Regional Electric Power Cooperation-Western Interconnection Regional Advisory Body] meetings, so I like to make sure that we don’t lose sight of the reliability discussion and certainly appreciate WECC’s partnership on that,” Mary Throne, chair of both the Wyoming Public Service Commission and WIRAB, told the board.
Throne said one the most interesting parts of NERC’s 2023 ERO Reliability Risk Priorities Report, released last month, was the addition of public policy to the list of grid risks. (See ERO Adds Energy Policy to Risk Priorities List.) She cited EPA’s recent proposed new rules for reducing greenhouse gas emissions from power plants as an example of the need for better coordination among regulatory agencies.
“In the preamble to the EPA regs, EPA commented that it had coordinated with FERC, but there really wasn’t anything in the preamble to support that statement,” Throne said.
After acknowledging Wyoming’s role as the nation’s leading producer of coal and an exporter of electricity, Throne said the state “did not feel like the EPA really considered the reliability risk” of its proposed regulations. “I think I might even use the word ‘naïve,’” she said.
Director Richard Woodward asked Throne how WIRAB and WECC can address the issue of energy policy risk.
“I think a communication strategy that puts all of this in terms that people can understand, identifying the risks without creating hysteria,” Throne said. “I don’t want to see the reliability discussion being politicized too much, but just a pragmatic discussion with reason, facts. And I think it’s important that WECC remains … a neutral source of technical information, so that policy people have good advice.”
Transmission investments that could help “address reliability, congestion and cybersecurity concerns” in the nation’s electric grid are being held back by “regulatory tension” between the federal and state governments, according to a recently released report from Moody’s Investors Service.
The report, published on Monday, asserts that not only is massive transmission investment needed to keep pace with the growth of new wind and solar generation sources and aging infrastructure, but “opportunities abound” for developing transmission assets. However, in spite of support from decarbonization initiatives at various levels of government, the siting and permitting process represents a significant bottleneck for utilities with the experience and resources to carry out these projects.
North America’s grid is long overdue for an upgrade, Moody’s argues in the report, citing data from NERC showing an annual average of about 9,500 “momentary or sustained transmission outage events” between 2015 and 2021, a figure “more than double the annual average of the preceding five years.” The report attributed most of these outages to severe weather events, which have become “more frequent and severe” in recent years.
Transmission improvements could be extremely useful to help the grid absorb the impact of such events, Moody’s said, citing a report from consulting firm Grid Strategies studying the winter storm of February 2021. More interregional transmission capacity could have saved nearly $1 billion in impact — and kept the lights on for 200,000 homes — for each gigawatt added, the report said.
Transmission improvements also could help with high congestion costs, which Moody’s said “have emerged as a major problem” in recent years; the firm cited data from the U.S. Energy Department’s draft National Transmission Needs Study indicating congestion costs in the Mid-Atlantic region surged from $529 million in 2020 to $953 million the following year. Additional investment is needed to bring the transmission system in line with mandatory cybersecurity requirements adopted in response to mounting threats from malicious online actors around the world.
FERC has sought to encourage transmission investments, the report said, noting “limited revenue risk [and] counterparty risk” on the part of transmission owners thanks to the commission’s cost recovery framework and transparent process for setting return on equity for transmission assets. The report considered revenue collected under FERC’s regulatory framework to be overall “more stable and predictable than” under state regulations and called the commission’s approach “favorable to transmission owners.”
While FERC has tried to cultivate a positive environment for TOs — particularly large utilities such as Duke Energy and Exelon, which Moody’s called “best positioned to take advantage of” these opportunities — challenges remain in the approval process. The report noted that authority over transmission siting and permitting largely remains in the hands of state and local governments, which “can be slow and impede the pace of transmission development.”
This regulatory dilemma is illustrated by the slowing pace of transmission capacity upgrades, Moody’s said, pointing to data from FERC that shows an average of around 600 miles of high-voltage transmission lines completed annually in the U.S. since 2017, far below the 2,000 average annual miles completed between 2012 and 2016. The slow pace of construction, in spite of steadily rising transmission investments since 2017, has resulted in long lead times for such projects, with Moody’s estimating up to 10 years is needed from preliminary planning to end of construction.
Moody’s said efforts are underway in the federal government to help with the permitting issue, citing Sen. Joe Manchin’s (D-W.Va.) Building American Energy Security Act as an example of the kind of work that could help get transmission projects moving. Among other reforms, the bill would set maximum timelines for permitting reviews and set a statute of limitations for court challenges to projects.
“Measures like these at the federal level, as well as improved coordinated planning at the state and regional level, could facilitate the nation’s transmission development and help meet long-term greenhouse gas emission goals,” Moody’s said.
Without new retail rate designs, full electrification will cause higher overall energy bills for consumers in some regions of the country, the American Council for an Energy Efficient Economy said in a report Thursday.
The success of electrification efforts, which are a major part of addressing climate change, will depend on pairing them with policies that improve equity and lower energy burdens for consumers, according to “Equity and Electrification-Driven Rate Policy Options.”
“When electric rates are high, fuel switching can increase the overall energy bill for participating customers,” the paper said. “In those circumstances, utilities should find ways to lower the operating costs of electrified appliances, especially for LMI [low- and moderate-income] households.”
Electrification involves switching major appliances that use natural gas or heating oil such as furnaces and water heaters and replacing them with devices that run on electricity such as heat pumps.
Earlier research from ACEEE has found that a quarter of U.S. households already have a high energy burden, meaning they spend more than 6% of their income on utility bills. Those bills have been going up lately because of extreme weather and the war in Ukraine.
Heat pumps are more efficient than traditional furnaces that burn fossil fuels, but in some states, electric prices are high enough to negate those savings.
“California and New England are two areas in which electricity rates are significantly above average; in the rest of the United States, electrification will often produce lower total energy bills,” ACEEE said.
Fuel switching could decrease rates, especially if the higher demand happens during times when the grid is not stressed. Other trends, such as the growing use of distributed energy resources, will reduce peak demand, also helping lower rates.
But some regions, including colder areas where electrified heating loads are going to be high, could see higher energy burdens on LMI consumers, the report said.
“It is thus critical to add new electricity demand efficiently; energy burdens could be lowered if electricity rate designs fairly allocate costs and send adequate price signals to inform and give customers opportunities to reduce system costs by changing consumption patterns at high-cost hours,” the report said.
Without the policies and rate design, the higher prices in some regions could deter consumers from switching to electricity. The paper evaluated several rate designs but said it was not attempting to provide a comprehensive list of potential solutions.
One option is percentage of income payment plans (PIPPs), which lower burdens for low-income consumers by capping utility bill payments at a set percentage of a participant’s income. They keep bills affordable regardless of increases in utility rates, so they can be a complimentary policy to any other rate designs, the paper said.
PIPPs should be coupled with longer-term investments in efficiency and weatherization for low-income homes, which would lower their demand while improving the health and safety conditions of their homes.
Another option is rate designs that enable heating electrification. Rates that offer incentives for customers to change their behavior such as time-varying rates, and ones that are tailored to the operational characteristics of major appliances like heat pumps can cut the impact of fuel switching when areas face higher rates than the national average.
Heat pumps are used most in off-peak hours, so they could benefit from time-varying rates, and they tend to have high load factors most of the time, making their electricity usage more constant and less peaky, so demand-based rights might favor them, all else being equal.
Rate Design Alternatives
ACEEE borrowed some rate designs from an Energy Systems Integration Group report, which offered three alternatives that could lower bills when consumers electrify in areas with high power prices.
One, called “Rate II” (Rate I refers to the standard rate), would have lower volumetric charges to offset higher usage with a much higher customer charge to make up for utility costs.
Rate III would have a somewhat higher customer charge and seasonal volumetric charges, as well as peak and off-peak rates. The rates would be slightly higher than the control in the summer months, but favor non-summer off-peak electricity usage while utilities recover their costs from demand during summer peaks.
Rate IV would have a higher customer charge; seasonal supply charges similar to Rate III’s, but with a less drastic cost difference; and delivery charges that are only 10% of Rate I’s charges. It would add seasonal charges for peak and off-peak periods per kilowatt of demand, with lower charges during the summer.
The introduction of a demand charge, based on consumers’ highest monthly use, could be controversial because that use might not stress the grid at all if it is not aligned with the system peak demand.
Another option to keep rates reasonable while encouraging electrification is to implement an income-based fixed charge. California is considering the approach after Gov. Gavin Newsom (D) last year signed Assembly Bill 205, which requires the state’s Public Utilities Commission to consider a rate with at least three income levels and implement the change by July 2024 while ensuring the change does not hinder electrification and greenhouse gas reductions generally. Historically, California has had very high volumetric rates that include charges for things that do not directly relate to delivering energy, such as wildfire mitigation.
The CPUC has been at work implementing the law, with the state’s three major investor-owned utilities submitting a joint plan this April, as did other stakeholders. The average fixed monthly charge for the utilities varies: It would be $53 for Pacific Gas & Electric, $74 for San Diego Gas & Electric and $49 for Southern California Edison, while other parties proposed lower fixed rates.
“Some stakeholders have asserted that higher fixed charges give customers less control over their bills and may be less equitable for customers who do not consume a lot of energy,” ACEEE said. “There are also debates over the best way to recover utility system costs through fixed charges.”
Newly minted ERCOT COO Woody Rickerson told Texas regulators Thursday that last week’s Level 2 energy emergency alert was a necessary “balancing act” to protect ERCOT’s system equipment and to prevent load shed.
“I think the operations team did a really good job in very unusual circumstances,” Rickerson said in reviewing staff’s report of the Sept. 6 event during the Public Utility Commission’s open meeting. “It’s not something you see every day, but they were able to balance the two things and maintain reliability.”
Rickerson told commissioners several factors contributed to low power reserves that led to a drop in system frequency from 60.1 Hz to 59.9, the most significant being an “unusually” hot summer that has resulted in “abnormally” high demand. (See ERCOT Voltage Drop Leads to EEA Level 2.)
He said declaring a Level 2 EEA that bypassed Level 1 allowed ERCOT to deploy its responsive reserve service, or spinning reserve, and to interrupt power to some large industrial users. The alert was issued at 7:25 p.m. as solar power began ramping down in the evening after the ISO had already called on most of the ancillary services it relies upon during tight operating conditions.
The grid operator normally calls a Level 2 alert when its physical responsive capability (PRC) is less than 1,750 MW and not expected to recover within 30 minutes. Rickerson said the PRC had dropped to 2,104 MW at the time of the frequency decay.
“We suspect that the PRC number was not accurate,” he said. “We’re looking for why … there were several possible reasons.”
Rickerson, who was promoted to COO two weeks ago, said staff are conducting a more detailed analysis that will be shared with the PUC.
“We had relatively low wind that day, we had a congestion problem that caused us to curtail some generation, and all this occurred right in the middle of a solar down-ramp … so all these things were moving at the same time,” he said.
Thermal outages were just over 6 GW — “in line” with the summer’s forced outages, according to ERCOT’s report — during Sept. 6’s late afternoon and early evening hours. However, much-needed power from South Texas wind farms was restricted by an overloaded 345-kV transmission south of San Antonio. ERCOT was forced to order a manual curtailment of 1,590 MW of generation from the South to avoid “significant consequences” to grid reliability.
ERCOT’s board recently approved a transmission project it said would help address congestion in South Texas. The PUC has not yet considered the project for approval. (See “San Antonio Tx Projected OK’d,” ERCOT Board of Directors Briefs: Aug. 30-31, 2023.)
Commissioner Jimmy Glotfelty asked whether the transmission line was dynamically rated and whether it was rated accurately. Rickerson responded that ERCOT relies on transmission providers, who make their own line ratings.
“The new San Antonio line will help, but the biggest thing that would help would be generation north of San Antonio. That’s the remedy,” Rickerson said.
Glotfelty also asked Rickerson to provide more information on thermal outages in North Texas, saying, “There’s a lot more to look under the hood here.”
Rickerson promised ERCOT’s next report will “beef up” the generation limitations.
“We always look at these types of operational incidents as opportunities, places to sharpen our tools and improve our procedures,” he said. “There are some things we can change and procedures to make these things more rote for the operators. We are going through a phase where our grid is not the grid we had in the past and we’re going to have new challenges. Our procedures and processes will need constant tune-ups to keep up.”
PUC Files Proposed Rulemakings
The commission approved for publication a rulemaking that creates the committee overseeing the Texas Energy Fund loan program created during the 2023 legislative session (55407).
The rulemaking is a result of Senate Bill 2627, which sets aside billions for new dispatchable generation, backup power and upgrades in ERCOT and the non-ERCOT portions of Texas. Non-ERCOT utilities can use these funds to modernize or weatherize facilities and for resiliency improvements. Energy storage facilities are not eligible.
SB2627 requires the PUC to evaluate loan applications based on service quality, operational efficiency, a history of in-state operations, and other factors. The loans will have a 3% interest rate and 20-year terms.
The Texas Backup Power Package Advisory Committee, comprised of three to nine members appointed by the PUC’s executive director, will be responsible to recommend the grants’ and loans’ criteria to the commission.
Commission staff is holding a workshop on the loan program Thursday.
Texas voters will have an opportunity to approve or reject the program during the Nov. 7 statewide elections.
The PUC also approved for publication rulemakings that:
Set up an emergency pricing program activated when ERCOT’s average system-wide energy price has been at the $5,000/MWh high system-wide offer cap for 12 hours within a rolling 24-hour period. The program’s emergency offer cap will be set the low system-wide offer cap of $2,000/MWh (54585).
Create annual resiliency plans to be filed with the PUC by transmission and distribution service providers (55250).
Direct transmission and distribution utilities to perform circuit-segmentation studies and determine whether load shed can be managed more effectively (55182).
The proposals are published on the PUC’s website and in the Texas Register and are unable to be adopted as final rules for 30 days. A public comment period is held during that time.
A year after New York ordered seven utilities to plan a series of thermal energy network pilot projects, none of the proposals is ready for regulatory consideration.
But progress is being made, and the Public Service Commission on Thursday issued guidance to help further develop the plans to the point at which construction can be authorized.
The Utility Thermal Energy Network initiative is a significant undertaking — one commissioner likened it to creating a new utility. A 2022 state law mandated that UTEN pilot projects be developed as a means of reducing emissions from New York buildings, which are responsible for 32% of in-state greenhouse gas production, the most of any source.
Some New Yorkers already have partly or completely electrified their homes, but many do not have this option, as they lack money or live in a multiunit dwelling. UTENs are seen as a way to reach them and contribute to the emissions reduction goals of the state’s landmark Climate Leadership and Community Protection Act.
The PSC formally set the process in motion at its September 2022 meeting, opening Case No. 22-M-0429.
The 14 proposals submitted by the utilities would cost an estimated $362 million to $435 million.
Who will pay for this and over what period is one of the big questions. There also are technical challenges, particularly in densely built urban areas; a dearth of standards and performance metrics; the sticky question of whether fossil fuels can be burned to generate the heat UTENs will share; a state law complicating efforts to drill more than 500 feet deep for ground-source heat pumps; and a shortage of workers skilled to do some of the work.
All of this points to the value of pilot projects and the need to further refine them.
In September 2022, there was some grumbling among the commissioners about the details of the state law driving the case.
On Thursday, one of the commissioners called the legislation “clunky” and said its timeframes were not workable. Projects were to be approved within six months of the legislation taking effect.
But the process drew support from commissioners, even as they asked questions about some individual details or raised yellow flags about others.
That said, the pilots clearly are not ready for prime time.
The order the PSC adopted Thursday described the utilities’ proposals as “a reasonable first step” but insufficiently detailed. It sets out a five-stage planning, review, operation and assessment process to reduce risk and increase speed while preserving the public interest.
The Department of Public Service staff or the PSC itself will review each stage of each project and must sign off before it can progress to the next stage. At any point, the PSC can terminate a project or require it to be modified.
The order presents a strong bias against any use of fossil fuel combustion in the proposed pilot systems and notes the opposition of environmental advocates in submitted comments. But it stops short of banning fossil fuels, saying the PSC might consider their use to ensure reliability and hold down costs.
Estimated costs of individual proposals range in the tens of millions of dollars.
The most expensive initially was an ambitious Con Edison plan to recycle waste heat from a data center to provide heating, cooling and domestic hot water for the New York City Housing Authority’s Fulton Homes complex in Manhattan. Renovation plans subsequently announced by NYCHA knocked the price tag down from $67.9 million to $62.4 million.
KEDNY proposed a $67.7 million project with NYCHA that would link apartment buildings, commercial buildings and a community center in Brooklyn.
Niagara Mohawk proposes to draw thermal energy from the effluent of the Syracuse metro area wastewater treatment plant to serve a new mixed-use development at a cost of up to $66.8 million.
At the other end of the scale, RG&E proposed a $13.2 million system to serve 22 buildings in a disadvantaged Rochester neighborhood.
The order directs DPS staff to convene a technical conference within 30 days and orders the utilities to submit final proposals by Dec. 15. Proposals that are judged compliant will be done with Stage 1 at that point and can progress to Stage 2 of the review.
The process is progressing slowly, and the small freshman class could get even smaller. But PSC Chair Rory Christian called the effort one of the next big steps in moving toward the state’s clean energy goals.
“We’re not just creating a new system, we’re re-imagining energy use in New York state,” he said.
