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November 8, 2024

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ACEEE Paper Says Rate Design Can Avoid Higher Bills from Electrification

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.”

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ERCOT Walks ‘Balancing Act’ During Recent EEA

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.

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NY Utility Thermal Energy Network Pilot Program Simmers

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.

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CAISO May Scrap Policy Catalog; Start from Scratch

CAISO is looking at scrapping a catalog of about 60 proposed policies, which include many stakeholder suggestions, saying the document has become “unwieldy” and it might be better to start over from scratch.

The ISO’s so-called “policy catalog” lists current, planned or potential policy initiatives aimed at enhancing CAISO markets. The catalog is used in crafting CAISO’s policy roadmap, which details what CAISO intends to take on over the next three years.

The policy catalog and roadmap were discussed Tuesday during a meeting of the Western Energy Imbalance Market (WEIM) Regional Issues Forum (RIF).

CAISO updates the policy catalog twice a year; stakeholders can submit suggestions at any time. With about 60 policy initiatives, the latest catalog, released in March, “has proven a little bit unwieldy,” said Becky Robinson, CAISO’s principal economist and director of market strategy and governance.

“There’s often more in the catalog than there is bandwidth to take on,” Robinson said.

CAISO is asking the RIF for ideas to make the catalog “more meaningful and relevant,” she said.

One option would be to consolidate the existing catalog, with stakeholders grouping and prioritizing the initiatives. The second option would be to start over with a “clean slate.” Stakeholders could submit new proposals or re-submit earlier suggestions.

In going from the catalog to the policy roadmap, CAISO would like to coordinate the plan with its strategic goals, resources and other planning processes.

RIF’s Expanded Role

Discussion of the policy catalog and roadmap comes as the RIF is expanding its role at CAISO.

The RIF is an independent, self-governing body that includes stakeholders from various sectors across the Western Interconnection. It provides feedback on WEIM-related issues.

RIF’s enhanced role was mentioned in January, when the WEIM Governing Body and ISO Board of Governors approved changes recommended in the WEIM Governance Review Committee’s Phase Three (EDAM) Final Proposal. (See CAISO Approves Day-ahead Market for Western EIM.)

In its proposal, the committee “encouraged the RIF to continue its transition from a role that was largely educational at its outset to one that is capable of providing advisory input as well.” The committee urged CAISO staff to support the transition.

Josh Walter, who chairs the RIF, said the forum’s evolution “provides the opportunity to have a more meaningful impact on the WEIM’s Governing Body and their decision-making.”

“This new role allows the RIF to discuss and opine on active stakeholder initiatives, provide direct input to the Governing Body on decisional issues independent of CAISO staff and serves as an important resource in market development and enhancement decisions,” Walter told RTO Insider.

During Tuesday’s meeting, WEIM Governing Body member Anita Decker said she’s looking forward to watching “this evolution of the RIF.”

“I really want to reinforce that the RIF really is part of the WEIM governance,” Decker said. “We want to hear from you.”

Noting that the Governing Body already is “highly supportive” of the RIF, Meg McNaul, the forum’s vice chair, pointed to two immediate goals for the group. One goal is to help stakeholders communicate their policy positions to CAISO through the existing process.

The second goal is a new endeavor for the RIF. The group will organize a roundtable discussion on CAISO’s policy catalog and roadmap so stakeholders can weigh in on prioritization of initiatives. The first roundtable is expected to take place early next year.

The RIF also has a longer-term role, McNaul told RTO Insider.

“As the EIM evolves, the RIF can play an important role in contributing to the regional dialogue on topics of importance to the stakeholder community, as shown by this week’s in-depth discussion of price formation topics,” she said.

What’s in the Catalog

Proposals in CAISO’s policy catalog are those that would require a stakeholder process and typically result in ISO tariff changes.

The latest version of the catalog lists, “Initiatives Currently Underway and Planned,” which include enhancements to resource adequacy, day-ahead markets, price formation and energy storage modeling.

Among its 57 “discretionary initiatives,” the catalog lists pumped storage with multiple pumping levels, balancing-area-authority islanding of internal regions, and a potential WEIM-wide transmission rate.

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More Federal Outreach Needed to Support Clean Energy Development on Tribal Land

LAS VEGAS — The government and developers need innovative capital approaches and a commitment to building deep relationships to unlock the potential of clean energy development on tribal lands, experts said in a panel at this week’s RE+ conference held at the Venetian Expo and Caesars Forum.

However, the federal government is behind on outreach to tribal leaders about how to address financing and skill gaps, RTO Insider was told.

Tribal land accounts for 5.8% of the U.S. landmass but 6.5% of utility scale renewable energy generation potential, said Margaret Tallmadge, senior development manager at Navajo Power, a majority native-owned utility scale solar developer working with tribal nations and communities across the U.S.

Barriers to developing this “outsized potential” include “access to capital; limited opportunities to build technical capacity and internal capacity within tribes to pursue their own projects; and minimal knowledge of tribal sovereignty, federal Indian law and regulatory complexities in Indian country,” Tallmadge said.

Some of those barriers are exacerbated by the federal government, which is lagging in its trust responsibility to tribes, Paul Dearhouse, a senior consultant to the Tribal Energy Loan Guarantee Program at the U.S. Department of Energy’s Loan Programs Office (LPO), told RTO Insider. “We’re a few years behind in actually sending out a ‘Dear Tribal Leader’ letter, saying, ‘Here’s a program designed to finance tribal energy projects. What’s your thoughts? What’s your feedback? What are the best ways to do that?’ We haven’t done that to date.”

Tribal input is vital to develop appropriate ways of dealing with the unique challenges tribes may face, where they have land ideal for renewables development but little access to capital and often no experience working with developers whose incentives and financing structures are designed with short-term ownership rather than long-term land stewardship in mind.

Developers working with tribes also need to be innovative, balancing the need to craft project structures that enable the tribe to participate without a large capital outlay with financiers’ desire to have traditional PPAs, said Kevin Blaser, managing director of energy systems at Bakinaw Federal Contracting.

One example of where limited access to capital creates issues is with interconnection queues. While a pain point for most utility-scale development, they create an even larger challenge for projects on tribal lands, Dearhouse said. FERC orders and rules implemented at the RTO level to fix aging infrastructure can result in escalating fees to maintain a project’s position in the interconnection queue. Most tribes won’t have the large amount of capital needed to maintain their queue position, creating “a huge barrier,” but also an opportunity.

“This is a new frontier to make our LPO offerings better, to do a proper rulemaking for our program and to really listen to tribes that are in the queues across the nation, to ask: ‘Are there better ways that the Loan Programs Office could design the program to help address that specific gap?’” he said.

Developers Must Invest in Relationships

While funding mechanisms are important, developers seeking to build clean energy resources on tribal lands must start with building a relationship, Blaser said. “If you’re going to work or partner with tribes — and there’s a ton of benefits to doing that — you really have to take the time to learn their culture, learn what they’re trying to do, and understand what their strategy is, even if their strategy is ‘we don’t know.’”

There is no single right way of working with tribes, Blaser said: “Because there are 576 or so federally recognized tribes, there are 576 different ways of doing it. There are all those bodies of laws; every culture is different.”

A long-term perspective and partner mentality is essential as developers work with tribes, said Dave Harper, head of tribal engagement at the Alliance for Tribal Clean Energy. “You don’t want to be an outsider; you want to come in as a partner mentality. What does being a partner mean? It means that we’re going to be fair with each other, we’re going to be respectful. We’re going to be able to have dialogue and to sit down.”

Tribes need to use those partnerships when they have limited internal knowledge or bandwidth, Dearhouse said. “For utility-scale projects, many times a tribe has a part-time environmental coordinator, so they really have to bring in trusted partners like the fellow panelists here that can really help fill in that piece.”

A relationship with the LPO also is important for tribes seeking to deploy renewable projects on their lands. “We are long-term patient capital. The path that we walk to get a tribal applicant in the door through to funding can be long, months to even a couple of years, because of the steps that we take, but for a really responsive applicant, it can be expedited two months, but not every tribe’s ready.”

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MISO: Expect More Expensive Annual Transmission Packages

MINNEAPOLIS — MISO’s lead planners on Tuesday told their Board of Directors that more expensive annual Transmission Expansion Plans (MTEPs) will become the norm, saying MTEP 23’s $9.4 billion package is a sign of future scattershot load growth in the footprint.

MTEP 23 contains 578 projects at $9.4 billion, more than doubling MTEP 22’s investment. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.)

Senior Director of Transmission Planning Laura Rauch acknowledged that MTEP 23 is the largest MTEP cycle in MISO’s history that doesn’t include long-range transmission plan (LRTP) projects or Multi-Value Projects.

During a meeting of the MISO Board of Directors’ System Planning Committee on Sept. 12, Rauch said most MTEP 23 projects are needed for reliability amid “localized load growth rather than bulk increases to load.” She characterized the bump in load as “spot load growth.”

MISO Director Nancy Lange asked whether the RTO anticipates “these lumpy, large investments” in MTEP cycles into the future.

Rauch said MISO members have indicated large industrial and commercial load additions will persist. She said MISO planners are expecting more economic growth in the footprint and sizable demand from new data centers and green hydrogen facilities.

MISO Director Barbara Krumsiek asked if funds from the Inflation Reduction Act are behind the jump in transmission needs.

“It’s such a substantial leap. Has it been long in the making or recent?” she asked.

Rauch said the upswing in spending appears to be occurring independent of government funding.

MISO Director Mark Johnson said despite the billion-dollar costs of two MTEP 23 projects, the projects differ from LRTP projects because they’re meant to be in service within three years, not the approximate decade allotted for the long-term planning.

Rauch said MISO remains “firmly committed” to recommending LRTP projects in MISO South despite the large amount of MTEP 23 investment in the region. She said the MTEP 23 projects don’t “preclude” separate, future solutions for long-term transmission needs in the South.

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MISO: Reliability Risk Upped by 49 GW in Approved but Unbuilt Generation

MINNEAPOLIS — MISO’s quarterly Board Week explored the reasons behind MISO’s growing number of generation projects that have the stamp of approval to connect to the system but remain unbuilt.

49 GW Greenlit but Unfinished

MISO said many of its new resources that have struck generator interconnection agreements are beset by delays and cancellations, “mostly driven by build-related issues.” It said those lost and paused resources increase risk for a “future capacity or reliability attributes shortfall.”

By MISO’s count, 49 GW approved through its interconnection queue are awaiting construction, with an average delay to commercial operations of more than 650 days.

Scott Wright, MISO | © RTO Insider LLC

“That’s nearly 50 GW. This is pretty sizable. … This is a very pressing situation. We need to get iron in the ground. That’s what needs to happen,” Executive Director of Resource Planning Scott Wright said during a Sept. 12 System Planning Committee meeting of the Board of Directors. He added that MISO is negotiating new GIAs all the time and the postponed gigawatt amount is certain to rise by year’s end.

Wright said MISO’s plan to place an annual megawatt limit on project proposals, collect higher entry fees, enact escalating penalty charges and require developers to prove they have secured land will make for more certain generation projects that ultimately will mitigate long-term risk. (See MISO Sticks with MW Caps, Higher Fees to Pare Down Queue Requests.)

“With all the capital flowing in, it’s not hard to imagine a queue that’s 500 GW,” Wright said. He added MISO needs to be more selective about the projects it allows in to produce good network upgrade studies and approve projects that are a sure thing.

But Wright said incoming, mostly renewable generation likely won’t fare well in terms of accredited capacity. He also said EPA’s proposed carbon rule stands to pull the plug on “tens and tens” of gigawatts.

MISO has said EPA’s proposed emissions rule for fossil plants would supercharge retirements so they outpace the commercialization of new technologies like green hydrogen and carbon capture. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.)

“Thank you so much for that very calming discussion,” MISO Director Mark Johnson joked.

MISO members at a Sept. 13 meeting of MISO’s Advisory Committee were light on answers as to how to get the 49 GW online sooner.

“These are not speculative projects. We ran into the pandemic and supply chain issues,” Invenergy’s Arash Ghodsian said.

Wisconsin Public Service Commissioner Tyler Huebner seconded that view. He said developers ran headlong into the pandemic, and then a federal investigation into solar panels hampered new capacity.

“It has been a compounding of issues on the solar side in particular,” Huebner said.

“It’s incredibly challenging to build out new infrastructure, new power plants,” Invenergy’s Eric Thoms added.

North Dakota Public Service Commissioner Julie Fedorchak suggested MISO and members simply allow more time to develop generation. She said special interest groups and landowners are getting more vocal in proceedings at state commissions and commissioners are having to extend timelines to hear them out.

“I think we need to just bake in more time. Not to give up, but just be realistic,” she said.

Ameren’s Jeff Dodd seconded that longer timelines probably are the new reality. He said there’s more “fatigue” these days among landowners who are asked to host infrastructure.

Clean Grid Alliance’s Beth Soholt asked MISO for more data behind the delays on new build capacity, including locations and whether local communities are opposing projects. However, Soholt said transmission construction must catch up to meet the needs of generation developers.

“We have a transmission problem — we’re working on it — but we did have a 10-year lag between the multivalue projects and [the first long-range transmission portfolio]. So, we have a backlog in some of the generation projects that want to connect,” she said.

Solholt said it’s important the nearly $2 billion Joint Targeted Interconnection Queue (JTIQ) portfolio of 345-kV lines is built to ease the queue backlog. She also said MISO’s Environmental Sector prefers members not simply leave fossil generation operating on the system for “longer and longer.”

WEC Energy Group’s Chris Plante said though MISO can complete scores of generator interconnection agreements, some projects still are “conditional until the transmission reinforcements are there.”

“I want to make sure we have a heightened sense of urgency,” MISO CEO John Bear said a day later at the MISO board meeting. He said MISO is up against a wave of generation retirements and similarly tapering reserves at PJM and SPP, which means MISO won’t be able to rely on imported power from neighbors in the future.

“We’re going to have to take care of ourselves,” he said.

Bear said while MISO can export on windy days, it often runs into trouble when wind drops off. He advocated for “dispatchable, long-duration assets” on the system. He said though MISO remains fuel neutral, “we’re big fans of reliability.”

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NERC Seeks Comment on IBR Registration Proposals

NERC is seeking comment from industry stakeholders on proposed changes to the organization’s Rules of Procedure (ROP) intended to meet FERC’s order from last year to identify and register the owners of grid-connected inverter-based resources (IBRs).

The ERO posted the proposal for a 45-day comment period Wednesday, citing the commission’s November order directing NERC to describe its plans for registering IBRs (RD22-4). (See FERC Addresses IBRs in Multiple Orders.) NERC submitted its registration strategy in February, and FERC approved the work plan in May. (See FERC Approves NERC’s IBR Work Plan.)

FERC’s order was motivated by concerns over the ongoing transition from conventional generation resources to IBRs like wind and solar facilities. Currently, the ERO’s rules defining which resources must register with NERC, follow its reliability standards and respond to its alerts do not apply to many smaller IBRs. Updating the ROP is the first step in NERC’s work plan. The next stages are identifying candidates for registration, to be done by May 2025, and carrying out the registration process, to be finished by May 2026.

The changes before industry will apply to Appendices 2 (Definitions), 5A (Organization registration and certification) and 5B (Compliance registry criteria) of the ROP.

In Appendix 2, NERC proposes to add two new definitions — generator owner-IBR (GO-IBR) and generator operator-IBR (GOP-IBR) — to the registry criteria, while also updating the definition of “reserve sharing group” (RSG) to be consistent with that proposed by Project 2022-01 (Reporting ACE definition and associated terms).

The addition of GOP-IBR represents a change from the work plan NERC submitted in March, which included only GO-IBR. NERC staff said at the time that it felt GO-IBR could be used in reference to both owners and operators of IBRs, but at FERC’s prodding, it pledged to consider using additional terms.

Proposed changes to Appendix 5A include adding the GO-IBR, GOP-IBR and distribution provider-underfrequency load shedding (DP-UFLS or UFLS-DP) functions to the registration functions list. The DP-UFLS term indicates entities that own, control or operate UFLS-protection systems needed to implement grid protection programs but do not meet any of the other criteria for registering as distribution providers. NERC also proposes to clarify the Compliance Committee’s process for reviewing registration appeals.

The revisions to Appendix 5B would specify that entities registered as GO-IBRs or GOP-IBRs must own and maintain, or operate, inverter-based generation resources with an aggregate nameplate capacity of at least 20 MVA, which deliver their capacity to a common point of connection at a voltage at least 60 kV. Additional revisions will further clarify which entities should be considered candidates for registration, remove dated information and add the RSG function to ensure consistency with Appendix 2 and Project 2022-01.

The ERO will accept comments on the proposed changes through Oct. 30. After the comment period is over, NERC plans to submit the changes for approval at the Board of Trustees’ next meeting in December and then to FERC for final approval.

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Efficiency and Reliability are Debated at House Energy Hearing

The partisan divide on energy efficiency and other policies was on display at a hearing Wednesday of the House Energy and Commerce’s Energy, Climate and Grid Subcommittee.

The panel examined a series of bills from Republicans, including the Guaranteeing Reliable Infrastructure Development (GRID) Act from Subcommittee Chair Jeff Duncan (R-S.C.), which would require any federal agency implementing a rule that affects reliability to bring it before FERC. Other legislation would delay a DOE proposal to implement new efficiency standards for distribution transformers for five years and limit the department’s ability to issue new efficiency standards across the board.

Duncan cited the recent NERC report that listed energy policy as threatening reliability as a reason to support his bill requiring more oversight by FERC. (See ERO Adds Energy Policy to Risk Priorities List.)

“There’s a looming resource adequacy crisis. We all need to take this morning seriously and do more to ensure reliability and affordability of the energy system,” Duncan said. “FERC has allowed the distortion of market incentives such as state and federal subsidies aimed at promoting the deployment of renewables to interfere with electricity price formation. This has contributed to the early retirement of reliable generation assets like nuclear and natural gas.”

EPA’s proposed power plant rule would add to the problem as it would limit the amount of time fossil plants can operate, he added.

The GRID Act is a broad proposal that would cover many potential government actions, making it hard to determine just how much work it would give to FERC, said David Ortiz, director of the commission’s Office of Electric Reliability.

“As a general matter, FERC and the ERO, NERC, have the necessary expertise to understand and comment on the potential effect of proposed regulatory actions on the reliability of the bulk power system,” Ortiz said. “However, fulfilling the goal of the GRID Act would require detailed, interconnection-wide modeling and analysis beyond FERC’s capability.”

FERC might not have access to the data needed to perform the studies required under the proposed bill, he added. Other organizations could do the analysis, with Ortiz pointing to DOE’s national laboratories.

Ranking Member Diana DeGette (D-Colo.) said everyone in the room agreed reliability is important and will be even more so in a warming world where summer power outages threaten lives.

“It’s clear, a reliable source of electricity is paramount to our nation’s health and well-being,” DeGette said. “I think that one of the ways to ensure we have reliable electricity is through energy efficiency.”

Increasing energy efficiency helps to stretch out the current energy supply to serve more consumers reliably, while also saving them money.

The Biden Administration has been implementing efficiency standards at DOE that would save up to $570 billion after DOE under President Trump missed dozens of deadlines under the law to either issue a standard or explain why none was needed. DeGette argued the bills before the committee do not deal with reliability.

“Instead, what I see is bills that in the name of reliability, would gut energy efficiency standards that are saving Americans money, and that are cutting down on our energy use,” she added.

Mid-Carolina Electric Cooperative CEO Bob Pauling in testimony came out against a proposed DOE standard that would require the industry to stop using standard “grain oriented electric steel” distribution transformers at a time when supply chains for the vital infrastructure already are stressed.

“The utility industry needs manufacturers to be 100% focused on increasing output, not adapting to new, government mandated efficiency requirements that are not technologically feasible nor economically justified,” he said in written testimony.

DOE Assistant Secretary for Electricity Gene Rodrigues noted that the transformer standard still is just a proposal, which the agency was required to take up under a consent decree, and said the department takes the issue of electric reliability and the need for more transformers seriously.

“That is why DOE expressly asked stakeholders for comment on timelines required for compliance with the proposed standard, as well as comments on the availability of key components,” Rodrigues said.

The efficiency standard is just part of DOE’s work on transformers. It also is working with the rest of the government and other stakeholders to help bolster the domestic supply chain for key grid components for decades to come, he added.

“We have provided national projections of the long-term demand growth for distribution transformers to provide America’s manufacturers with investment certainty that will help them to expand capacity,” Rodrigues said. “We have connected manufacturers with suppliers of difficult-to-source grid components. We have utilized legislation passed by this Congress to provide funds for distribution transformers, such as the $10 million in transformer rebates and $10 billion in 48C tax credits.”

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NYPSC Continues Legal Battle Over NYISO’s 17-year Amortization

The New York Public Service Commission on Tuesday petitioned a federal court again to reconsider FERC’s approval of NYISO’s proposed change to the timeline for demand curves in its installed capacity market auctions (ER21-502).

This is the third time the PSC has asked the D.C. Circuit Court of Appeals to rule on NYISO’s proposal to implement a 17-year amortization period when calculating the net annual cost of a hypothetical peaking power plant in its capacity markets and comes after FERC declined the PSC’s request for a rehearing on Monday. (See NYPSC Seeks FERC Rehearing on NYISO’s 17-Year Amortization.)

NYISO is mandated to update the assumed operational lifetime of a hypothetical fossil fuel plant in its capacity market auctions every four years, but, in response to aggressive state climate and energy legislation, the ISO proposed reducing that assumed lifetime from 20 to 17 years.

The ISO argued the 2019 Climate Leadership and Community Protection Act imposes such strict net-zero standards for fossil fuel plants that their operational use would be dramatically reduced; however, the PSC contended the adjustment to a shorter period hurts New York ratepayers and is speculative.

The PSC reiterated previous arguments when requesting the court review FERC’s decisions and its denial for a rehearing, including that a 17-year period could cost consumers $400 million, claiming FERC should have waited to rule until addressing other pending rehearing requests related to NYISO’s compliance and asserting that FERC’s decision departs from precedent.

The petition also cites a dissent submitted by Commissioner Mark Christie, who expressed concerns about the May approval of the 17-year timeframe, which reversed previous rejections by FERC. Christie opted to not elaborate, citing pending rehearing requests related to that approval order.

Despite the legal wrangling, NYISO already has implemented the 17-year amortization period as part of its demand curve reset.