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November 5, 2024

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WECC Report Reviews State of the Western Interconnection

Among the topics covered by WECC’s State of the Interconnection (SOTI) report released Friday, one subject stands out for its immediacy: the impact of extreme natural events on the Western grid.

WECC organizes the annual report to highlight its stakeholder-selected reliability risk priorities, which currently include cybersecurity, natural events, resource adequacy, and the impact of changing resources and customer loads on the bulk power system (BPS).

And while growing cybersecurity risks get play across the NERC-led ERO Enterprise, the SOTI makes clear that climate threats are still paramount in the Western Interconnection.

“Last year, the West experienced extreme weather ranging from heat waves and dry spells to extreme winter storms and atmospheric rivers. The frequency, duration and seasons of extreme events have increased over the last 40 years,” WECC said in the report.

The interconnection last year registered 40 reportable reliability events, according to the SOTI, up from 33 in 2021 and tying 2019. WECC said such events have increased in severity over the past four years, based on NERC’s severity risk index (SRI), which “measures the severity of daily conditions based on the combined impact of load loss, loss of generation and loss of transmission on the BPS,” according to NERC.

Among last year’s events were 10 Level 3 energy emergency alerts (EEA-3), nine of which occurred during a late summer heat wave over Aug. 30 to Sept. 10.

“The average duration of the EEA-3s in 2022 was more than 200 minutes, exceeding the average duration for EEA alerts in previous years by almost double,” the report noted.

Last summer’s heat wave also saw the Western Interconnection set a new electricity demand record of 167,530 MW on Sept. 6, exceeding WECC’s peak forecast of 164,650 MW and smashing the previous record of 162,017 MW set in August 2020. The report notes that 1,000 cities in the West saw temperature records fall during the heat wave, with afternoon highs reaching 15 to 30 degrees above historical averages.

Although not detailed in the SOTI, the West averted even higher demand — and rolling blackouts — last summer through California’s emergency measures, which included heavy use of industrial demand response and last-minute calls for residents to consume less electricity during periods of peak usage. (See California Runs on Fumes but Avoids Blackouts.)

The report notes that 22,581 wildfires burned 3.3 million acres across the West last year, with 31 of those affecting the BPS between January and July, down from 70 such fires in 2021.

“There is no strong correlation between wildfire number or severity and risk to the BPS. This is largely because fire location is the dominant driver of risk to BPS elements,” the report said.

The SOTI also highlighted the impact of drought and long-term aridification on the Western grid, with the latter having severely reduced water levels of the reservoirs behind hydroelectric dams on the Colorado River system, with Lake Powell, impounded by the 1,320-MW Glen Canyon Dam, at its lowest level since being filled in the 1960s.

While a series of atmospheric rivers this past winter have restored the reservoir levels supporting California’s extensive hydroelectric system, WECC offered a cautionary note.

“Despite record precipitation over the last few months, much of the West remains in a state of drought, although conditions have improved compared to a year ago,” the report said.

Dual Peaks

The SOTI addresses Western resource adequacy from the perspective of natural events and the changing resource mix. It notes that, over the last 50 years, the U.S. heat wave season has doubled from 34 to 73 days, and that grid planners are dealing with the dual challenges of higher loads in both summer and winter.

“While the Western Interconnection’s peak demand occurs in the summer, many entities are winter-peaking. As temperatures and extreme weather increase, some of these entities are becoming dual-peaking. This presents resource planning challenges for entities that have historically experienced one predominant peak,” the report said.

WECC pointed to a recent example: Just a year and a half after record-smashing heat in June 2021 produced record loads in the Pacific Northwest, a December 2022 cold front also caused record winter peak demand in the BC Hydro, Alberta Electric System Operator and Western Power Pool areas.

The SOTI pointed to a future Western resource mix that will be much less reliant on coal and nuclear generation by 2032 (with anticipated retirements of 13.4 GW and 1 GW, respectively), and more heavily dependent on solar (31.9 GW of new capacity), wind (9.2 GW) and natural gas (4.7 GW). WECC also projects the region will take on 18.3 GW of new battery storage over that period.

“Variability is a primary driver of resource adequacy challenges, and, based on data provided by entities for WECC’s Western Assessment, variability will increase,” WECC wrote. “Projections for maintaining resource adequacy depend on new resources coming online as planned, with little margin for delay. Factors such as supply chain disruption or siting delays can pose serious risks.”

The report pointed out that WECC and the ERO Enterprise have “focused heavily” on the emerging risks from inverter-based resources (IBRs) such as solar and wind.

“While solar-related IBR events decreased in 2022, battery storage — also inverter-based — is increasing, expanding the potential for increased IBR-related events,” the report stated.

The report also covers transmission-related developments over the past year, including final U.S. Department of the Interior approvals of the Gateway South transmission line across Wyoming, Colorado and Utah; the Ten West Link from Arizona to California; and two segments of the Gateway West project from Wyoming to Idaho.

WECC also points to other projects in the later phases of review or nearing approval, including Boardman-to-Hemingway in the Northwest, Greenlink in Nevada and SunZia in the Southwest.

“While these projects reflect progress, WECC studies show a growing risk associated with transmission availability, particularly regarding growing resource adequacy risks,” the report said.

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Danly Addresses Capacity Auction Snafu at MISO Board Meeting

NEW ORLEANS — FERC Commissioner James Danly paid an unannounced visit to MISO’s Board of Directors meeting Thursday following a snag in the RTO’s new capacity accreditation process that will delay next month’s planned capacity auction.

Danly urged MISO’s leadership to “recommit” to market fundamentals. He said the grid operator must ensure that its prices incent resource adequacy and that it follows “steady, deliberate” changes to its tariff.

MISO will experience high capacity prices when scarcity conditions are present, Danly said.

“As the old saying goes, the solution to high prices is high prices,” he said.

FERC issued a show-cause order to the RTO on March 17, directing it to recalculate a systemwide capacity ratio used to validate accreditation values for planning resources or explain why it shouldn’t have to (EL23-46).

MISO said it will recalculate seasonal accredited capacity ratios but doing so will likely delay its first four-season auction. Its original unforced capacity to seasonal accredited capacity ratio erroneously counted some previously excused planned outages against some generators’ availability. (See FERC Order May Delay MISO’s 1st Seasonal Capacity Auction.)

Danly discouraged MISO from “chopping and changing” its market design, saying reactionary alterations make it “rationally impossible” for market participants to respond to and prepare for structural changes. He said his advice extended to other grid operators.

MISO told RTO Insider after the meeting that Danly’s appearance was coordinated weeks prior between it and FERC, though it did not tell stakeholders he was coming. The RTO said that as a rule, it does not place addresses from FERC commissioners on its meeting agendas. It also said that when it scheduled Danly’s visit, it had nothing to do with its seasonal capacity auction. However, Danly’s remarks focused exclusively on the capacity market.

MISO CEO John Bear said staff will ensure stakeholders have enough time to understand the recalculated ratio and how it affects thermal resources’ accreditation before running the auction.  

The recalculated ratios are expected to result in “reduced accreditation values for individual market participants and on an aggregate basis,” MISO says.

Entergy and other market participants have warned that smaller capacity values for their units may cause shortfalls in some MISO zones for certain seasons. (See FERC Denies Exemption Requests from MISO Accreditation Rule.) 

During an Advisory Committee meeting Wednesday, Jim Dauphinais, an energy consultant representing multiple MISO end-use customers, said it’s important that the grid operator back up and make sure it’s using correct values in the auction. He said that while it was “unfortunate” how it played out, FERC’s order and subsequent delay illustrates how untested market changes can cause disruptions when systems and people aren’t prepared.

“Quite frankly, we don’t know if our seasonal construct is working,” Dauphinais said.

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NC Utilities Commission Approves New Net-metering Rules for Duke

The North Carolina Utilities Commission on Thursday largely approved Duke Energy’s (NYSE:DUK) proposal to update its net energy metering (NEM) rules for residential rooftop solar customers that is meant to end cross-subsidization caused by the old payment system.

The utility’s proposal had the support of renewable energy trade groups including the Solar Energy Industries Association and the North Carolina Sustainable Energy Association, but the proposal still drew some opposition because of the new charges it will place on NEM customers starting in 2027.

The process to update the rules took several years and responds to a pair of laws. HB 589, passed in 2017, required that payments to NEM customers not lead to any cross-subsidization from other residential customers who do not own solar panels and that Duke do a study, on which it based its proposal, on the costs and benefits of the program.

HB 951, passed in 2021, is intended to support renewable generation as a means of cutting carbon emissions from utilities and required the NCUC to evaluate and modify NEM rates as needed.

Duke’s study found cross subsidies of $25 to $30/month in its Carolinas (DEC) territory and $35 to $40/month in its Progress (DEP) territory.

The main mechanism to deal with those is a new minimum monthly bill of $22 for DEC and $28 for DEP. Larger solar facilities above 15 kW represent the biggest opportunity for under-recovery of fixed costs so such customers will be billed $1.50/kW-month in DEP, while customers in DEC will have to pay $2.05/kW-month.

Duke will also start charging NEM customers non-bypassable charges to recover costs for programs such as demand-side management and efficiency, securitized storm costs, and similar charges that are approved by the NCUC for recovery through riders that are not dependent on energy use.

The commission found that the minimum bill, the charge for larger solar panels and the non-bypassable charges are all key to ensuring that NEM customers do not benefit from cross subsidies, but it required changes to the other proposals in the package.

Duke will have to change its initial proposal on how to net exports from customers with their imports from the grid during critical peak pricing (CPP) periods when demand is highest. Duke initially would not have netted exports when CPP is in effect, but the commission directed it to net exports and imports during such hours.

The NCUC also rejected Duke’s proposal to pay NEM exports at its approved avoided-cost rates that it pays qualifying facilities under the federal Public Utility Regulatory Policies Act. That would have locked in the rates for a decade, and the commission agreed to its staff’s suggestion that NEM avoided costs be based on avoided-cost proceedings it holds every two years.

Duke has historically retained renewable energy credits produced by its customers’ generators eligible for NEM, but customers will now keep them when the new NEM rates go into effect.

While pairing storage with solar is increasingly common, that technology was not dealt with at all in the rule changes. The NCUC said more “field testing and experimentation” would help to set up rules for compensating solar plus storage.

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MISO Winter Recap Centers on December Emergency

NEW ORLEANS — MISO’s annual winter lookback focused almost exclusively on operations during the widespread Dec. 23 deep freeze, with staff vowing to work on emergency coordination with their neighbors and digging into why the RTO was asked to shrink flows on its Midwest-South transmission transfer.  

“So, a difficult quarter,” MISO Independent Market Monitor David Patton said as he began his postmortem before the Board of Directors’ Markets Committee March 21.

Patton said had it not been for the winter storm, real-time energy prices would have been down 11% year-over-year. Instead, they were up by 15% at $47.60/MWh.

Jessica Lucas, executive director of system operations, joked that Winter Storm Elliott was “the Christmas gift that no one wanted.” She said if the storm had lasted two full days, its “impacts could have been much more severe.”

Lucas said MISO consistently exported power to southern neighbors, including emergency energy to Tennessee Valley Authority, and complied with requests to reduce its Midwest-South transfers by 1,500 MW. The grid operator typically flows 3,000 MW south and 2,500 MW midwest over the connection.

MISO went into Dec. 23 with19 GW of unplanned outages from the day before. The grid operator was forced to call a maximum generation event, calling up emergency resources as it also exported energy to neighbors. (See MISO Defends Energy Exports During December Storm; MISO Data Show Steep Gas-fired Outages During Winter Storm.)

Lucas said fuel issues played a significant role in gas-fired generation outages, with multiple units unable to start. She also said the gas market was on holiday, complicating matters and preventing generation owners from buying additional fuel. She said “strong wind performance” kept operations afloat.

“MISO maintained reliability across the footprint with no interruptions,” she said.

When asked how operations performed during the storm, Renuka Chatterjee, vice president of operations, said the phrase that comes to mind is “dodging a bullet.”

“The only difference between this and Winter Storm Uri was the wind output,” she said.

Patton said it’s “boggling” that gas markets are allowed to close for weekends and holidays.

“The fact that gas doesn’t trade on a weekend is hard to understand … We can’t shut our markets down on a weekend,” he said.

Patton said MISO lost two 1 GW generators on either side of the regional connection almost simultaneously as the RTO’s neighbors asked it to dial down the transfer constraint’s flows.

Lingering Questions on Transfer Reduction

Patton said MISO needs to understand why its neighbors needed the transfer’s cutback.

“We’ve been asking our neighbors about the situation to cut, and we haven’t heard anything,” Patton said. He added, “This has nothing to do with MISO’s shortcomings.”

He said with more information from its neighbors, the RTO might be able to manually redispatch generation before taking more dramatic steps.

Patton said the many gas generation outages from units without backup fuel shows the importance of MISO accrediting capacity on the margins. He said a marginal aspect in capacity accreditation isn’t meant to single out only renewable generation. (See MISO Accreditation Impasse Persists at Workshop.)

JOAs with Neighboring Systems? 

Patton also said the “massive exports or wheels through MISO” during the storm means the grid operator should more clearly define how it expects its control room staff to react during widespread emergencies in the Eastern Interconnection.

He said the RTO and its neighbors need joint operating agreements that “specify what you can expect from us and specify what we can expect from them.”

“Typically, you should never shed load to protect non-firm exports,” Patton told the board.

Less than a month earlier, Patton advocated that the system operator sign JOAs with its neighbors. He said procedures should cover a “slew of deliveries” that operators can take in risky situations.  

“I’m shocked that NERC doesn’t require RTOs to have joint operating agreements across all the major seams,” he said during the Gulf Coast Power Association’s MISO/SPP conference in early March.

Patton said some MISO market participants will see bills reaching “tens of millions” because of prices during the storm, partly because of its actions to help its neighbors.

“When you don’t have joint operating agreements … it’s really hard to see good interregional collaboration on a forward, or a planning basis,” he said.

Jennifer Curran, senior vice president of planning and operations, agreed that MISO and neighboring systems should determine coordination frameworks.

Director Robert Lurie said it was “interesting” that the RTO was able to keep exporting power while in emergency procedures. He said the storm shows the importance of interregional flows and managing constraints.

“First, I want to say that all things considered, you did a remarkable job,” Director Phyllis Currie told executives.

She asked whether staff could collaborate with its neighbors before facing emergency procedures. Chatterjee said they held a conference call with PJM soon after the storm and that it is interested in creating a specialty market product with MISO for use during emergencies.

Southern Renewable Energy Association’ executive director, Simon Mahan, said Winter Storm Elliott showed that fossil fuel generation “is just as susceptible to the weather as wind energy or solar energy.”

Mahan said MISO’s exports during the storm indicates that the grid operator should redouble its efforts to plan interregional transmission.

Under “blue sky” conditions, he said, sturdier interregional links are a more efficient way to operate the Eastern Interconnection.

“Those same connections are literally a lifeline in extreme weather events. MISO needs to work with its neighbors to expand its regional transmission planning efforts outside of MISO and better connect MISO North with MISO South,” Mahan argued. “It can probably be said, and without exaggeration, that MISO’s actions saved lives during Winter Storm Elliott. But it still wasn’t enough to completely prevent the blackouts [in Duke Carolinas’ territory and TVA].”

Mahan said grid planners can underestimate the value of interregional transmission “because we don’t have a perfect way to calculate the true value of a warm meal or a hot shower.”

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FERC Approves PJM Proposal to Reduce Congestion Penalty During Grid Upgrades

FERC last week approved a PJM proposal to allow it to reduce the transmission constraint penalty factor (TCPF) under a set of circumstances that the RTO argued becomes punitive to load without providing any benefit (ER23-918).

The tariff and Operating Agreement revisions allow the factor to be reduced when localized transmission congestion is caused by the construction of upgrades — and the necessary deactivation of certain lines — that were either part of PJM’s Regional Transmission Expansion Plan (RTEP) process or to interconnect a generator. The TCPF would be reduced from its default of $2,000/MWh to a level that reflects the offers from resources available to address the congestion.

Given that the TCPF’s purpose is to incentivize generation or transmission solutions to congestion, PJM argued that when congestion is caused by upgrades that will resolve the issue upon their completion, it is unrealistic to expect a short-term investment to address the situation, and the penalty factors can become counterproductive. PJM stated that the average line outage caused by upgrades lasts an average of 211 days.

DAntonio-Phil-2017-06-08-RTO-Insider-FI.jpgPhilip D’Antonio, PJM | © RTO Insider LLC

“Where a transmission facility is taken out of service altogether due to an RTEP or interconnection upgrade, however, long-term price signals reflecting the default ($2,000/MWh) transmission constraint penalty factor cap do not serve the intended purpose given that the transmission upgrade currently under construction will mitigate these issues,” PJM Director of Energy Market Operations Philip D’Antonio said in an affidavit.

FERC approved a PJM request to remove the TCPF in Virginia’s Northern Neck peninsula after one of the three transmission lines into the region was placed on an outage for upgrades. The tariff and OA revisions were limited to that region, but the commission encouraged PJM to “consider modifications to its analyses of and planning for transmission outages to prevent such occurrences in the future.” (See FERC Approves Pause of PJM Tx Constraint Penalty Factor in Va.)

The PJM Markets and Reliability Committee approved the revisions during its Nov. 16, 2022, meeting. (See “TCPF Adjustments Permitted for Issues with Ongoing Solution,” PJM MRC Briefs: Nov. 16, 2022.)

DC Energy submitted comments to the proposal asking that the commission condition any approval on requiring that PJM provide market participants notice of any changes to the TCPF, as well as the specific outage, facilities and constraints prompting the reduction.

The Independent Market Monitor objected to the proposal, arguing that it lacks a verifiable process for PJM to follow when implementing the change and that no amount of data can be made available to provide the transparency needed to ensure that the RTO is applying the rules consistently. The IMM asked the commission to reject the filing and require PJM to create new rules that more accurately reflect transmission operating limits and forward-looking dispatch tools.

The Monitor also said that PJM and the commission should be eliminating instances in which the RTO has the discretion to set prices, in this case by choosing a marginal unit and modifying the TCPF to set LMPs. In the case of transmission upgrades that might cause congestion, the Monitor argued that transmission operators should create practices that ensure reliability throughout construction.

FERC said that PJM’s tariff already contains language requiring the notifications sought by DC Energy. It also sided with PJM over the Monitor, agreeing with the RTO that the proposal would not grant it considerable discretion and that it would only be allowed to reduce penalty factors in the specific circumstances outlined.

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MISO Enviros Say Broader Tx Planning Necessary

NEW ORLEANS — Clean energy advocates and a transmission developer asked MISO’s Board of Directors last week for stronger transmission plans and a facility blueprint for MISO South.

Southern Renewable Energy Association’s Andy Kowalczyk said he shared multiple stakeholders’ concerns that the grid operator has waited too long to address long-term transmission needs in the South.

Noting Entergy joined MISO in 2013, he said, “I know that in transmission planning terms that seems like yesterday, but MISO South has yet to be fully connected with our neighbors to the north. Only a narrow path between the north and south exists, and there’s been no truly regional planning in the subregion compared to the north in the past decade.”

MISO plans to bring a second long-range transmission plan (LRTP) portfolio forward for the board’s consideration sometime next year. The recommendation will again be focused on MISO Midwest and could hit $30 billion, staff have said. (See MISO Says 2nd LRTP Portfolio Still in Flux.)

During the board’s System Planning Committee meeting March 21, Aubrey Johnson, vice president of system planning, said MISO’s second, middle-of-the-road, 20-year planning future indicates renewable energy and carbon reduction will increase by 2030. Past Future 2 iterations didn’t anticipate the transformation until 2040; it will influence the second leg of MISO’s LRTP.

Beth Soholt 2023-03-21 (RTO Insider LLC) FI.jpgCGA Executive Director Beth Soholt | © RTO Insider LLC

Clean Grid Alliance’s Beth Soholt said MISO’s futures refresh is “further evidence” that the transition is happening at a much faster pace than anticipated.

“A trend we’ve always had with the utilities and at MISO is that transmission capacity is full before it is constructed and goes into service,” she said. “Given the very large interconnection queue in MISO, which is responding to demand for new resources, we are seeing this same trend again.”

Soholt said the Midwest’s first planned LRTP lines are quickly being spoken for. She said the future’s update almost triples the footprint’s renewable energy resources that will require sizeable transmission additions. Soholt urged the board to ensure staff is planning to build the bulk transmission system “at the appropriate bigness.”

Kowalczyk said despite MISO’s “major successes” with its Midwest LRTP plan, “the planning paradigm needs to change for the South.” He said it “should be unacceptable” that the grid operator will wait four years before it considers Southern needs.

The New Orleans resident said he was “genuinely worried” that the southern grid will falter during future emergencies. Kowalczyk said solar projects in Arkansas and Louisiana need new transmission capacity to come online.

“We need MISO to commit to planning for the future MISO South, for the good of the entire footprint,” Kowalczyk said.

NextEra Energy’s Matt Pawlowski urged MISO to be more aggressive on transmission planning. He said early green hydrogen projects, other new load and several generation developers want to join the system. Pawlowski said the region risks losing out on renewable energy and economic development if it doesn’t get more planning intensive.  

“None of this happens without transmission. The more aggressive we are, the better off we are to accommodate these loads,” he said. “The message to you on transmission is: We need to be aggressive on scenarios; we need transmission now. We’re already behind.”

Pawlowski said he doubted staff’s projections to energize the first batch of LRTP projects by 2028 or 2030. He said in his experience, construction and permitting should take 10 to 15 years, not MISO’s more optimistic forecast.

“Emerging industries like green hydrogen and offshore wind are getting a lot of attention from the business community and there are serious efforts to take advantage of federal incentives, but without being able to reliably deliver gigawatts of clean energy, they will not flourish,” Kowalczyk warned.

MISO’s “other” project category in its annual Transmission Expansion Plans drew interest at MISO Board Week. They include transmission owners’ projects needed for load growth and to address existing facilities’ ages and conditions. Stakeholders have said at times that the category appears to be a catch-all and is difficult to understand.

“How much work is MISO really doing to understand this category? I’d like to understand MISO’s due diligence on this,” Director Nancy Lange said.

Laura Rauch, senior director of transmission planning, said “other” projects often are largely driven by localized reliability needs, as opposed to NERC and regionally defined standards that drive baseline reliability projects.

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LG Energy Solution Quadruples Size of Ariz. Factory Plan

LG Energy Solution said Friday it would build a $5.5 billion factory in Arizona with an annual capacity of 43 GWh of vehicle and stationary batteries.

Construction of the Queen Creek facility is expected to start later this year. It is part of a rapid production buildout by the South Korean company, which has said it plans to expand its global production capacity by 300 GWh in 2023.

LGES is planning, building or operating manufacturing facilities in Michigan, Ohio, Tennessee and Ontario, either alone or in joint ventures with automakers GM, Honda and Stellantis.

The LGES announcement Friday came a year to the day after the company initially announced it would build a factory in Queen Creek, Ariz.

But the plan announced March 24, 2022, had a construction price tag and annual output only about one quarter as large as the revised plan. And in June 2022 — as inflation was soaring and the South Korean Won had reached a decade-plus low against the U.S. Dollar — LGES appeared to be hesitating on its construction. The company told Reuters it was reassessing its plans in Arizona.

The economic landscape changed radically in August 2022, when Congress passed the Inflation Reduction Act, which creates incentives for American consumers to buy electric vehicles with American-made components and incentives for manufacturers to build those components in the U.S.

In its announcement Friday, LGES cited the rising demand from EV manufacturers for domestically produced batteries.

“Our decision to invest in Arizona demonstrates our strategic initiative to continue expanding our global production network, which is already the largest in the world, to further advance our innovative and top-quality products in scale and with speed,” CEO Youngsoo Kwon said. “We believe it’s the right move at the right time in order to empower clean energy transition in the U.S.”

LGES called it the largest single investment ever for a standalone battery manufacturing facility in North America.

It will comprise two factories.

One will build cylindrical batteries for EVs, is targeted to begin production in 2025 and will have an output capacity of 27 GWh per year.

The other will build pouch-type lithium iron phosphate batteries for energy storage systems (ESS), begin production in 2026 and have a designed capacity of 16 GWh per year. LGES said it would be the first ESS-exclusive factory in the world.

LGES also has manufacturing facilities in China, Indonesia, Poland and South Korea. It said in the news release that expanding its presence in the U.S. would allow it to decrease logistics costs and improve partnerships with its customers in both the EV and ESS sectors.

Other companies have announced plans for battery factories north and west of Arizona.

EV manufacturer Tesla earlier this year said it would invest $3.6 billion in production facilities in Nevada, including a new battery factory and a heavy-duty truck factory. (See Tesla to Invest $3.6B in Nev. Truck, Battery Factories.)

And Statevolt is pursuing development of a 54-GWh battery plant in Southern California, near the lithium deposits in the Salton Sea area. (See 54 GWh EV Battery Plant Proposed for Lithium Valley.)

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Overheard at NE Electricity Restructuring Roundtable: March 2023

BOSTON — A panel of experts made the argument for smarter rate design on Friday at Raab Associates’ New England Electricity Restructuring Roundtable.

Updating rates to send better price signals is the key to unlocking the power of demand, the panelists said.

It’s a process that’s “more art than science, or more behavioral than economics,” said Janet Gail Besser, the panel’s moderator.

The speakers focused on Massachusetts, where the roundtables are held.

“With last fall’s Department of Public Utilities order requiring the utilities in Massachusetts to develop advanced metering infrastructure implementation plans, it appears there will be new opportunities for innovative rate design that can encourage electrification and reduce carbon emissions,” said Besser, a former chair of the DPU.

Electricity rates have been changing in structure for decades, but there’s one consideration that’s upped the ante in recent years, said Sue Tierney, a senior adviser at Analysis Group.

“What’s different now is the urgency of evolving the electric system as part of the path to decarbonizing the economy,” Tierney said.

An effective change to rate design to help start boosting demand is time-of-use rates, the panel agreed.

“Time-varying rates is an essential tool,” Tierney said. “Having it as a default option provides two opportunities: for the customer to take charge and figure out what they want to do in terms of their own energy management; and it sets up the context for … retailers and aggregators to use those time-varying rates.”

In the last few years, five states have started implementing opt-out time-of-use rates. Massachusetts is not one of them, and again the panel picked on the Bay State.

“Our customers in Massachusetts, we don’t know how much energy they’re using until we get the bill from utilities a month later. And we have no idea at any point in time when our customers are using energy,” said Travis Kavulla, vice president for regulatory affairs at NRG Energy. “So there’s no incentive or practical ability at all … for us to make investments in demand response.”

Melissa Whited, a senior principal at Synapse Energy Economics, offered another way to tweak rates to incentivize electrification of vehicles or home heating: playing around with how customers are charged.

For example, she said, states have traditionally tried to keep fixed charges low, and let volumetric rates stay higher, to incentivize customers to conserve energy.

“But with electrification, high volumetric rates are a barrier to adopting new technologies,” Whited said. So, California has experimented with high fixed charges with low volumetric rates limited to customers who are using certain demand-side technology.

There’s also an argument to be made for a broader overhaul, said Harvey Michaels, a lecturer at the Massachusetts Institute of Technology who has studied heat pump adoption.

“We have to realize as part of what we’re doing now that charging electric bills for the energy efficiency programs and other things we do, particularly when they’re competing with a gas-fired alternative, is shooting us in the foot,” Michaels said. “We have to figure out how to pay for these things with something other than electricity.”

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Regulators Slash NV Energy’s Transportation Electrification Plan

Nevada regulators on Thursday gutted NV Energy’s proposed $348 million transportation electrification plan, slashing the budget to about $70 million and removing most of its proposed programs.

The whittled-down plan, which the Public Utilities Commission of Nevada (PUCN) voted 3-0 to approve, has three programs. They include an interstate corridor EV charging program, an electric school bus vehicle-to-grid trial, and an innovation demonstration program that will provide matching funds for federal Inflation Reduction Act grants.

The proposed plan encompassed 10 personal and six commercial vehicle programs. Programs that the commission axed include a $5,000 EV purchase rebate for low-income residents, incentives for home charger installations, EV charging infrastructure programs for multifamily housing and workplaces, and transit electrification grants. (See NV Energy Seeking $348M for Transportation Electrification.)

Commissioners said the plan as proposed was too broad and that financial analysis, including impact on rates, was insufficient.

Another concern was what commissioners called a lack of progress on a previous NV Energy plan, the $100 million Economic Recovery Transportation Electrification Plan (ERTEP) that PUCN approved in late 2021. The three-year plan, which runs through 2024, aims to bring about 1,822 EV chargers to 120 sites throughout Nevada. (See NV Energy Gets Green Light for $100M EV Charger Plan.)

“The most recent update showed there was no progress made in actual implementation of the [ERTEP] programs,” Commissioner C.J. Manthe said on Thursday. “At the end of 12 months, there was only program administration costs that were expended.”

Commission Chair Hayley Williamson also noted NV Energy’s lack of spending thus far on the ERTEP programs. Still, she said, the transportation electrification plan that the commission approved on Thursday is significant.

“Despite some of these programs being deferred or rejected, this is still an approximately $70 million budget for transportation electrification, which is clearly important to the commission,” she said.

NV Energy was required to file ERTEP and the more recent transportation electrification (TE) plan by Senate Bill 448, passed during Nevada’s 2021 legislative session. The company filed the TE plan as part of the third amendment to its 2021 integrated resource plan. The TE plan covers 2023 and 2024; an updated plan will guide transportation electrification programs after that.

NV Energy Response

In a statement provided to NetZero Insider after the PUCN vote, NV Energy said, “We are currently evaluating the details of the commission’s order.”

But in a Feb. 24 filing, NV Energy responded to criticisms that have been raised since the TE plan was filed in September.

The TE plan is complementary to the charging-station-focused ERTEP, the company said, bringing transportation electrification programs to most of its customer classes. With its broad scope, the plan is intended to fulfill the intention of SB 448, NV Energy said.

“To be clear, the direction from the legislature was not just to prepare for future electric vehicle adoption or to keep up with resulting load — it was to accelerate transportation electrification in this state,” the company said in its filing.

NV Energy said it provided information related to its TE plan “well in excess of” the requirements of SB 448. And regarding progress on ERTEP, the company said it is not behind schedule.

“ERTEP is in year one of a three-year plan,” NV Energy said.

Clean transportation advocates said Thursday that the PUCN decision leaves “gaping holes” in the state’s EV policies. They said support is particularly needed for residential and commercial customers who want to install EV chargers at their homes or businesses.

“Leaving out residences, particularly multi-family homes, is a huge, missed opportunity,” Joe Halso, staff attorney with the Sierra Club, said in a statement. “What has been approved today is far from the holistic support necessary to meet EV drivers’ needs and improve access to clean transportation options for all Nevadans.” 

Program Details

The TE plan’s interstate corridor charging depot program is an expansion of a program contained in ERTEP. Charging sites would feature two Level 2 chargers, six DC fast-charging ports and shade canopies, although NV Energy said site hosts could request fewer chargers.

NV Energy will offer site hosts an incentive for each charging port, with higher amounts for sites in disadvantaged communities. With a $23 million budget, the program is expected to support 10 charging sites with 80 charging ports.

The electric school bus vehicle-to-grid trial is also an extension of an ERTEP program. NV Energy is looking for about nine school district sites — two large and seven small — to participate in the trial, in which energy will be discharged from electric buses during peak periods. Priority will be given to rural school districts.

The $32 million program is expected to support about 110 charging ports at nine sites.

PUCN also approved $1 million that NV Energy can use as matching funds if it secures federal grants under the Inflation Reduction Act.

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CAISO Board Approves Summer Readiness Measures

CAISO’s Board of Governors on Thursday approved measures to help ensure summer reliability, including extending for a third year a requirement that utility-scale storage batteries maintain a minimum state of charge during critical conditions.

The requirement “applies during very limited circumstances where we experience the most constrained conditions on the system,” such as during an extreme heat wave last September that brought CAISO to the brink of ordering rolling blackouts, said Anna McKenna, the ISO’s vice president of market policy and performance. (See California Runs on Fumes but Avoids Blackouts.)

In a memo to the board, McKenna and other CAISO staff members said the storage constraint “mitigates the risk storage resources may be unable to meet day-ahead discharge schedules in the real-time market because they were either insufficiently charged or discharged prematurely, leaving them unable to meet their day-ahead schedules for later hours when their energy may be essential to maintain reliability.”

The requirement was intended to be temporary when it was adopted in April 2021, following the rolling blackouts of August 2020. CAISO decided to extend it despite opposition from some stakeholders, primarily storage operators who said it puts them at a disadvantage when demand and prices are highest.

The ISO intends to replace the minimum state of charge constraint with a “more comprehensive set of tools” that the Board of Governors approved in December, but the software for its planned system upgrade is not yet ready, the staff memo said.

“These more comprehensive sets of tools, when implemented, will provide ISO operators with enhanced state of charge visibility and control via exceptional dispatch functionality,” it said. “These enhancements also provide opportunity cost compensation for resources that are exceptionally dispatched to hold state of charge.”

CAISO management had originally proposed extending the minimum state of charge requirement through September 2024 to allow for unanticipated delays in software development. But it pulled back on that plan because of stakeholder concerns and set Sept. 30, 2023, as the sunset date to ensure it “expires even in the event of implementation delays,” the memo said.

Capacity Procurement Mechanism

The Board of Governors also approved updates to the ISO’s capacity procurement mechanism (CPM) that it uses to purchase electricity to head off shortfalls during “significant events” such as summer heat waves. 

The changes are “limited but necessary for us to access capacity over the summer that may be needed to backstop should we be not sufficient with the resource adequacy capacity that we have,” McKenna told the board Thursday. 

CAISO ran into problems using its “backstop” CPM to find and procure capacity during summer heat waves in 2020 and 2021, partly because of its own rules, a staff memo said.

To fix those issues, CAISO management proposed four operational improvements, including two changes to its rules to help the ISO buy electricity that is “not contracted for during a significant event,” a staff memo said.

One change would let the ISO adjust the volume in megawatts of CPM resources “if the designated capacity already is committed and shown to the ISO as resource adequacy capacity.”

Another gives resource scheduling coordinators flexibility to designate resources for a significant-event CPM for less than 30 days, which has been the minimum term.

“Because of this rule, a resource scheduling coordinator may have to reject a mid-month significant event CPM designation because the designated capacity has an existing commitment or is unavailable for the following month,” the memo said. “This existing minimum term rule has prevented the ISO from accessing immediately needed and immediately available capacity.”