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November 17, 2024

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ERCOT, Brazos Reach Agreement in Bankruptcy Case

Brazos Electric Power Cooperative has offered to pay ERCOT as much as $1.44 billion in its proposed exit plan from Chapter 11 bankruptcy and settle its dispute with the Texas grid operator over astronomical wholesale power prices in the wake of the February 2021 winter storm.

Under the terms of a settlement agreement and reorganization plan filed Thursday with the U.S. Bankruptcy Court for the Southern District of Texas, Brazos will make an initial payment of $1.15 billion. It will then make annual payments to ERCOT of $13.8 million for 12 years and contribute a portion of the sale of its generation assets, about $116.6 million, to fund payments through the grid operator to market participants still short from market transactions during the week of the storm (21-30725).

The initial lump sum will be used to help replenish a fund ERCOT used to settle transactions following the storm and to finance an initial distribution to market participants that joined in the settlement.

ERCOT had no comment on the filings, keeping with its practice of not remarking on legal matters. However, it told stakeholders in a market notice that it has not yet reached a final agreement on “certain important provisions in the plan.” It also noted that both the plan and a disclosure statement are working drafts and will be amended to reflect ongoing discussions and negotiations with Brazos and other key stakeholders.

The bankruptcy court has scheduled a hearing for Sept. 14 to determine whether the plan meets U.S. Bankruptcy Code requirements. Assuming confirmation, Brazos will then begin soliciting votes, due Oct. 27, from ERCOT and market participants on the agreement. Another hearing has been scheduled for November to consider final approval of the settlement and reorganization plan.

Brazos filed for bankruptcy in March 2021 after receiving an invoice from ERCOT for $2.1 billion in market transactions that it was short the market, with payment due in a few days. The cooperative responded with a force majeure event letter and by disputing the charges. (See ERCOT’s Brazos Electric Declares Bankruptcy.)

The co-op then opened an adversary proceeding against ERCOT in August 2021, challenging the Public Utility Commission’s emergency orders directing the grid operator to set prices at their $9,000/MWh limit to reflect the scarcity in the market. It sought to reduce the short-pay claim by at least $1.1 billion, the amount it attributed to ERCOT’s administrative adjustment.

Wholesale prices remained at their maximum for four straight days after the grid came within minutes of total collapse. ERCOT also increased ancillary fees to more than $25,000/MWh as it desperately sought to balance demand with load after a devastating loss of generation that led to long-term blackouts.

“The consequences of these prices were devastating to Brazos Electric and its members,” the cooperative said in its restructuring plan.

The adversary proceeding trial began earlier this year but was suspended after several weeks to allow the parties to mediate the dispute. (See ERCOT, Brazos Agree to Mediation in Dispute.)

ERCOT has said that almost all of the Brazos short-pay claim should be entitled to priority treatment as an administrative expense claim in the bankruptcy case. The short-pay amount has been revised to $1,886.6 billion, which will be fully recovered.

When Brazos comes out of bankruptcy, it has agreed to sell its generating assets, which total about 4 GW of capacity, and transition from a generation and transmission cooperative to a transmission and distribution cooperative. All of Brazos’ generation is natural gas-fired.

Under the agreement, Cliff Karnei, Brazos’ general manager since 1997, and three other members of the cooperative’s senior management will leave their jobs by March 2023. In addition, Karnei and two others will be barred from working for any ERCOT market participant if they’re acting as a financial counterparty to the grid operator.

Karnei resigned from ERCOT’s Board of Directors last year shortly after the storm hit, ending two decades of service on the board.

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California Legislature Passes Climate, Energy Bills

California lawmakers passed a last-minute package of climate and energy bills on Wednesday night that Gov. Gavin Newsom wanted to bolster grid reliability and reduce greenhouse gas emissions.

The last day of the 2021/22 legislative session saw lawmakers vote to reverse the state’s decision to close its last nuclear plant, Pacific Gas and Electric’s Diablo Canyon facility, by 2025. The Senate and Assembly approved Senate Bill 846, which grants PG&E a $1.4 billion forgivable loan to keep Diablo Canyon operating five years beyond its scheduled retirement.

The plant supplies nearly 9% of the state’s electricity needs and 17% of its carbon-free energy, the measure says.

“Preserving the option of continued operations of the Diablo Canyon powerplant for an additional five years beyond 2025 may be necessary to improve statewide energy system reliability and to reduce the emissions of greenhouse gases while additional renewable energy and zero-carbon resources come online,” it says.

Newsom, who backed the bill, signed it Friday. Continued operation of Diablo Canyon will require approval of the U.S. Nuclear Regulatory Commission.

Grassroots advocacy group Californians for Green Nuclear Power (CGNP) has pushed for the move since before many politicians were convinced that keeping the plant open made sense. Newsom and other officials gradually came around to CGNP’s point of view as the state struggled to maintain grid reliability starting with the rolling blackouts of August 2020.

“This has been the culmination of a decade of work for CGNP, of thousands of hours of research, filings, outreach and testimony,” the group’s president, Carl Wurtz, said in a prepared statement. “It’s unfortunate it took the lights going out for many to appreciate Diablo Canyon’s value, but better late than never.”

Others continue to believe nuclear power is wrong for California. A contingent of lawmakers said the $1.4 billion could be better spent on fast-tracking more solar, wind and storage resources to meet the state’s goal of relying on 100% clean energy by 2045.

Negative reaction to SB 846’s passage included a statement by the nonprofit Environmental Working Group saying, “This action can only hurt the state’s shift to safe, renewable energy and prolong the risk of a disaster at the plant.” The “bailout bill” was rushed through the Legislature at Newsom’s bidding in the last week of the session, with little time for review by lawmakers and the public, it said.

“The bill … which goes into effect immediately, extends the plant’s carefully planned and negotiated [retirement],” EWG said.

A 2016 agreement among PG&E and environmental and labor groups initially laid out plans for Diablo Canyon’s closure. The California Public Utilities Commission in January 2018 approved the 2,200-MW plant’s retirement. The bill invalidates that decision while ordering the CPUC to reopen its Diablo Canyon proceeding.

SB 846 also instructs the CPUC to submit to the Legislature a cost-benefit analysis of keeping the plant open from 2024 to 2035 compared with adopting a portfolio of “other feasible resources” consistent with the state’s greenhouse gas reduction goals, and a “reliability planning assessment” with supply-and-demand forecasts for five- and 10-year periods under several risk scenarios.

Climate Bills

Other measures passed by lawmakers this week at Newsom’s behest included:

  • Assembly Bill 1279, the “California Climate Crisis Act,” which would codify former Gov. Jerry Brown’s 2018 executive order requiring the state to become carbon neutral by 2045 and to “achieve and maintain net-negative greenhouse gas emissions thereafter.”
  • SB 1020, which would establish new interim targets for the state’s effort, under 2018’s Senate Bill 100, to supply all retail customers with 100% zero-carbon energy by 2045. The bill would make it state policy to supply 90% clean energy to retail customers by the end of 2035, upping that amount to 95% by Dec. 31, 2040.
  • SB 905, which would require the California Air Resources Board to establish a program to capture and store carbon dioxide, and AB 1757, which would task the state’s Natural Resources Agency with establishing ambitious carbon sequestration targets for “natural and working lands” by Jan. 1, 2024.

One Newsom-backed bill failed Wednesday. AB 2133 would have accelerated the state’s GHG reduction goals from 40% below 1990 levels to 55% below those levels by 2030. The bill failed in the Assembly after members of the lower house could not agree to support some Senate amendments.

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Newsom Declares Emergency as Heat Stresses Calif. Grid

California Gov. Gavin Newsom on Wednesday proclaimed a state of emergency aimed at temporarily increasing energy production and reducing demand in response to an extreme heat wave forecast to hit the state this weekend.

Newsom’s emergency proclamation will allow gas-fired power plants to generate additional electricity by loosening air quality requirements and restrictions on fuel use. The proclamation relaxes restrictions on the use of backup generators from 2 p.m. to 10 p.m. on days in which CAISO has declared an Energy Emergency Alert Level 2 or 3.

And ships berthed at California ports won’t be required to use shore power when CAISO declares a Level 2 or 3 energy alert.

The heat wave, which is forecast to last over the Labor Day holiday weekend and through Wednesday, is expected to be the most extensive so far in the West this year. The temperature in Death Valley is forecast to peak at 126 degrees F on Saturday, which would tie the highest temperature ever recorded on Earth in the month of September.

“We are anticipating this extreme heat to be a length and duration the likes of which we haven’t experienced in some time,” Newsom said during a news conference on Wednesday.

The emergency proclamation issued on Wednesday is similar to one the governor issued during a heat wave in July 2021.

“We’ve headed these issues off in the past,” Newsom said Wednesday. “We did so last year quite successfully. I’m confident we’ll do it again this year and this week.”

Newsom concluded his remarks by urging residents to stay safe and hydrate.

Shortly after the news conference concluded, CAISO issued an Energy Emergency Alert Level 1, which means real-time analysis has shown that all resources are in use or committed for use, and energy deficiencies are expected. A Level 1 alert is less severe than a Level 2 or 3 warning, the latter of which signals the likelihood of rolling blackouts. The ISO’s grid is most vulnerable in the evening hours as solar resources roll offline and other generating sources are required to ramp up to fill the drop-off in production. 

Also on Wednesday, CAISO issued a statewide “flex alert,” a call for voluntary electricity conservation on Wednesday from 4 p.m. to 9 p.m. to reduce the risk of outages. Additional flex alerts are possible through the Labor Day weekend, CAISO said.

CAISO is keeping an eye on Sunday and Monday in particular, when it expects peak loads of around 48,000 MW. (See Heat Wave to Test Western Grid this Weekend.)

During his news conference, Newsom touted progress the state has made in its transition to clean energy. An estimated 4,000 MW have been added to the grid that weren’t available in July 2020, the governor said.

Recently developed emergency measures include the addition of generators and a strategic energy reserve, more procurement and demand response to produce 2,000 MW in response to emergency conditions, according to a release.

Still, the heat wave is stretching limited energy resources across the Western U.S., Newsom said. And the state’s hydroelectric generation has been hurt by the extended drought.

Newsom also pointed to climate bills the state Legislature might pass on Wednesday, the final day of the session. Those include Senate Bill 846, which would keep the Diablo Canyon nuclear plant open beyond its scheduled 2025 retirement.

Assembly Bill 2133 would increase the state’s greenhouse gas reduction target from 40% below 1990 levels by the end of 2030, to a 55% reduction in that period.

Hudson Sangree contributed to this article.

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FERC OKs MISO Seasonal Auction, Accreditation

FERC issued a pair of orders Wednesday that allow MISO to establish a seasonal capacity auction and availability-based accreditation, but also rejected its request to require a minimum capacity obligation (ER22-495, ER22-496).

The commission said a seasonal auction and an availability-based accreditation will “better align resource adequacy requirements with periods of increased risks on the MISO system.” However, it said the proposed minimum capacity obligation isn’t likely to improve resource adequacy.

MISO in late 2021 sought FERC approval to perform four seasonal capacity auctions with separate reserve margins by the 2023-24 planning year and apply a seasonal accreditation based on a generating unit’s past performance during tight system conditions.

The RTO also filed separately to establish a minimum capacity obligation, where a load-serving entity must demonstrate that it has secured at least 50% of the capacity required to meet its peak load before MISO’s voluntary capacity auctions.

The commission issued the orders just before MISO’s requested Sept. 1 effective date for the new tariff rules. The grid operator has been moving ahead with preparations for the 2023-24 capacity auction while assuming FERC approval.

Most intervening stakeholders reacted negatively to the two filings earlier this year. They said a stricter accreditation based on risky hours that can’t be accurately predicted would result in volatility and unfair penalties for generators. Many also said MISO didn’t explain the reliability problems the minimum capacity obligation was meant to correct. (See MISO’s Seasonal Capacity Proposal Opposed at FERC.)

But FERC said a four-season auction will provide “a more granular assessment of seasonal resource adequacy needs” and ensure that LSEs don’t procure “capacity beyond what is necessary to ensure resource adequacy in a given season.”  

“This, combined with MISO’s proposal to accredit resources based on their seasonal performance, will offer further assurance that MISO’s resource adequacy provisions are sufficient to mitigate the system’s resource adequacy risk throughout the planning year,” the commission said.

FERC said the RTO’s plan to use capacity values based on historical performance during high-risk hours “will increase MISO operator confidence that those resources will perform when they are most needed.”

The seasonal accreditation design is rooted in a unit’s prior performance during 65 hours of emergency or other tight seasonal system operating conditions. FERC disagreed with resource owners’ complaints that the new accreditation is overly burdensome or complicated.

The commission also batted back complaints that the accreditation won’t accurately predict availability during system needs. It said although “no capacity accreditation methodology can perfectly predict a resource’s future availability or performance during all intervals,” MISO had made an earnest effort.

But FERC also instructed MISO to complete an informational report that compares the seasonal accreditation results to actual resource availability by the end of the 2025-26 planning year.

The new seasonal design means that MISO’s zones can seasonally clear beyond an annual $257/MW-day cost of new entry (CONE). The current planning resource auction design sets the maximum auction clearing price at CONE, which is calculated by dividing the new generator’s costs over the days in a year. Now, CONE will be divided by the days in a season.

The grid operator has said a seasonal clearing price of up to $1,000/MW-day could be appropriate, though it promised to make sure the sum of four seasonal clearing prices for any zone remains at or below CONE.

Despite member complaints over higher clearing prices, FERC was comfortable with seasonal prices possibly exceeding an annual CONE.

“As MISO explains, such outcomes will incent new entry in the event the MISO system is short capacity,” the commission said.

Clements Objects to Seasonal Design

Commissioner Allison Clements dissented in a 19-page statement, called the seasonal design a flawed and “ambiguous proposal” whose accreditation relies on the “wrong set of hours.” She said crediting resources with up to 12-hour lead times is unwise, given that they “are unlikely to be capable of performing when called upon.”

Clements said it wasn’t clear how MISO or its members would navigate four seasonal auctions held simultaneously in the spring. She said capacity sellers must blindly offer into a season without knowing any results of the other three seasons.

Allowing MISO’s clearing prices to exceed CONE in a season could “provide a loophole for excessive customer costs,” Clements said.

“Today’s decision bakes troubling flaws into MISO’s capacity rules that may jeopardize reliability for years to come. While the majority urges MISO to continue working to improve its capacity rules, it is not clear how some of these improvements could be made within the confines of MISO’s stakeholder process absent Commission action forcing such an outcome,” Clements said.

The commission has no reason to believe that these stakeholder dynamics will change such that MISO will better align capacity payments with system value in the future. Today’s order therefore puts a flawed short-term improvement ahead of long-term results, leaving it to industry to regulate themselves,” she said. “In my view, it would be better for us to insist the job is done right. ‘Measure twice, cut once,’ as the old adage goes.”

FERC Snubs Minimum Capacity Obligation

The commission shared stakeholders’ and the Independent Market Monitor’s mostly dim view of the proposed minimum capacity obligation.

It found MISO’s argument that it needs a minimum obligation to discourage LSEs from relying entirely on the voluntary auction while the RTO navigates a rapidly transforming resource mix “unpersuasive.” The commission said the grid operator had not demonstrated that a minimum capacity obligation “will address or mitigate resource adequacy concerns.”

FERC said it was unconvinced that the obligation will reverse a trend of fading reserve margins because MISO conducts an auction six weeks before its planning year begins. It said the obligation is “highly unlikely to facilitate the construction of new resources ahead of the relevant planning year, as resources, particularly generation resources, take longer to develop than six weeks.” FERC said LSEs will instead likely scramble to procure bilateral contracts from the same resources that would have otherwise offered capacity in the auction.

“…[N]othing inherent in the proposed MCO is likely to support the construction of new capacity in time to meet resource adequacy needs relative to the status quo,” the commission said.

It also said that the RTO didn’t address how the obligation would affect market power by limiting buyers’ ability to purchase capacity in the auction.

“The disciplining effect of the auction, a centralized market where capacity sellers are subject to market power mitigation, on the bilateral capacity market is an important component of both MISO’s resource adequacy construct and the Commission’s approach to market power more broadly,” FERC said.

Commissioner Mark Christie emphasized in a concurring opinion that while FERC rejected the proposed obligation, it didn’t mean MISO couldn’t offer a new minimum capacity obligation in the future.

In another concurrence, Commissioner James Danly said while he agreed with the market power concerns, he would have preferred FERC set the matter to a paper hearing to consider the tariff revisions. He said it appeared MISO has a “desperate need for reform of its capacity construct” combined with a difficult stakeholder process.

“I am concerned by the increasing risk that MISO will be unable to retain sufficient dispatchable generation to ensure reliability and resource adequacy,” Danly said. “With these concerns in mind, I urge my colleagues to consider commission action pursuant to [the Federal Power Act] Section 206.”

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Kansas Regulators Approve CCN for Competitive Project

Kansas regulators on Tuesday granted a certificate of convenience and necessity to NextEra Energy Transmission (NEET) Southwest as it seeks to build a transmission line it was awarded last year through SPP’s competitive process.

The Kansas Corporation Commission said in its decision the project “will have a beneficial effect on customers by lowering overall energy costs, removing inefficiency, relieving transmission congestion, and improving the reliability of the transmission system” (22-NETE-419-COC).

NEET Southwest estimates it will cost $85.2 million to build the 94-mile, 345-kV transmission line from the Wolf Creek nuclear power plant in Kansas to the Blackberry substation in Missouri. The project has a 2025 completion date.

Commission staff said the project is expected to produce a benefit-to-cost ratio of between 3.36 and 1.48 to 1.24, but that was based on an early estimate of $162.7 million in construction costs.

“This leads the Commission to believe the [B/C] ratio is much higher than originally projected,” the KCC said.

Under the terms of a nonunanimous settlement agreement among NextEra and KCC staff, Evergy, SPP, Kansas Electric Power Cooperative, Sunflower Electric Power and Citizens’ Utility Ratepayer Board, NEET Southwest will consider an option to double circuit a 25-mile segment that parallels an existing Evergy 161-kV transmission line. That is subject to receiving approval from SPP for a change in project scope and agreements from Evergy.

The KCC directed NEET Southwest to cooperate with Evergy, the incumbent transmission provider, to interconnect the transmission line to the Wolf Creek substation.

SPP’s Board of Directors approved NEET Southwest’s bid for the project last October. It is one of four competitive projects the grid operator has signed off on under FERC Order 1000. (See “Expert Panel Awards Competitive Project to NextEra Energy Transmission,” SPP Board of Directors/Members Committee Briefs: Oct. 26, 2021.)

In February, FERC approved NEET Southwest’s request to recover 100% of all prudently incurred costs associated with the project should it be abandoned or canceled for reasons beyond the company’s control. (See NextEra Transmission Subsidiary Gains Abandonment Approval.)

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Memphis Says Staying with TVA is Best Option

Memphis Light, Gas & Water’s (MLGW) leadership said Thursday that a long-term energy contract with Tennessee Valley Authority is a safer alternative than joining MISO and simultaneously generating its own power.

MLGW President J.T. Young said during a special meeting of the utility’s Board of Commissioners that staying with its current electricity supplier represents the “least risk and most value.” He advised the commissioners to reject all alternative supply proposals and to schedule a future vote to consider the recommendation.

The board has up to 60 days to hold a vote. Its members said they would like to speak with TVA executives in the next month about the federal utility’s long-term strategy before making their decision.

The Memphis utility has been exploring alternatives to TVA’s supply since 2020 and has received 27 responses from alternative energy suppliers. In June, consulting firm GDS Associates said leaving TVA and building its own generation and transmission to participate in MISO’s wholesale markets would yield the utility tens of millions of dollars each year — or place the same amount at risk. (See Inflation Dampens Possible Memphis Exit from TVA.)

Supply scenario used in MLGW RFP (MLGW) Content.jpgSupply scenario used in MLGW’s request for proposals | MLGW

 

GDS told the board Thursday that updated figures indicate none of the alternative bids produce savings when compared to TVA supply. The bids were based on MLGW’s  2020 integrated resource plan (IRP) that envisioned multiple resource portfolios, including 230- and 500-kV links to access wholesale power in MISO South.

Chris Dawson, power supply principal for GDS Associates, said the IRP is not “immune” from inflation, more expensive labor and supply chain issues.

“I hate to keep coming back to this, but … the landscape is different than it was in 2020. … It’s not the same environment that the IRP was developed in,” Dawson said.

He said MLGW’s “from-scratch” power alternatives to TVA will require “an immense amount of funding” and are now more expensive than remaining with TVA under a long-term, 20-year contract.

The commissioners accepted public comments at the beginning of the meeting but did not permit comment following Young’s recommendation.

Memphis resident Pearl Eva Walker, climate and justice chair for the local NAACP chapter, asked that the board choose an energy supplier more focused on affordability, reducing energy burdens, and climate change mitigation.

She said GDS’ analysis seemed to emphasize the risks of switching energy suppliers and ignored potential benefits. Walker said Memphis could likely take advantage of the clean energy incentives in the recent Inflation Reduction Act.

“We want a supply moving forward that will help MLGW take advantage of these tax credits,” she said.

Multiple residents asked that the utility not tie itself to a supplier like TVA, which they said is shortsightedly focusing on expanding natural gas-fired resources as historic heatwaves engulfed Tennessee over the summer. (See SACE Urges FERC Inquiry into Proposed TVA Gas Plant.)

The Sierra Club’s Dennis Lynch, who served on MLGW’s Power Supply Advisory Team, said signing a long-term contract with TVA would be “the wrong direction.”

Lynch called MLGW’s IRP “bogus” because it relied too heavily on adding a natural gas-fired plant. He called on the utility to commission a 100% clean-energy IRP.

Other residents told the board that TVA appears to be its most reliable option, with some invoking ERCOT’s disastrous outages during the February 2021 winter storm. They said Memphis must avoid a similar catastrophe.

MLGW is TVA’s largest wholesale customer, comprising about 10% of total load and spending about $1 billion per year on electricity. The city has been a TVA customer for 80 years, but recently voiced displeasure over energy burdens and prices under the federal utility.

MISO this March held its quarterly Board Week in Memphis in an apparent attempt to woo MLGW. While there, the RTO’s leadership met in private with the utility’s executives. (See “Memphis Location for Board Week May Pay Off,” MISO Board of Director Briefs: March 24, 2022.)

Ahead of the board meeting, the Southern Alliance for Clean Energy (SACE) accused TVA of being evasive about the extent of its dependence on MISO for energy imports.

“Without MISO, there’s a good chance TVA couldn’t keep the lights on in Memphis. Yet TVA continues to lead people in Memphis to believe joining MISO would threaten reliability,” SACE said in a press release emailed to RTO Insider.

The alliance said that based on interchange data from the Energy Information Administration, TVA has imported 11% of its demand from the MISO footprint in 2022. “It’s fair to say that TVA relies on MISO,” SACE said, noting Memphis accounts for almost 10% of TVA’s total load and imports from MISO have roughly equaled the amount of total power TVA has supplied to MLGW in recent years.

TVA’s vice president of transmission and power supply Aaron Melda pushed back on SACE’s conclusion, saying interchange and power flows do not necessarily equate to energy purchases. He said MISO also flows power over the TVA system by way of its Midwest-South transmission constraint.

Melda said TVA’s 69 interconnections with other utilities means that it can and should purchase less expensive power at times to save its customers money.

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NE States Seek Comment on Offshore Wind Interconnection Plan

New England is getting serious about offshore wind transmission.

In a request for information published on Thursday, a coalition of five states — Massachusetts, Connecticut, Rhode Island, Maine and New Hampshire — asked for comments about how to connect the thousands of megawatts of offshore wind power in the development pipeline with the region’s complicated, crowded grid.

The states are trying to start early, cognizant of the intense planning required for such a massive infrastructure buildout and competition for federal funding.

NE OSW Concept Map (New England Energy Vision) Content.jpgA conceptual offshore wind transmission plan from the New England states. | New England Energy Vision

They also laid out an early conceptual framework for how they plan to get started, with incremental, phased additions of transmission able to handle 1,200 MW each through 2040.

“Having a clean, affordable, reliable regional electricity grid — supported by transparent decision-making processes and a transmission system that reliably accommodates duly enacted clean energy laws — is foundational to achieving our clean energy future,” the states said in a statement.

In addition to comments on the plan, which are due Oct. 14, state agencies will hold a technical conference to talk in depth about the best interconnection points, how to minimize land-based transmission upgrades, the design and implementation of HVDC systems, and how to co-optimize transmission infrastructure to maximize consumer benefits.

Among the questions the group is asking for advice on are how to prioritize different projects, whether to prefer HVDC over other types of lines, and how to minimize costs to ratepayers.

The Modular Offshore Wind Integration Plan included in the RFI gets even further into the nitty gritty of where offshore transmission lines should make landfall.

“Initial assessments suggest that Bridgeport, Conn., and Boston, Mass., areas are potential efficient interconnection points for the next tranche of OSW generation,” the plan says, but the states also ask for advice about other options.

The RFI and accompanying plan were met by excitement from the region’s environmental groups and clean energy industry.

“New England for Offshore Wind is thrilled that five of the six New England states have come together to issue this request for information and explore investment options for the transmission infrastructure needed to integrate clean resources, including offshore wind, onto the regional power grid,” said Susannah Hatch, Environmental League of Massachusetts Director of Clean Energy Policy in a statement.

Whither Vermont?

Notably missing from the list of states involved is Vermont, but the document makes clear that the Green Mountain State, with its lack of coastline, will still be watching closely.

“Given Vermont’s vertically integrated structure and the lack of any shoreline to act as a potential point of interconnection for offshore wind — which is a substantial, though not sole, focus of this RFI — Vermont will not act as a participating state,” a footnote says.

“However, Vermont is generally supportive of a regionally organized effort to gather information that will aid each state’s planning activities and potentially facilitate federal funding opportunities for transmission upgrades and will remain a close observer of this request for information and may participate in subsequent discussions regarding its content and/or next steps.”

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MISO Opening Winter Fuel Surveys Next Month

MISO this year will again ask thermal generators for information on their fuel supplies through weekly surveys and consumables data requests.

Staff will begin collecting the information Oct. 3. The recurring data requests will open each Monday and close on Sunday and can be updated throughout the week.

The RTO is collecting the data from members with units that use coal, oil and petcoke and that are registered in the commercial model. Staff has been testing the surveys.

MISO’s Mike Mattox told the Reliability Subcommittee Thursday that members’ individual answers on the nine-question survey will be confidential, with aggregated data published on MISO’s website.

The weekly surveys were introduced last winter after the RTO issued warnings about natural gas and coal fuel-security issues and forced-generation outages during cold fronts. (See MISO Sounds Alarm on Potential Winter Fuel Scarcity.) It announced early this year that the task would become permanent so it can better understand fuel positions during winter. (See MISO Winter Fuel Security Surveys Now Permanent.)  

Mattox said the RTO still plans to turn winter fuel security surveys into a year-round task for owners of fossil fuel generation owners. However, he said fuel survey issuances “may change [in] frequency as conditions warrant.”

The grid operator said last year’s fuel surveys indicated generators had healthy stockpiles, despite the reliability anxiety. The RTO attributed the results to generally mild winter weather and careful fuel management. Some operators reported slower train deliveries because of supply chain issues, labor shortages and harsh weather.

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Heat Wave to Test Western Grid this Weekend

Forecasters say a Western heat wave like the one that pushed CAISO’s grid to the breaking point over Labor Day weekend 2020 will hit California and the Desert Southwest this weekend, with temperatures that could set records in inland areas of Northern California.

The extreme heat promises to be the latest in a series of weather anomalies that have tested power systems from Texas to Washington state in the past two years.

“An extended period of dangerously hot conditions with record temperatures up to 115 [degrees F]” will threaten residents of inland areas of Northern California over the holiday weekend, with the highest temperatures anticipated on Sunday and Monday, the National Weather Service (NWS) said in a heat advisory.

Inland areas of Southern California, including downtown Los Angeles, could see highs up to 105 degrees on Sunday and Monday, with “abnormally warm overnight lows” that could cause millions of residents to run their air conditioners long after the region’s supply of solar ramps down in the evenings.

The NWS predicts highs of 112 degrees in Sacramento, 111 degrees in Las Vegas, 109 degrees in Phoenix and temperatures pushing into the 90s in areas of the Pacific Northwest (although not in major population centers such as Portland and Seattle), potentially limiting CAISO’s ability to import electricity from neighboring states.

Any interruptions to transmission or generation, which wildfires have caused the past two summers, could exacerbate the situation.

CAISO Responding

West-wide heat waves and supply constraints struck the Western grid in August and September 2020, causing CAISO to order rolling blackouts in mid-August of that year and to declare energy emergencies over Labor Day. The August blackouts affected more than 2 million residents for periods ranging from roughly 30 minutes to 3 hours.

Since then, CAISO has interconnected several thousand megawatts of lithium-ion batteries to its grid, almost all with 4-hour discharge capacities. The batteries are intended to make up for shortfalls during hot summer evenings and have performed according to expectations so far. How the batteries will perform in more extreme conditions could be tested this weekend.

California’s summer has been relatively mild this year with the exception of a less-severe heat wave in mid-August, when CAISO issued a “flex alert” asking customers to reduce usage.

In preparation for the upcoming heat wave, the ISO said it is carefully watching the situation on Sunday and Monday when it expects peak loads of around 48,000 MW.

“We are taking measures to bring on all available resources and considering potential load relief actions, including flex alerts,” CAISO said in an emailed statement. The alerts will ask customers to set thermostats at 78 degrees from 4-9 p.m., to avoid using large appliances and to turn out unnecessary lights.

“Flex alerts have been an effective way to lower electricity use and help the grid through the most stressed time,” it said.

The ISO has also called for restricted maintenance operations from Wednesday through Tuesday.

“Market participants are cautioned to avoid scheduled maintenance to ensure all available generation and transmission lines are in service,” it said.

In a video posted to YouTube Tuesday, CAISO CEO Elliot Mainzer said, “With extreme heat forecast across California and the West over the next week through the Labor Day holiday, we need the public’s help to keep the power flowing without interruption. The ISO will use all available resources and tools to meet the heightened demand for electricity during this regional heat wave, but intense weather events like these call on all of us to do our part.”

Weather Anomalies

Record temperatures this weekend would continue an unpredictable series of extreme weather events, which many attribute to climate change.

February 2021’s winter storm nearly collapsed ERCOT’s grid amid widespread blackouts ordered by the Texas grid operator and SPP. A heat dome over the normally mild Pacific Northwest in June 2021 pushed temperatures to 116 degrees in Portland, Ore., and 108 degrees in Seattle, with some inland areas hitting 118 degrees. (See Avista Orders Blackouts as Temperatures Soar.)

In July of last year, a massive wildfire in southern Oregon severely derated the Pacific AC and DC interties during a Western heat wave, shutting off essential summer power from hydroelectric dams in Washington and Oregon to California.

Mainzer said in a recent interview with RTO Insider that extreme weather events are affecting load planning.

“How different weather patterns may behave in different parts of the West and what it means for our energy infrastructure is an issue that’s becoming front and center,” Mainzer said. “The basic physics of greenhouse gasses, where you’re trapping more heat in the atmosphere, means greater extremes.”

In an Aug. 19 webinar, two Stanford University students who performed summer fellowships with the Western Interstate Energy Board (WIEB), presented their findings on extreme weather and the grid.

Temperatures across the region have generally increased by about 1 degree F since 1995, researchers Jake Hofgard and Evan Savage said in the WIEB webinar. “However, this … smooths over the extreme temperatures which have the most impact on the grid,” Savage said.

All regions in the West saw an increase in extreme temperatures during heat waves, particularly the Pacific Northwest, California, Nevada, Arizona and Colorado, they said.

Their research focused on weather anomalies because “identifying extreme weather events and their impact on the grid is going to be particularly useful for regulators that want to prevent outages, especially in summer months,” Hofgard said. The researchers concluded that “extreme weather anomalies are becoming more common across the entire West, with a particularly significant increase in the Pacific Northwest.”

Their forward-looking analysis showed Phoenix could eventually see temperatures of 125 degrees in a 1-in-100 weather event, with Albuquerque and Salt Lake City also experiencing abnormally high temperatures.

Grid planners need to better incorporate weather anomalies into their load forecasts and to increase reserve margins, while making those margins more dynamic in response to weather variations, they said.

“We found that assuming historical weather patterns for long-term forecasting is no longer reliable,” Savage said. “As extremes become more prominent, [it] could expose utilities to risk. And similarly, long-term energy load forecasts should also include climate modeling in order to capture the increase in extreme temperatures that we may see in the future and [the corresponding] increase in air conditioning load growth.”

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ERO Supports FERC’s Extreme Weather Standards Proposal

In a joint filing to FERC last week, NERC and the regional entities gave their support to the commission’s proposal to modify NERC’s reliability standards in response to the ongoing impacts of climate change (RM22-10).

The comments of the ERO Enterprise came in response to FERC’s Notice of Proposed Rulemaking, issued in June, to direct NERC to update reliability standard TPL-001-5.1 (Transmission system planning performance requirements) to set expectations for long-term extreme weather planning by utilities. (See FERC Approves Extreme Weather Assessment NOPRs.) The standard is set to take effect next July, replacing current standard TPL-001-4. FERC’s proposed changes would require responsible entities to:

  • develop benchmark planning cases based on historical extreme heat and cold weather events and future meteorological projections;
  • use steady-state and transient stability analyses, covering a range of factors such as the grid’s changing resource mix and its performance during extreme weather, to plan for future extreme events; and
  • create a corrective action plan (CAP) to mitigate any occasions where performance requirements for severe weather have not been met.

The commission also sought comment on whether standard MOD-032-1 (Data for power system modeling and analysis) should be revised to address climate change concerns, and whether drought, tornadoes or other extreme weather conditions should fall within the scope of the final rule.

TPL-001

In their comments, NERC and the REs agreed that TPL-001-5.1 is unsuited to “the risks posed by extreme heat and cold weather conditions” and called for the standard to be revised or augmented with a new standard focused on transmission planning. The ERO noted that the rising incidence of severe weather and the ongoing transition to renewable resources, both of which are directly connected to climate change, are moving forward at a rate that NERC’s standards development process has been unable to match, despite its best efforts.

“Understanding and addressing the reliability risks posed by these extreme hot and cold conditions has been a high priority of the ERO Enterprise,” the entities said in the filing, citing NERC and FERC’s joint report on last year’s winter storms, NERC’s cold weather standards project (Project 2021-07) and other weather-related work by the ERO. “The ERO Enterprise supports the commission’s attention to the role [that] reliability standards for long-term transmission planning can play in helping to address the risks posed by extreme heat and cold conditions.”

Regarding the proposed changes to TPL-001-5.1, the ERO reminded FERC that it originally suggested updating the standard during a technical conference the commission held last year — the same conference that FERC cited when it issued the NOPR in June. (See FERC Tackles Grid Planning for an Unpredictable Climate.)

Both TPL-001-4 and its planned successor “require transmission planners and planning coordinators to evaluate … wide-area events affecting the transmission system,” including severe weather, but do not require the creation of CAPs — which NERC said was “appropriate at the time” the standards were approved. However, the ERO believes these requirements are no longer sufficient for the challenges currently facing the grid, and that “there is opportunity to improve the … standard to better account for the … impacts of extreme heat and cold … and to require entities to take corrective actions [in response to] system performance issues.”

Flexibility for the ERO

While NERC and the REs endorsed FERC’s desire to revise the transmission planning standards, they did have some suggestions regarding the implementation process. In particular, the ERO asked the commission for as much flexibility as possible to “best address the considerations discussed in the NOPR.”

First, the ERO noted that “significant work would be required to develop the necessary technical foundation for a uniform planning approach [accounting] for regional differences in climate and weather patterns” that could affect how entities implement the new standard. With this in mind, it asked that FERC’s final order not limit it to the example benchmark-based development approaches listed in the NOPR.

NERC and the REs also reminded FERC that the impact of climate change does not only involve sudden crises like last year’s winter storms, but also long-term environmental conditions that can severely affect the grid over sustained periods. As a result, the ERO urged that any studies mandated by the new standard should also take these phenomena into consideration.

In regard to other extreme weather conditions, the ERO said these should be included in future versions of TPL-001, though again with consideration to the climate conditions experienced by different regions. For example, in the Western U.S., drought and wildfire risks constitute a major threat from the changing climate, while in other areas hurricanes, flooding and icing may be larger concerns.

Finally, NERC noted that MOD-032-1 already allows planning coordinators and transmission planners to request “other information … necessary for modeling purposes” from entities, including data related to extreme heat and cold conditions.“To the extent NERC’s stakeholders identify that specific revisions would be beneficial for reliability, those revisions could be included in the scope of a TPL-001 revision project; however, the commission does not need to direct revisions to reliability standard MOD-032-1 to account for any new extreme heat and cold study requirements at this time,” the ERO said.