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December 24, 2024

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Feds Update Solar Development Roadmap in West

The Department of the Interior is proposing to designate 22 million acres of public land in the West as suitable for solar development. 

The roadmap announced Jan. 17 is an update of the 2012 Western Solar Plan and is intended to make permitting faster and easier. 

An estimated 700,000 acres of land for potential solar development is needed to help meet the Biden administration’s goals of a 100% clean energy grid by 2035, the U.S. Bureau of Land Management said.  

The 2012 Western Solar Plan identified areas with high solar potential and low resource conflicts in order to guide responsible solar development. It looked at land in Arizona, California, Colorado, Nevada, New Mexico and Utah. The update adds Idaho, Montana, Oregon, Washington and Wyoming.  

The draft analysis of the “Utility-Scale Solar Energy Programmatic Environmental Impact Statement” would further streamline the permitting process, steering developers toward sites with fewer potential conflicts with other land users, less environmental impact, greater access to transmission lines and higher solar potential. 

The update also reflects a dozen years of technological, societal and economic changes. 

The draft and its appendices are available on BLM’s website. Public comment will be accepted through April 18 and will help shape the Final Programmatic Environmental Impact Statement and Record of Decision. 

“This is a big deal,” acting Deputy Interior Secretary Laura Daniel-Davis told reporters during a conference call Wednesday, “and it’s the first time in more than a decade that the plan has been updated.” 

It will make permitting faster, easier and more consistent, she said. 

“Simply put, the updated Western Solar Plan will create the foundation for solar development and conservation on public land into the future,” Daniel-Davis said. 

“The proposal complements other regulatory updates in progress, including BLM’s pending Renewable Energy Rule, which will help incentivize renewable energy development on our public land” through fee reductions of up to 80%, she added. (See BLM Seeks to Slash Fees for Solar, Wind on Public Land.) 

BLM Director Tracy Stone-Manning said the clean energy portfolio on public land has been growing in the past three years, during which BLM has approved 47 renewable projects rated at 11.24 GW.  

BLM is now processing 67 clean energy projects rated at more than 37 GW, Stone-Manning said, and is in early review of more than 195 applications plus 97 site testing requests. 

She spoke also of BLM’s deep and continuing responsibility to balance the Biden administration’s economic and clean energy goals with the need for preservation of resources and respect for stakeholders. 

BLM worked with the National Renewable Energy Laboratory and Argonne National Laboratory to calculate that approximately 700,000 acres in the West would be needed to meet Biden’s clean energy goals. The proposed designation is 22 million acres, or approximately 31 times more than needed, which will provide needed flexibility. 

BLM prepared five alternatives; its preferred alternative, No. 3, would exclude areas in the 11 states that are more than 10 miles from existing or planned transmission lines carrying at least 100 kV and exclude areas that have a slope greater than 10%. 

Alternative No. 3 would exclude 140 million acres in the 11 states and invite solar applications on 22 million acres, ranging from 106,458 acres in Washington to 6.99 million acres in Nevada. 

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Wash. Bill Seeks Increased Monitoring of Petroleum Sector

OLYMPIA, Wash. — A Washington bill to create a new agency to monitor activity in the state’s petroleum market details five pages of information the body would have to collect from oil companies.

That’s too much data for a new state agency to collect and digest, representatives of oil industry representatives argued during a Jan. 17 hearing of the Washington Senate’s Energy, Environment and Technology Committee to introduce Senate Bill 6052.

But environmental groups contended that an oil industry transparency law is greatly needed.

The bill sponsored by Sen. Joe Nguyen (D) would create a Division of Petroleum Market Oversight under the umbrella of the Washington Utilities and Transportation Commission. Modeled after a new California office, the proposed agency would collect a massive amount of financial and industrial data from various branches of the oil industry in the state, including five refineries and a complex supply chain.

A Senate report describing the bill outlines the scope of information to be collected from oil producers, storage facilities, middlemen and transporters. The proposed agency’s purpose is to analyze the data to ensure the public is not being gouged at the gas pump.

“It has incredibly complex reporting requirements for an agency that does not exist,” said Peter Godlewski, government affairs director at the Association of Washington Business (AWB), which opposes the bill.

The agency would have subpoena power and would confidentially refer suspected legal violations to the Washington Attorney General’s office. It would also report its observations and conclusions to the governor’s office, other state agencies and the Legislature.

“I have concerns on how you determine price-fixing,” said Sen. Drew MacEwen, the committee’s ranking Republican.

‘Sunshine for Consumers’

Gov. Jay Inslee called for the bill following the political and economic fallout from the state’s introduction of a cap-and-invest program, which went into effect last year. Critics of the program, which is administered by Washington’s Department of Ecology, have blamed it for the state having some of the highest gasoline prices in the country. (See Cap-and-trade Driving up Washington Gasoline Prices, Critics Say.)

Inslee has challenged those critics, contending the oil industry has used confusion around the program to hike gas prices in excess of the costs to comply with the program, padding their profits. (See Inslee Challenges Cap-and-trade Role in High Wash. Gas Prices.)

Meanwhile, headed for the ballot next November is a public referendum to repeal the cap-and-invest program, against the wishes of the Democratic-controlled Legislature.

Washington’s gas prices have been among the highest in the nation since last summer, including a week as the highest. But during the Jan. 17 hearing, Nguyen cited AAA figures showing that Washington’s gas prices have been among the five highest in the nation since the 1970s for various economic and geographic reasons.

“This [bill] provides sunshine for consumers. … It makes [oil companies] show their math,” Clifford Traisman, lobbyist for Washington Conservation Action, said at the hearing. Leah Missik, senior policy manager at Climate Solutions, added that Washington needs to know what profits are earned at the different stages of the oil supply chain, from imports to the gas pump.

“Why does [the gas price] fluctuate so dramatically? … At the end of the day, we don’t know why,” said Matthew Hepner, an official with the International Brotherhood of Electrical Workers, which supports the bill.

‘Hellscape’

In opposing the bill, the Western States Petroleum Association (WSPA) and AWB expressed concerns about the complexity and scale of the proposed agency’s tasks and fears about sensitive information being leaked to the public.

“This Is highly sensitive data. If released, it will affect the market,” said Greg Hanon, who represents the WSPA, whose members include four of Washington’s five refineries. Jessica Spiegal, WSPA’s Northwest Region senior director, said: “It makes more sense to find out how Ecology got it wrong on the cap-and-trade program.”

Relying on Ecology Department calculations, Inslee and Democratic leaders said in 2021 that cap-and invest would add a few pennies per gallon. Instead, prices have been up 21 to 50 cents, depending on who’s calculating. That miscalculation is a key factor in today’s political controversy over the program.

Sen. Liz Lovelett (D) asked two AWB lobbyists at the hearing how making sensitive data public would hurt the oil companies and the market.

“It is unclear what type of hellscape this would unleash,” Lovelett said. The lobbyists said they would have to get back to her with answers.

Representatives from companies operating in the supply chain between oil refineries and gas stations opposed Nguyen’s bill because they contend some definitions in it are hazy.

Alone among the state’s refiners in not opposing the bill was bp America, which previously left the WSPA because it disagreed with the association’s opposition to some carbon-reduction measures.

Tom Wolf, a lobbyist for bp, said the company is fine with the concept behind the bill, but would like to see some tweaks to it. He also urged Washington to delay the bill for at least a year to give the state a chance to study the record of California’s program, which is only six months old.

Nguyen said his bill still needs work to address cybersecurity and confidentiality issues and clean up some of its definitions.

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ISO-NE Details Resource Modeling Plans for Capacity Accreditation

ISO-NE provided stakeholders with additional detail on its plans for modeling capacity demand and resource reliability attributes as the RTO and stakeholders continued work on the resource capacity accreditation (RCA) project at the NEPOOL Reliability Committee meeting Jan. 16. 

“Improvements are required to the Resource Adequacy Assessment (RAA) used currently to calculate capacity requirements (demand) and develop resource-specific accreditation values,” said Fei Zeng, ISO-NE technical manager. 

ISO-NE is working to improve the RAA modeling to better assess the risks and severity of loss-of-load events, and how different resources would affect system reliability during these periods. The RTO is trying to better capture resource reliability performance under different weather and system loading conditions, and with different resource mixes. 

The RAA resource modeling includes specific cases focused on season risk, resource accreditation, and system and zonal capacity requirements. 

ISO-NE has outlined four different modeling options for different resource types: thermal modeling based on seasonal qualified capacity and outage rate; profile modeling based on an “hourly expected performance profile;” storage modeling based on expected energy limitations; and perfect capacity modeling, based on seasonal qualified capacity. 

At the January RC meeting, Zeng detailed which modeling options would be used for different resource types: 

    • Thermal model: nuclear, coal, fuel cell, nonintermittent hydro, imports, tie benefits, and (from March to November) gas and oil resources. 
    • Profile model: active and passive demand resources, and intermittent resources like solar, wind and landfill gas. 
    • Storage model: battery storage and pumped hydro. 
    • Perfect capacity model: distributed energy capacity resources and co-located generators that function as a single capacity resource. 

For peak winter months, ISO-NE is proposing to take a more varied approach to modeling oil, gas and dual-fuel resources, instead of just using the thermal model, which would apply to them in all other months. 

From December through February, gas resources would be modeled as a single fleet using the profile model, intended to account for gas network limitations and demand from local gas distribution companies.  

“A regression model is used to establish a relationship between the amount of daily gas available to generation and temperature conditions based on historical data,” Zeng said. “The daily available gas will be apportioned to each hour during the day based on historical hourly gas generation patterns and the representative heat rate of the gas fleet.” 

For oil resources, ISO-NE proposes using the thermal model for residual fuel oil (RFO) resources in all RAA cases and for distillate fuel oil (DFO) resources in the accreditation and capacity RAA cases.  

For the RAA seasonal risk assessment, ISO-NE would model DFO resources as an “aggregate energy storage resource with a limited amount of energy available during a two-week period.” 

Zeng noted that DFO resources have smaller storage tanks than RFO resources, causing them to exhaust their stored fuel more quickly and require more frequent replenishment. Because of variability in tank sizes and replenishment strategies, “DFO resource risks are better captured on a fleet level,” Zeng said.  

The two-week DFO energy constraint would be based on data from the past five winters. 

Fuel Requirements

To compare the reliability benefits of different types of resources that rely on a limited supply of energy, ISO-NE proposes creating a “daily operating hours requirement” (DOHR), which would equal the number of hours per day a resource must be able to operate at its seasonal capacity rating during peak winter months. Resources that can’t meet this requirement would have their qualified capacity derated.  

The RTO would use RAA results to calculate the daily operating requirement and would update the requirement at each capacity auction. ISO-NE also is considering a winter peak seasonal operating hours requirement (SOHR) and a fuel storage hours requirement (FSHR) for stored fuel resources. The calculation of SOHR and FSHR would consider RAA results and historical weather data.  

FSHR would be calculated by “multiplying the DOHR by the number of days in a winter cold snap,” said Alex Mattfolk of Levitan & Associates (LAI), which is working as a consultant for ISO-NE on the project. For this calculation, the consulting firm has determined that modeling a four-day cold snap would cover more than 99% of days. 

The seasonal requirement would be determined by multiplying the DOHR by the number of days cold enough to significantly stress the grid. LAI determined that 11 days would cover over 99% of days.  

Operationally Limited Resources

Mattfolk also presented on the firm’s proposal for “operationally limited resources” — gas plants that typically are unable to run on cold days due to “physical and/or operational constraints on gas delivery.” These resources would not be credited with any qualified capacity.  

LAI proposes to flag operationally limited resources based on historical performance during cold periods. Flagged resources could appeal their designation by providing evidence the gas constraint no longer applies or that the lack of operations was due to some unrelated factor. 

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EPA Proposes Methane Emission Penalties

EPA is moving to impose financial penalties for excessive methane emissions within the oil and gas sector. 

The proposed rule, announced Jan. 12, is part of the ongoing Methane Emissions Reduction Program established through the Inflation Reduction Act, which called for the penalties. 

As required by the IRA, the waste methane emissions charge would apply to certain oil and gas facilities that report emissions of more than 25,000 metric tons of carbon dioxide equivalent per year to the Greenhouse Gas Reporting Program. The charge would start at $900/MT of excess emissions in 2024, then increase to $1,200 in 2025 and $1,500 in 2026. 

EPA’s proposed rule spells out how the charge will be calculated and how exemptions will be granted. The agency said the charge will encourage the industry to stay on target to reduce its emissions, which can be accomplished through readily available technology. 

The agency said it expects gradually fewer facilities will be at risk of incurring the charge as they reduce their emissions sufficiently to comply with the recently finalized final rule in December establishing performance standards for new sources of methane and setting emissions guidelines for states to follow. 

There are two other key components of the IRA’s methane program: EPA is offering more than $1 billion in financial and technical assistance to speed the transition to low- and non-emitting oil and gas technologies. The agency is also working with the industry and other stakeholders to improve the Greenhouse Gas Reporting Program and increase the accuracy of reported methane emissions. 

Oil and natural gas operations are the largest industrial source of methane emissions in the U.S., EPA said. Methane is targeted because it is a superpollutant, roughly 28 times more potent as a greenhouse gas than carbon dioxide and responsible for about a third of the warming effect of all greenhouse gases.  

“Today’s proposal, when finalized, will support a complementary set of technology standards and historic resources from the Inflation Reduction Act, to incentivize industry innovation and prompt action,” EPA Administrator Michael Regan said in a news release. “We are laser-focused on working collectively with companies, states and communities to ensure that America leads in deploying technologies and innovations that aid in the development of a clean energy economy.” 

“It’s common sense to hold oil and gas companies accountable for this pollution,” Environmental Defense Fund President Fred Krupp said. “Proven solutions to cut oil and gas methane and to avoid the fee are being used by leading companies in states across the country.” 

The American Petroleum Institute had a different take. “As the world looks to U.S. energy producers to provide stability in an increasingly unstable world, this punitive tax increase is a serious misstep that undermines America’s energy advantage,” it said. “While we support smart federal methane regulation, this proposal creates an incoherent, confusing regulatory regime that will only stifle innovation and undermine our ability to meet rising energy demand. We look forward to working with Congress to repeal the IRA’s misguided new tax on American energy.” 

U.S. Sen. Kevin Cramer (R), representing the oil-rich state of North Dakota, decried the impact of the “burdensome” charges. “Democrats in Washington and their climate-zealous allies jammed the partisan Inflation Reduction Act through Congress, placing backwards, overburdensome regulations on domestic energy. This fee will reduce production and increase costs, disproportionally harming the working-class Americans who depend on affordable and reliable energy the most. Burdening North Dakota energy producers with more fees and penalties while saddling every American with higher energy is a foolhardy mistake Democrats will have to answer for.” 

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Wisconsin Senate Votes to Fire Commissioner Huebner 4 Years into Job

Wisconsin’s GOP-controlled Senate voted Jan. 16 to reject Public Service Commissioner Tyler Huebner’s nomination to the commission — nearly four years into his time at the regulatory agency.

Tyler Huebner | RENEW Wisconsin

Until Tuesday, Huebner had been performing duties unconfirmed. Wisconsin Gov. Tony Evers (D) first appointed Huebner in 2020 to fill former Commissioner Mike Huebsch’s unexpired term. Huebner’s first term came and went in 2021 without a confirmation or hearing vote, and Evers re-enlisted Huebner to a new term ending in early 2027. The Senate’s confirmation of Huebner subsequently was pushed into the 2023-2024 legislative session.

The 21-11 vote mostly along party lines to fire Huebner appeared to hinge on Republican senators’ unease with Huebner’s support for determining rates on customers’ ability to pay and cutting carbon emissions. Some said his aims veered from strictly regulatory into policymaking.

During testimony, Sen. Julian Bradley (R) said it was a problem that Huebner used his position to be “an activist” and said state law doesn’t allow the PSC the authority to enact income-based ratemaking.

Last week, the Senate Utilities and Technology Committee voted 3-2 against confirming Huebner after they questioned him in the fall over a 2022 water utility decision that established a subsidy pilot program for low-income customers and the PSC’s Strategic Energy Assessment Plan, which modeled an 80% reduction of CO2 emissions in the state’s energy production by 2039.

Sen. Jeff Smith (D) said the vote to remove Huebner is “such a head-scratcher at a time when Wisconsin is experiencing an unprecedented expansion of renewable energy.” He said Huebner brought valuable experience to the table.

“It is shortsighted [and] leaves us less prepared for the challenges ahead,” Smith said.

Huebner is a former executive director of RENEW Wisconsin, a nonprofit dedicated to accelerating the clean energy future.

The vote throws the three-person Wisconsin PSC into upheaval. Last week, Chairperson Rebecca Cameron Valcq announced her departure from the commission effective Feb. 2 after five years. At the time, Valcq said it was the “right time for me to pass the baton as I leave the agency in very capable hands.” She said the PSC had become “more transparent and accessible” during her tenure.

The exits leave freshly confirmed Commissioner Summer Strand as the sole Wisconsin regulator beginning next month unless Evers is swift with new appointees. The Wisconsin Senate confirmed Strand’s April 2023 appointment 27-5 in the same Jan. 16 session following the vote to oust Huebner. Strand is set to succeed Valcq as chair.

In a statement released by the Wisconsin PSC, Huebner said he was “proud” of the decisions he made as a state regulator and “especially grateful” to be involved with Wisconsin’s energy planning and reliability direction through his involvement with the Organization of MISO States (OMS).

“I am moving forward, and I plan to build on my work at the commission and throughout my career to tackle some of the big challenges of our times in a different capacity,” Huebner said.

The Senate vote disrupts OMS leadership. In 2023, the OMS Board of Directors unanimously elected Huebner to serve as the 2024 OMS president.

Current OMS Vice President and Iowa Utilities Board Commissioner Josh Byrnes is now considered OMS president. According to OMS Bylaws, in the event of a vacancy in the office, the organization’s vice president will succeed the presidency until the next annual election occurs.

OMS Executive Director Marcus Hawkins said the OMS community “will sorely miss Tyler’s expertise and credibility.”

“The high quality of his character, intellect and work ethic were a rare and powerful combination that made every OMS discussion better. His departure is a significant loss for Wisconsin and for the state regulatory community as a whole,” Hawkins said in an emailed statement to RTO Insider.

In a press release, Evers said Huebner’s dismissal continues a trend of legislative Republicans terminating appointees without grounds or leaving them unconfirmed indefinitely. Senate Republicans in October rejected seven of Evers’ appointees to the Wisconsin Natural Resources Board, Wisconsin Elections Commission, Wisconsin Medical Examining Board and the Governor’s Council on Domestic Abuse.

“Commissioner Huebner is an exemplary public servant who’s dedicated to serving the people of Wisconsin and building the sustainable future we want for our state. The decision by Senate Republicans to fire him today defies justification and logic,” Evers said in a Jan. 16 press release. “It’s my job to appoint the best and most qualified people to serve our state — that’s what I have been and will continue doing, regardless of the apparent Republican position that every appointee must agree with them 100% of the time to earn their support.”

Evers said state Republicans’ ongoing efforts to “harass, disparage and fire dedicated public servants is a serious threat to the basic functions of our government and democracy in our state.”

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Xcel Says Coal Retirements on Track Despite South Dakota PUC’s Plea for Extensions

Xcel Energy insists its plan to retire two Minnesota coal plants won’t mar reliability even though the South Dakota Public Utilities Commission sent a letter urging the utility to hold off on shutting down the units.  

The South Dakota PUC asked Xcel in a letter this month to reconsider its planned closures of the Sherburne County Generating Station (Sherco) and Allen S. King coal plants in Minnesota.  

“Closing these plants will take nearly 3 GW of reliable dispatchable electricity generation off the [MISO] grid precisely at a time when those resources will be needed the most to keep electricity flowing 24/7/365 throughout Xcel and MISO’s footprint,” South Dakota commissioners wrote to Xcel. “Premature closure of these plants adds to the uncertainty of electric generation resource adequacy in the upper Midwest including Xcel’s customers in South Dakota.” 

South Dakota commissioners cited NERC’s finding in its Long-Term Reliability Assessment that the MISO footprint could face a 4.7-GW shortfall through 2028. 

“Evidence is mounting that the premature closure of dispatchable generation will elevate the risk of electricity outages, particularly in tight load hours including hours of extreme cold and extreme heat, as well as those hours when wind generation is low,” the commissioners wrote.  

Commissioners also expressed concern South Dakota ratepayers may bear the costs of closing the plants early. They said Xcel said in a docket that choosing not to operate the two coal plants for the duration of their useful lives paired with a decision against extending the Prairie Island nuclear plant could cost customers $453 million more than keeping the plants open.  

“We do not want Xcel to be part of the impending problem of [a] generation shortage in the MISO footprint. Reliability should be your number one commitment!” commissioners told Xcel leadership.  

Xcel, however, said both the PUC and it are taking threats to reliability seriously and that it appreciates the feedback on plans to decommission its coal plants by 2030.  

“We are in alignment with the commission’s priority to ensure reliability throughout the clean energy transition and ensure South Dakotans have a dependable supply of electricity at all times, including periods of extreme weather and high demand,” Xcel said in an emailed statement to RTO Insider.  

Xcel pointed out that it plans to infuse 2.1 GW of wind and 2.5 GW of solar onto its Upper Midwest grid by 2032 and said it has another 1.1 GW of wind and solar waiting in the wings beyond 2032. It added that its two nuclear plants will be able to complement the variable supply with dispatchable, carbon-free electricity.  

Xcel also said it has plans to include 800 MW of “hydrogen-ready” combustion turbines in its generation portfolio and soon will build 500-700 miles of new transmission lines to further bolster reliability. It said it looks forward to “continuing to meet with the commission” for insight on the “complex task” of ensuring a reliable and affordable clean energy future.  

Xcel remains on track to exit coal generation by the end of the decade. It officially retired the first of its coal units at Sherco on the last day of 2023, with plans to retire the other two in 2026 and 2030.  

Ryan Long, president of Xcel Energy Minnesota, South Dakota and North Dakota, said there’s “tremendous potential for the plant site in the Upper Midwest’s energy future.”  

“Just as we’re taking a phased approach to decommissioning the coal units, we’re building replacement generation in phases to support clean, reliable and affordable energy for our customers,” Long said in a press release at the time.  

Xcel is building the first two phases of the total 710-MW Sherco Solar project adjacent to the Sherco site. It also plans to construct a 10-MW, 100-hour battery storage facility onsite as a pilot project from Massachusetts-based Form Energy. Xcel received a grant of up to $35 million from the U.S. Department of Energy for the battery project. 

Xcel said Sherco Unit 2 is slated to become a synchronous condenser to manage system stability after retirement.  

Finally, Xcel said it’s proposing to build the Minnesota Energy Connection, a 175-mile, 345-kV transmission line in southwest Minnesota that will use existing interconnection at Sherco to connect a minimum 2 GW of wind and solar.  

“There’s a lot of life left at the Sherco site, and our dedicated coworkers will manage the transition over the next decade,” plant director Michelle Neal said in the release.  

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ERCOT Meets Demand, Sets New Winter Peaks

ERCOT set a new winter peak for demand Jan. 16 as it easily met demand during a frigid blast that pushed temperatures 30 to 50 degrees below normal in Texas. 

The grid operator had expected electricity consumption to match the record levels set last summer, projecting demand as high at 86 GW as the winter storm approached. However, demand averaged 78.14 GW during the interval ending at 8 a.m. Jan. 16. 

That broke the previous winter mark set the day before, when demand averaged 76.34 GW during the 9 p.m. interval, surpassing the previous record of 74.53 GW set in December 2022. It also exceeded ERCOT’s earlier all-time peak of 74.53 GW set in 2019. 

The ISO issued conservation appeals for Jan. 15 and the morning of Jan. 16. With a hard freeze expected as far south as Houston, ERCOT is expecting similar conditions the morning of Jan. 17. 

The grid operator thanked Texas residents and businesses on X. 

“Your conservation efforts, along with additional grid reliability tools, helped us get through record-breaking peak times today and yesterday morning,” it posted Jan. 16. 

ERCOT was also boosted by energy storage and solar resources. Batteries peaked at more than 1,200 MW during the early morning hours Jan. 16; solar produced a record 14.21 GW of energy at 10:40 a.m.  

The grid’s staff said in December that there was a 1-in-6 chance of outages this winter if conditions matched those of the 2022 winter storm. While the temperatures have been frigid — Dallas has been below freezing since the afternoon of Jan. 13, with a low of 11 degrees Fahrenheit the morning of Jan. 15 — thermal outages were slightly below average at 7 GW. 

Texas Gov. Greg Abbott (R) took to X to praise ERCOT’s “flawless” performance, a credit, he said, to recent measures to weatherize critical facilities and strengthen the grid. 

Wholesale electricity prices hit $500/MWh during one 15-minute interval the morning of Jan. 16 but have generally stayed below $200/MWh since Jan. 13. 

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NERC Taking Comments as Winter Reliability Standard Deadline Looms

NERC is taking comments on a winter reliability standard for generators that has failed to clear its stakeholder process twice, the ERO announced Jan. 16.  

Comments are due by 8 p.m. EST on Jan. 22. NERC hopes to get one more vote on the rule, which failed to clear the stakeholder process its second time Nov. 30 with only 58% in support, short of the two-thirds required. If stakeholders fail to approve it this time, NERC Board of Trustees Chair Ken DeFontes has said the board might have to move the standard forward on its own. (See Standards Committee Authorizes Shortened Ballots.) 

FERC has required a new reliability standard to be filed by February based on the recommendations from its joint report with NERC on Winter Storm Uri, which led to deadly blackouts in Texas in February 2021. 

The proposed rule (EOP-012-2) would require generators to review their risks for extreme cold weather, which equates to the lowest 0.2 percent of hourly temperatures measured in December, January and February from Jan. 1, 2000, until the date temperatures are calculated. Any generator with extreme temperatures at or below freezing (32 degrees Fahrenheit) will have to comply with the standard. 

The proposal would require generators to develop and implement plans designed to mitigate the reliability impacts of cold weather. If the generators see lower extreme temperatures on their five-year reviews, those plans would have to be reviewed to ensure that they are in compliance with the standard and if they would have to identify additional mitigation measures. 

Generators would have to implement freeze protection measures that protect critical components so they could keep operating at their calculated extreme cold weather temperatures with sustained wind speeds of 20 mph for a period of not less than 12 continuous hours, or the maximum operational duration for intermittent energy resources. 

If a generator cannot meet the proposed standard’s requirements, it would be required to add new or modify existing freeze protection measures to provide the capability to operate at the extreme cold temperatures for its location. 

Generators will have to show that they have followed those cold weather plans and trained their staff to implement them, the proposed standard says. 

NERC plans to hold a nonbinding poll on the associated violation risk factors and violation severity levels through Jan. 22. 

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Congressional Democrats Urge FERC to Complete Transmission Rule

Nearly half the Democrats in Congress sent a pair of identical letters to FERC on Jan. 16 urging the commission to finalize its proposed transmission planning and cost allocation rule.

Sens. Martin Heinrich (D-N.M.) and Ed Markey (D-Mass.) led the group of 21 senators from the party in sending the upper house’s letter, while Rep. Paul Tonko (D-N.Y.) led the group of 113 House members in its version of the letter.

“In recent years, we have witnessed numerous examples of grid resilience issues, which have highlighted the inadequacy of the grid to handle changing load patterns, interconnect new clean energy resources and respond to increasingly frequent and severe extreme weather events,” read both letters, which were addressed to FERC Chair Willie Phillips. “FERC’s final rule should ensure that transmission planners account for these factors by requiring a long-term, forward-looking, 20-year planning horizon that addresses the changing circumstances and the evolution of our energy system.”

Phillips has said since assuming the chair that he wanted to move forward the Notice of Proposed Rulemaking on transmission, which was issued in April 2022. The commission also has to issue an order on rehearing for Order 2023, which updated its minimum standards for interconnection queues around the country. (See FERC Updates Interconnection Queue Process with Order 2023.)

The congressional letters follow some from stakeholders last month urging FERC to complete the rule this year. (See FERC Gets Growing Call to Finish Transmission Rule in 2024.)

The Department of Energy has said improved and increased transmission is needed for reliability, affordability and clean electricity. The department’s National Transmission Needs Study found capacity will need to double in many parts of the country by 2035 to meet the Biden administration’s clean energy goals, assuming just moderate load growth, the members said.

“In order to grow our economy, keep communities safe during extreme weather events, address historic environmental injustices and decrease energy costs for consumers, a robust and well-planned transmission grid is essential,” the letters said. “With a strong final rule, FERC can play a critical role in achieving these goals, fulfilling the promise of the most consequential infrastructure and climate laws in history.”

The Inflation Reduction Act and the Infrastructure Investment and Jobs Act have committed the country to a historic energy transition, they said, but the electric grid needs to be expanded to make that possible.

Americans for a Clean Energy Grid Executive Director Christina Hayes welcomed the support for finalizing the rule from Congress.

“The grid is in need of a 21st-century update, and the reforms currently pending at FERC will go a long way toward increasing the reliability and resiliency of our energy system and ensuring the delivery of cost-effective energy to all Americans,” Hayes said in a statement. “We will continue to work closely with FERC to help finalize a durable rule that advances the development of high-capacity transmission for the benefit of customers throughout the country.”

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Christie Denounces Tx Incentive Process as FERC Approves More MISO LRTP Project Perks

Commissioner Mark Christie has used FERC’s latest order on transmission incentives to condemn the commission’s process as requests for incentives come in fast and thick from MISO’s long-range transmission projects.

This time, FERC granted Xcel Energy’s ask for construction work in progress (CWIP) incentives and abandoned plant incentives for four 345-kV long-range transmission plan (LRTP) projects in South Dakota, Minnesota and Wisconsin, which allow Xcel to recover incurred costs in rates if the lines are canceled for reasons beyond its control (ER24-409).

The incentives apply to Xcel’s portions of the Big Stone South-Alexandria-Cassie’s Crossing project, the Wilmarth-North Rochester-Tremval project, the Tremval-Eau Claire-Jump River project and the Tremval-Rocky Run-Columbia project.

Xcel said it plans to spend up to $1.2 billion on construction for its portions of the projects. The utility said its Wisconsin- and Minnesota-based Northern States Power subsidiaries “expect to face a negative cash flow position while undergoing extensive levels of capital expenditures over the next several years” to build the LRTP projects.

Xcel said the CWIP incentive will improve cash flow and credit ratings during construction. It also said the projects carry heightened risks of abandonment because multiple utilities over multiple states are working in concert to build the lines. Xcel added that an economic downturn could hurt the chances for the lines, which were planned to serve projected, not existing, generation.

FERC agreed that the CWIP and abandoned plant incentives are “tailored to address the risks and challenges” Xcel’s subsidiaries will face as they undertake the projects.

But in a concurrence, Christie repeated that FERC’s granting of incentives “has become nothing more than a check-the-box exercise.” Christie has become increasingly critical of transmission incentives in FERC orders allowing them for developers. (See FERC Approves Dairyland Incentives for Minn.-Wis. Transmission Line.)

Christie said though FERC followed its protocol to grant Xcel the incentives, it’s time for FERC to revisit its CWIP and abandoned plant incentives, as well as the RTO participation adder, which he called “an involuntary gift from consumers.”

Christie repeated concerns that the CWIP incentive allows utilities to recover costs before a line has been placed into service, effectively forcing customers to serve as a lender for transmission development while they earn zero in interest and even pay utilities a profit through return on equity. He also said the abandoned plant incentive makes ratepayers the “insurer of last resort” as well as the lender on projects.

“Just as consumers receive no interest for the money they effectively loan transmission developers through CWIP, they receive no premiums for the insurance they provide through the abandoned plant incentive if the project is never built,” he wrote. “There is something really wrong with this picture.”

Christie said he supports FERC’s recent proposals contained in notices of proposed rulemaking to limit the RTO participation adder to three years after a utility has joined an RTO and eliminate CWIP incentives. He said those steps, alongside a reconsideration of the abandoned plant incentive, will “ensure that all the costs and risks associated with transmission construction are not unfairly inflicted on consumers while transmission developers and owners stand to gain all the financial reward.”

“In short, revisiting all these incentives is imperative at a time of rapidly rising customer power bills,” Christie said.