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November 13, 2024

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MISO Shelves IMM’s Transmission Planning Recommendation in State of the Market Report

MISO last week said it plans to handle four of the five recommendations this year from the Independent Market Monitor’s State of the Market report, putting a recommendation regarding transmission planning on hold.

The grid operator announced it’s deferring action on the IMM’s recommendation that it re-evaluate the future generation mix used to develop the long-range transmission plan (LRTP).

MISO Independent Market Monitor David Patton tied multiple State of the Market recommendations this year to reducing transmission congestion. He said most of the root cause of congestion can be tied to wind generation, which has little incentive to follow MISO’s dispatch instructions. (See MISO IMM Zeroes in on Tx Congestion in State of the Market Report.)

However, Patton also used this year’s report to criticize the future resource mix assumptions the RTO is using to shape a second LRTP portfolio for its Midwest region. It marked an unprecedented foray into transmission planning when the IMM typically focuses on MISO markets.

Patton recommended MISO use more battery storage, hybrid resources, other dispatchable resource additions and grid-enhancing technologies as alternatives to expensive transmission buildout. (See MISO Promises Analyses on Long-range Tx; Stakeholders Divided on IMM Involvement.)

MISO said while it agrees with the IMM that it’s important to “evaluate the cost and benefits of transmission to avoid inefficient investments,” it disagrees that the fleet mix envisioned in its second of three 20-year transmission planning futures isn’t well-founded.

“MISO is still evaluating and will work with stakeholders to define LRTP scenarios, business case and alternatives to manage uncertainty,” Zhaoxia Xie, of MISO’s market design team, said during a Nov. 9 Market Subcommittee meeting.

Xie said MISO may not end up taking the IMM’s recommendation but will conduct more analysis and hold discussions with stakeholders.

Jeremiah Doner, MISO’s director of cost allocation and competitive transmission, said MISO still finds that Future 2A is a valid “anchor” to its LRTP. But he said as with any 20-year planning scenario, MISO could conduct more analysis and scrutinize uncertainties. He said the IMM’s recommendation likely can be tackled through the course of stakeholder meetings on the second portfolio of the LRTP.

Minnesota Public Utilities Commission staff member Hwikwon Ham said MISO should outright reject the IMM’s recommendation. He said the IMM’s view of the future resource mix is based on a pessimistic view that “MISO members’ goals aren’t real and that decarbonization isn’t going to happen.” However, he said the Monitor’s opinion is increasingly implausible, as evidenced by Michigan Gov. Gretchen Whitmer (D) preparing this week to sign a bill requiring the state to reach 100% clean energy by 2040.

“This is going to be a real deal,” Ham said. “MISO should not waste its time on this.”

Other stakeholders said the IMM’s recommendation blurs the line between the duties of MISO’s Market Subcommittee and Planning Advisory Committee.

Work in Progress on Other Four

MISO was more receptive to the IMM’s four other recommendations in this year’s report.

MISO said it agrees with the advice that it ratchet up its excess and deficient energy deployment penalty charges, which Patton said are not high enough to dissuade generators from deviating from MISO’s dispatch instructions.

Xie said the MISO operations team is working on the design of a “follow dispatch flag” that will be sent to generators when they’re being dispatched down so they get a clearer signal to wind down output. Xie said the flag system will be MISO’s first step, and it will consider upping penalties in the future for generation that fails to curtail.

“Further evaluation and discussion are ongoing for the settlement incentives for the following dispatch,” she said.

Patton also recommended MISO expand its transmission constraint demand curves so its market dispatch system can better manage network flows.

Xie said an expansion of those curves likely will be contained in a larger filing that also will elevate MISO’s operating reserve demand curve and value of lost load. She said MISO could file with FERC for those changes sometime next year.

Patton has said MISO is missing out on valuable unrealized transmission flows because it’s forced to manually redispatch resources to manage constraints, especially when wind generation fails to scale back production on MISO dispatch instructions.

He said his recommendations will reduce flow uncertainty on the transmission system.

MISO stakeholders over the summer said MISO should introduce a software flag to let units more clearly know when they are being curtailed. Some said it’s not always apparent when MISO expects curtailment. Multiple stakeholders also said MISO sends incorrect dispatch instructions or instructions that don’t align with individual market participants’ offer curves.

Patton also recommended MISO improve its near-term wind forecasting to better reflect the characteristics of wind generation output. He said MISO uses a “persistence” forecast that assumes wind resources will produce the same amount of output as it most recently observed.

Xie said MISO will explore releasing more recent data through its interface to its forecasting vendors.

Finally, Xie said MISO agrees with the Monitor that it should establish a way for suppliers to submit annual offers instead of just seasonal offers in the new, seasonal capacity auction and rework some of its 31-day outage limit for generators per season.

Patton said MISO’s 31-day limit on non-exempt generation outages is causing some distortion in the capacity market because many suppliers this year deliberately adjusted their longer unit outages so they straddled seasons, thereby dodging penalties.

Xie said MISO plans to discuss with stakeholders a more “comprehensive participation model for resources looking for more flexible participation in the Planning Reserve Auction.”

She also said MISO will investigate modifying its outage penalty provisions and mitigation measures.

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MISO Continues to Find Mounting Retirements, Inadequate New Capacity in Abridged Resource Assessment

CARMEL, Ind. — In its third annual Regional Resource Assessment, MISO again found planned generation retirements continue to outstrip additions.  

MISO said though this year’s condensed RRA showed a slightly improved capacity picture, the survey still indicates a “continued capacity risk, highlighting the immediate importance of additional investment.”  

MISO said beyond what members are planning, the footprint likely needs an additional 13 GW of accredited capacity in 2027, 27 GW by 2032 and 34 GW in 2042 to fulfill demand.   

“Major trends from MISO members’ publicly announced plans remain unchanged compared to past RRAs, with wind and solar driving planned additions and coal comprising the bulk of planned retirements,” Laura Hannah of MISO’s strategy team said during a Nov. 7 Resource Adequacy Subcommittee meeting. Hannah said MISO also sees battery storage plans picking up steam since last year.  

MISO expects to have lost about 60 GW worth of installed capacity from mostly coal and gas resources through retirements by 2042, with retirements gathering speed around 2026.  

Over the same time frame, members told MISO they will add about 120 GW of wind, solar, battery storage and natural gas resources. However, the 120 GW of installed capacity will be whittled down to 50 GW in unforced capacity. MISO further qualified that its plans for a new, marginal-style capacity accreditation could further shrink that amount.  

“There’s a lot of moving pieces on accreditation,” Hannah said.  

According to MISO, its gas fleet won’t see much change by 2042. The grid operator said installed capacity of its natural gas resources is predicted to be about static, with an equivalent megawatt amount of planned investment and retirement announcements.  

Members serving a total 80% of the footprint’s load responded to the survey, up from approximately 75% last year. 

Through last year’s RRA, MISO said its members may need to build 200 GW in new installed capacity by 2041 to meet reserve requirements and achieve renewable targets and emissions-cutting goals (See MISO: 200 GW in New Capacity Necessary by 2041.) 

Hannah said the RRA analysis was “scaled back this year,” with MISO subbing its second transmission planning future for resource expansion modeling instead of performing a separate full-scale resource expansion modeling.  

Hannah said this year’s RRA was a “broad-brush” approach when compared to the previous two years’ reports. She said even though the resource expansion piece is an estimation, MISO remains confident in the long-term trends that this year’s and previous RRAs have exposed. She also said members reported only “modest year-over-year changes” in their generation plans.  

Some stakeholders asked if MISO would begin prioritizing generator interconnection requests that can sustain reliability and provide accredited, readily available capacity instead of simply installed capacity.  

Bill Booth, consultant to the Mississippi Public Service Commission, asked if MISO may consider linking its System Support Resource agreements with the footprint’s capacity needs; MISO’s SSR designations — where it orders retiring resources to remain online for the sake of reliability — are geared only toward the reliability of the transmission system. Booth said MISO is fast approaching “the iceberg” and asked if it was simply going to rely on states and load-serving entities to fill the planning gaps MISO foresees. 

Hannah said those ideas were beyond the scope of the RRA. Other staff said MISO’s ongoing work to quantify and prescribe specific amounts of resource attributes will deal with Booth’s and other stakeholders’ concerns. (See MISO Charting Course on Stimulating Generating Attributes.) 

MISO will collect stakeholders’ written reactions to the 2023 RRA through Dec. 31. 

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Bivens Resigns as ERCOT’s Market Monitor

The Texas Public Utility Commission and Carrie Bivens both confirmed Thursday that she is resigning as ERCOT’s Independent Market Monitor. 

It could be the first of several changes among those responsible for governing and monitoring the Texas grid operator. According to an article by Bloomberg, Will McAdams is “expected” to resign from the commission before the year is up. Rumors swirling in Austin indicate fellow Commissioner Lori Cobos could soon follow him out the door. 

Rich Parsons, the PUC’s communications director, said McAdams and Cobos both continue to “serve at the pleasure” of Gov. Greg Abbott (R). 

In a call to RTO Insider, McAdams expressed frustration with the Bloomberg story, which cited sources that requested anonymity. It comes as he is focused on preparing the ERCOT and SPP grids for winter; McAdams leads a senior leadership team assessing SPP’s current resource adequacy construct and making policy recommendations. 

“I continue, as I have been, to serve at the pleasure of the governor,” he said. 

Will McAdams takes in SPP’s Resource Adequacy Summit this summer. | © RTO Insider LLC

Thomas Gleeson, the commission’s executive director, confirmed Bivens’ pending resignation in a statement. 

“Carrie has done a great job as the Independent Market Monitor at a critical time for our state, balancing the urgent need for greater reliability in a way that protects our unique, competitive market,” he wrote, thanking her for her service. 

Bivens told RTO Insider the news of her departure was true but declined to comment further.  

Potomac Economics’ David Patton said in an email that Bivens resigned from the eight-person IMM to “pursue other opportunities.” He said the deputy director will manage the team while Potomac searches for a new director, but that day-to-day monitoring work will not be affected.

“She was an outstanding director, and we all wish her the best,” he said.

Potomac currently holds ERCOT’s market monitoring contract, which expires in December. The consulting firm is the only respondent to the PUC’s request for proposals to a four-year contract that begins in January.

Parsons said the commission is proceeding through the RFP process and cannot comment on specific details unless or until a contract is signed. 

“Let me just say that during her time as the IMM director, Carrie has had to deal with way bigger and thornier issues than either Dan [Jones] or I dealt with,” said Beth Garza, Bivens’ predecessor. Dan Jones preceded Garza, who, like Bivens, resigned her position. 

Bivens tangled with both the PUC and ERCOT leadership in recent years. She cast doubt on the performance credit mechanism pushed by former PUC Chair Peter Lake. Last month, she defended an IMM report before the ERCOT board that said its newest ancillary service “likely” raised the real-time market’s energy value by at least $8 billion. (See ERCOT Board, IMM Debate Ancillary Service Costs.) 

A departure by either McAdams or Cobos could be more problematic. According to sources in Austin political circles, both have been frustrated with their roles on the commission and the amount of work the state’s lawmakers have sent their way. 

“The magnitude and complexity of the PUCT’s responsibilities have increased significantly,” said energy consultant Alison Silverstein, a former PUC and FERC adviser. “If McAdams feels it’s time to move on, then that’s a big loss for the people of Texas and the electric industry. That loss would be compounded if … we lose [Cobos] and her experience and expertise.”

The two commissioners said reports of their departure are false.

“I deeply value and rely on the strong working relationships I have with state leadership and members of the Texas Legislature,” McAdams, a former staffer at the Capitol, said in a statement. “The legislature’s guidance has been and remains invaluable in strengthening the ERCOT grid. I’m also grateful for the additional funding and resources the legislature has granted the PUCT, which allows us to grow and take on more responsibility to ensure Texans have the reliable electric grid they expect and deserve.”

“I remain fully committed to serving on the [PUC] and serving the people of Texas to ensure a reliable, resilient, and affordable supply of electric power,” Cobos said. “I greatly value the important work that the Texas Legislature has accomplished over the past two legislative sessions to help ensure grid reliability in our state and look forward to continuing to work with the Texas Legislature to implement their important legislation.”

This week’s passage of a constitutional amendment that essentially sets up the PUC as a bank managing billions of dollars adds another layer of difficulty to the commission’s responsibilities. (See 2023 Elections Bring Billions for Texas Gas, Dem Wins in Virginia, NJ.) 

However, the PUC said lawmakers have provided it with additional funds for a 49-person staff increase, effective Sept. 1. That includes full-time staff devoted to legislation passed during the 2023 session. Salaries account for the bulk of the 56% budget increase for the 2023-2025 biennium.

The commission has added 25 positions since the end of the last session in May, growing its headcount to 225.

“The PUC will continue to add [staff] over the course of the biennium, but it will take time to complete the expected growth,” the commission’s Ellie Breed said in a statement. “In addition to the time it takes to post and fill positions, we need to allow time for onboarding and training new employees in the PUC’s complex subject matter.”

Stoic Energy CEO Doug Lewin said the rumors surrounding the PUC just add to the state’s uncertain regulatory environment. 

“Regulatory uncertainty is a is a major problem in ERCOT right now,” he said. “If you look at the huge amount of money in the market, particularly this year, but last year too, these were big years for generators. If you had a strong regulatory signal that the competitive market is going to continue to share it … I think you would be seeing a lot more investment. But I think a lot of what’s happening is they’re like, ‘Is [the market] going to be bad? Is it going to be something we’ve never heard of before? What is this performance credit mechanism?’ So, I do think that regulatory uncertainty is a drag on investment.” 

[This story was updated Nov. 11 to add comments from Commissioners McAdams and Cobos.]

 

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FERC Dives into Reliability Implications of EPA’s Power Plant Rule

FERC commissioners and the industry and state witnesses before them at the commission’s annual reliability technical conference Nov. 9 were split on whether EPA’s latest greenhouse gas rule for power plants can be implemented reliably and affordably.

Chair Willie Phillips opened up the afternoon’s panels focused on EPA’s proposal under Clean Air Act Section 111(d) by noting that FERC’s first job is to maintain reliability. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.)

“For half a century, EPA has set and enforced the emission standards that apply to every power plant in the nation,” Phillips said. “We remind ourselves again, at the outset of this conference, that our piece of the electric power puzzle is defined by the Federal Power Act. We do not build, certificate or authorize the construction or retirement of power resources. That responsibility lies with the states. We also do not have the authority to second-guess EPA’s regulatory choices.”

FERC’s task was to better understand how the rule would impact the grid going forward, with the knowledge that predicting future outcomes is a “fraught task,” he added.

Joseph Goffman, principal deputy assistant administrator for EPA’s Office of Air and Radiation, laid out the details of the rule, which he noted was still under development and would likely change before it is finalized.

“The proposed carbon pollution standards are in fact crucial to addressing the urgent need to reduce climate-destabilizing carbon dioxide pollution from the power sector,” Goffman said, “and an important part of the agency’s broader efforts to address the multiple health and environmental impacts of the power sector, while supporting the continued delivery of reliable and affordable electricity.”

The proposal includes varying compliance levels for coal and gas plants that depend on how long they plan to keep running and how often they are actually dispatched by grid operators, Goffman said. The rules will allow the industry to keep building uncontrolled combustion turbines needed to meet peak demand, while the only coal plants facing the strictest requirements are those that keep running past 2040.

The rule will also be implemented by states’ environmental agencies, and they will have some flexibility to make the rules workable. EPA is also proposing a transparent exemption process for units critical to reliability that cannot comply with the rule — as it did for the Mercury and Air Toxics Standards (MATS) a decade ago, Goffman said.

“I like to think about us as being maybe in the fifth inning of this process,” Goffman said. “We haven’t even gone to the bullpen yet. So, there’s a lot of work that we still understand that we must do on the path to finalizing these rules. And we are committed to engaging with reliability stakeholders as we develop the final rule.”

The last half of the game will involve EPA iteratively refining its rule and turning to FERC, state regulators, the industry, grid operators and others to get their expert opinions on any changes, he added.

The rule would require the longest-lived and most used fossil power plants starting in the 2030s to use carbon capture and storage (CCS), or clean hydrogen at scales that have yet to be proven for either technology. Their lack of viability has been a common criticism, and Phillips asked Goffman to address it.

EPA has designated those technologies as the “best system of emission reduction,” but states will ultimately get to pick the strategies that work for them. Both CCS and clean hydrogen have significant federal backing under the Inflation Reduction Act as well, Goffman said.

“We’ve had reports from various RTOs, in fact, almost all of them, that they’ve had unexpected retirement rates that they didn’t anticipate,” said Commissioner James Danly. Coupled with the difficulty of fully using all the incentives from the IRA and issues around interconnection, it is likely that law will not fully spur the massive growth in new clean energy some have predicted, he argued. Thus, the process of replacing the emitting plants with new clean capacity will not be as robust as EPA might think.

FERC Commissioner James Danly questions EPA Assistant Administrator Joseph Goffman at Thursday’s technical conference. | FERC

“You’ve laid out a lot of issues that I think we are going to have to address in terms of how we account for potential retirements,” Goffman replied.

Even without EPA’s rule, those issues are going to be facing FERC as the industry is transitioning away from fossil fuel to renewables and other cleaner resources because of other policies and market forces, said Commissioner Allison Clements.

“We face the need for markets to evolve to send the right signals to provide resources with the revenue certainty and to provide services we need,” Clements said. “That’s within FERC’s jurisdiction and is in need of change before we even get to this policy.”

Finalizing compliance with Order 2023 will help on that front, and FERC could also take up issues around retirement notifications to help remedy that issue, she added.

Less Room for Error

PJM released a paper early this year, before EPA released its proposal, projecting it would see 40,000 MW of retirements by the end of 2030, but it has already seen some announced retirements since then that it was not expecting, so the actual numbers could be bigger, said Mike Bryson, the RTO’s senior vice president of operations.

“We look at certainly the impact of the IRA, which I appreciate has a lot of stimulus in there,” Bryson said. “But we also look at the Ørsted announcement about Ocean Wind 1 and Ocean Wind 2 — 7,500 megawatts, which was supposed to be replacement megawatts.” (See Ørsted Cancels Ocean Wind, Suspends Skipjack.)

While PJM’s markets worked to help reliably transition its fleet from the MATS rule, which led to significant retirements of coal plants, its markets are different now. The reserve margin is thinner, and there is less room for error this time around, Bryson said.

Other industry speakers were more blunt, with Eastern Kentucky Power Cooperative CEO Tony Campbell, who was testifying for the National Rural Electric Cooperative Association, calling the rule “unlawful, unworkable, beyond salvage and disastrous for grid reliability.”

“Even if we put aside the enormous cost involved, the proposed rule relies on CCS and clean hydrogen, neither of which are ready at levels and scales for a sound economy that requires certainty, and not in all regions of the country,” Campbell said. “The infrastructure needed for both technologies is not now and will not be in place at the scale to meet EPA deadlines.”

Beyond the costs, both technologies need pipeline infrastructure, which has not been easy to build for natural gas, and that at least has an established regulatory regime, he added.

Campbell was not alone in questioning the rule’s legality, but Edison Electric Institute Vice President General Counsel Emily Sanford Fisher said that issue would ultimately be decided in the coming years in the courts.

EEI’s investor-owned utility members have embraced the clean energy transition, with Fisher noting the industry has met the goals of the Clean Power Plan even though it never it went into effect, and 2022 saw emissions equal to 1984’s.

“Regardless of any final EPA regulations addressing greenhouse gas emissions from … the fossil generating fleet, the clean energy transition is not going to be easy,” Fisher said. “Challenges do not mean, however, that this transition is impossible, or that our larger goals about a resilient equitable, affordable, clean energy future should change.”

Those challenges will require working across myriad stakeholders to address them, and the industry and policymakers should be prepared for some “bumpy” progress occasionally, she added.

EPA is likely paying close attention to the legal issues around its rule, given its experience with the Clean Power Plan being overturned, noted Analysis Group Senior Adviser Susan Tierney, who had released a paper before the technical conference explaining how the industry could meet the proposed rule’s requirements reliably. It echoed arguments she made for other EPA rules issued under the Obama administration.

“In each instance in the past dozen years, the industry and other stakeholders predictively stepped up to ensure that actual reliability was not compromised,” Tierney said.

Some of the particulars this time are different than in the past, but there are also reasons to be assured that a final EPA rule will not jeopardize reliability, she added.

Colorado is well underway to deep decarbonization, pushed by state policy and being one of the few states to benefit from plentiful wind and solar without the need for massive transmission lines, said its Energy Office’s executive director, Will Toor. It expects all coal plants to be retired before EPA’s requirements kick in, while its natural gas fleet will operate at low capacity factors, balancing a growing share of wind and solar.

“We do believe that it will be important as the EPA finalizes the rules to ensure maximum flexibility for states to comply in the most cost-effective manner,” Toor said. “We urge EPA to maximize the ability of states to use trading, massive rate-based averaging and other approaches. This should include an ability for states to recognize the changing use of existing gas plants over time.”

By 2030, only one gas unit in the state is expected to approach a 20% capacity factor, which falls to 11% before the end of that decade, he added.

“I’ve got to believe that before you get investors in, a 20% capacity unit is going to be rate based, and therefore the owners are going to be guaranteed cost recovery,” said FERC Commissioner Mark Christie.

Toor answered yes, and Christie noted that no investors are going to want to build additional natural gas plants that run so rarely. But Toor said his state has found that is the cheapest way to operate the grid going forward, even including the total costs of natural gas plants.

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100% Clean Energy, Renewable Siting Bills Heading to Michigan Governor

LANSING, Mich.— Legislation requiring Michigan to meet a 100% clean energy standard by 2040 and giving state regulators siting authority for large wind and solar energy projects is headed to Gov. Gretchen Whitmer (D).  

The Michigan Legislature completed work on the siting bills, HB 5120 and HB 5121, on Nov. 8, with the Senate’s approval on a 20-18 vote with only Democrats in support.   

Last week, lawmakers — again with just Democratic support — approved a package of bills:  

    • SB 271 requires electric providers to achieve a clean energy portfolio of at least 80% and 100% in 2040. It also sets a statewide energy storage procurement target of 2,500 MW and increases the cap on distributed generation such as rooftop solar to 10%.  
    • SB 273 requires utilities to boost their energy-efficiency savings from 1% to 1.5%. 
    • SB 502 requires the PSC to consider environmental justice, climate, affordability and reliability in its decisions on utility integrated resource plans.  
    • SB 519 creates a Community and Worker Economic Transition Office in the Department of Labor and Economic Opportunity to help retrain auto, energy and construction workers who lose jobs because of the switch to electric vehicles and efforts to reduce greenhouse gas emissions.  
    • SB 277 codifies an existing state rule allowing farmers to remain enrolled in the state farmland preservation program even if they rent their land for solar farms.  

According to the Clean Energy States Alliance, Michigan will become the 16th state to legislate 100% clean energy goals.  

In 2022, Michigan got almost 23% of its electricity from nuclear power and another 9.5% from wind, solar and hydropower, according to the Energy Information Administration.  

Michigan bills

| Energy Information Administration

Whitmer issued a statement indicating she would sign the bills, which she said makes Michigan “a national leader on clean energy.”  

“These bills will help us make more clean, reliable energy right here in Michigan, creating tens of thousands of good-paying jobs, and lowering utility costs for every Michigander by an average of $145 a year,” she said. “Getting this done will also reduce our reliance on foreign fuel sources, while protecting our air, water and public health.” 

Environmental groups criticized legislators for changing the 100% deadline from 2035 and defining landfill gas and incinerated waste as renewable energy. They also criticized allowing generators to continue using natural gas-fired generation after 2040 if they include carbon capture systems. 

But clean energy advocates were generally pleased with the final products. Lisa Wozniak, executive director of the Michigan League of Conservation Voters, said the bills puts Michigan among the top of all states in pushing for energy conservation.  

Derrell Slaughter, with the Natural Resources Defense Council, said the bills will help cut energy costs for state residents after “being plagued for decades with the worst service and highest rates” in the Midwest. 

The entire package has been controversial, with Republican opponents charging that Michigan residents will face higher energy costs and less reliability. The Mackinac Center for Public Policy, a conservative think tank based in Midland, argued that even if all the energy savings requirements go into effect, they will have little effect on curbing climate change. 

Most controversial were the siting bills, with both local government organizations and agricultural interests opposing them. Local government groups argued the measures were a state overreach on local decision-making and would deny local residents any say in how local property is developed. Agricultural groups charged the measures would reduce the amount of land being used for farming. (See Mich. Energy Siting Bills Set off Opponents and Backers.) 

But disputes over permitting new wind and solar projects in primarily rural areas led lawmakers to draft the measure giving the state Public Service Commission authority over siting of solar projects of 50 MW or more, wind facilities of 100 MW or more and energy storage facilities of at least 50 MW with a discharge capacity of 200 MW or more.  

PSC Chair Dan Scripps testified Nov. 7 before a Senate committee that the siting rules must change for the state to meet its climate goals. He said the state would need up to 209,000 acres of additional wind and solar — “a big number,” he acknowledged, but only 0.55% of the state. 

There has been no indication of how opponents might try to block the package.  The Legislature did not appropriate any funding in the bills to enact the proposals, which means under Michigan’s constitution opponents could try to hold a voter referendum on the bills.  But the petition requirements — directing that a sufficient number of petition signatures be collected and certified by the state before the bills take effect — make that a tough hurdle to overcome.  

A court challenge to the constitutionality of the provisions is possible, but no group has so far suggested a suit is coming. 

Because only Democrats supported the bills, they will not go into effect immediately after they are signed by Whitmer. However, the Legislature is planning on adjourning sine die some six weeks earlier than usual, which means the bills could go into effect by February.  

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California PUC Partners with State Workforce Agency to Advance Green Jobs

The California Public Utilities Commission has stepped up its coordination with the state’s Workforce Development Board (CWDB) to ensure that new clean energy jobs build pathways into the middle class for the disadvantaged communities that bear a disproportionate share of climate change impacts. 

The two agencies discussed their partnership in an Oct. 17 Environmental and Social Justice High Road Workforce En Banc workshop, which included panels covering tribal workforce development, utility efforts to promote jobs in energy and more.  

The CPUC and CWDB have been working independently and together for the past several years to advance what they call “high road careers” that address climate change. In 2019, the CPUC adopted its Environmental and Social Justice Action Plan, while the CWDB in 2020 released Putting California on the High Road, a plan for integrating economic and workforce development in climate policy to meet California’s greenhouse gas emissions targets by 2030 and achieve a carbon neutral economy by 2045. Both plans emphasize labor as an investment — not a cost — that can positively affect returns on social equity and climate action.  

In 2020, CPUC and CWDB signed a Memorandum of Understanding following Democratic Gov. Gavin Newsom’s Executive Order N-79-20 to accelerate climate change mitigation and build a more sustainable and inclusive economy. The MOU aims to build a framework to ensure investments in clean energy result in high-quality jobs and greater access to career opportunities for disadvantaged Californians.  

The MOU “really focuses on the role of agencies like the CPUC as an influencer on the kinds of jobs that are created as we implement our green and climate policies and our funding programs,” Carol Zabin, senior advisor for the UC Berkeley Labor Center’s Green Economy Program, said at the workshop. “That, to me, is by far the key element that we need to focus on.”  

Zabin said about three-quarters of the jobs involved in energy efficiency and renewable energy generation work are blue-collar, which, without unions or strong labor standard requirements, tend to be “low road,” low-wage positions with poor benefits and a lack of upward mobility. One of the goals laid out in the CWDB’s 2020 report is a just transition for blue-collar workers into the climate and energy workforce.  

The MOU in Action

CPUC Executive Director Rachel Peterson described one step the agency took to advance the goals in the MOU: the 2019 rollout of the Solar on Multifamily Affordable Housing (SOMAH) Project. The program provides financial incentives for installing solar panel systems in disadvantaged communities, identified as the 25% most pollution-burdened census tracts in the state, according to CalEPA’s environmental health screening tool CalEnviroScreen. More than 35,000 tenants have benefited from the program. 

But SOMAH also provides job training opportunities, with 850 individuals participating in paid job training on solar panel installation.

The commission also emphasized its work with Pacific Gas and Electric to train line clearance tree trimmers, who prevent vegetation from obstructing electrical lines. As part of a $1.97 billion settlement for PG&E’s role in the 2017 and 2018 fires in Northern California, the CPUC ordered the utility to start a multiweek training program for pre-inspector training and certificates. PG&E also was required to create a tree crew training and certificate program in partnership with the International Brotherhood of Electrical Workers.  

Representatives from the California-Nevada Joint Apprenticeship Training Committee (JATC) Line Clearance Tree Trimmer Certification program emphasized the importance of vegetation management in wildfire prevention. Despite the tangential connection between climate-caused wildfires and those sparked by electrical lines, Dan Kallai, training coordinator with JATC, said the position was crucial to climate mitigation.  

“Line clearance tree trimmers are directly mitigating the effects of climate change and reducing the number of wildfires and associated carbon emissions,” he said. “Furthermore, they keep the power grid running safely and efficiently by preventing power outages and the costly loss of our electrical resource to ground faults.”  

The program also is succeeding in creating high road careers. In 2019, SB 247 brought vegetation management under the scope of wildfire mitigation in California, and in January 2020 the law raised tree trimmer wages to match those of electrical utility linemen apprentices, giving them “skilled labor” status. Since January 2022, more than 2,300 people have enrolled in the program.  

Collaboration with Tribal Communities

California officials also are working to create access to high road careers in green energy in the state’s tribal communities. 

“There’s so much opportunity to partner with tribes, elevate tribal perspectives and learn from tribal experiences, but we can’t do this without first acknowledging the historical elephant in the room that the state has a lot to make up for in terms of tribal wellness and government integrity,” said Christina Snider-Ashtari, tribal affairs secretary to Newsom. “How do we start to disentangle that and provide more equitable access, more equitable job creation and workforce in those areas from a Native perspective, not from the perspective of a government that is responsible for those problems?” 

Grid Alternatives, a nonprofit solar organization with a mission to advance environmental justice through access to renewable energy, is looking to address that question.  

The organization partners with tribes to finance and implement solar projects that include education, training and energy cost reductions. Since 2010, Grid Alternatives has helped 50 tribes install 7.7 MW of power across eight states. Its grant program, the Tribal Solar Accelerator Fund, has awarded $7.3 million for a variety of solar-related projects, including helping tribes own their systems, as well as providing funding for scholarships, internships and workforce development opportunities in the solar industry.  

Next Steps

While some programs already have succeeded in advancing workforce development in climate-related careers, there is more to be done to ensure the goals outlined in the MOU are achieved. The CPUC and CWDB recognize the challenge of measuring future outcomes.  

“How do we know that people have actually moved into a high road career pathway?” Peterson said. “I’d like to see three years from now, four years from now, that people have been able to take advantage of these pathways.”  

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Brad Jones, Former ERCOT, NYISO CEO, Dies at 60

Friends, co-workers and others who had known former ERCOT and NYISO CEO Brad Jones recalled his memory Nov. 9, after his sudden death the day before.

Jones, 60, passed away in Houston’s MD Anderson Cancer Center of a rare intestinal cancer with a high mortality rate. The cancer was thought to have been in remission last year when he retired from ERCOT but returned late this summer.

“He’s one of the most charismatic, selfless leaders I’ve ever had the chance to work with,” said ERCOT’s Kristi Hobbs, vice president of system planning and weatherization. “He didn’t know a stranger. Everyone was his friend. He was truly about serving others, providing them development opportunities. He always had the best interest of the market and the industry in everything he did.”

Jones had two stints at ERCOT after a distinguished career at TXU (now Vistra). He served as the ISO’s vice president of commercial operations and COO from 2013-2015. Jones left ERCOT for NYISO before retiring in 2018, only to return to ERCOT as its interim CEO following the deadly 2021 winter storm.

He is widely credited with restoring confidence in the grid operator and laying out initial steps to prevent a repeat of the disaster, which almost brought the ERCOT grid to its knees. Part of that work included a listening tour around the state to share the message with Texans.

“It was really the organization’s darkest hour,” Hobbs said, noting her reluctance to use that expression. “He was our angel that was sent to us to help us navigate through that and rebuild the faith and all the good work of that organization. We can’t think of anybody else that would have been better suited for that role to help us during that time.

Brad Jones, with Pat Wood, had many friends within the Texas electric industry. | Gulf Coast Power Association

“And for that we’ll be forever grateful,” Hobbs added. “Brad was one of my best friends and mentors.”

ERCOT recognized Jones with a memoriam section on its website, linked from the home page.

“No words can express our sadness for this loss, and our gratitude for the opportunity to have known and worked with him,” the ISO said. “Brad was a friend, a colleague, a leader and a genuinely caring person. He touched the lives and careers of many ERCOT employees and industry colleagues. He will be dearly missed.”

Mike Greene, a 46-year veteran of the ERCOT market as a TXU executive and the ISO’s board chair, knew Jones for more than 30 years. He was one of the close associates who got a call from Jones during the Dallas Cowboys’ Oct. 29 game, alerting him that Jones had little time left.

“He’s always been a very confident guy and always did a great job in whatever job he was in,” Greene said. “We all think of Brad just in the job that he did following Winter Storm Uri. He did such a great job of pulling things together and giving the industry confidence. It was just an incredible job that he did. I told him I considered him a real Texas hero for that. It was tough. It took a lot of guts, a lot of confidence and a lot of ability to get it done.”

Jones was honored by politicians, regulators and industry leaders before retiring again in October 2022. During the Gulf Coast Power Association’s spring conference in April, he was presented with the Pat Wood Power Star Award by its namesake, former PUC and FERC chair Pat Wood III.

“Brad was fearless, decisive and passionate,” Wood said. “First, he saved Texas, and then he saved ERCOT.”

“Ever since Pat Wood got this award, I wanted it,” Jones said of the honor established in 2006 to honor individuals for advancing a fair and sustainable power market. “I hoped I could do something sometime that I could earn it. I realized you can’t do it alone.”

Jones was a devoted family man and a man of faith, Greene said. He was a father of six with his wife, Lynette, but still managed to keep a work-life balance that focused on family first.

Family First

Chris Schein, a friend and co-worker of Jones for 20 years, tells the story of a recent call he received from a man who had met Jones twice, for about two hours each time. The two men, both with large families, talked about how to succeed at work while also helping manage large families.

“Always make your family your first priority. Everything else will work out,” Jones advised.

“Yes, but my work is so demanding,” the man responded.

“Yeah, but it will work out. You’ll never regret the extra time you spend with your family.”

“This guy implemented Brad’s plan in early spring and said, ‘My family and I have never been happier,’” Schein recounted. “‘I only spent a few hours with Brad, but he literally changed my life. I’ll be remembering his advice throughout my career.’”

Veteran ERCOT stakeholder Mark Dreyfus, principal at MD Energy Consulting, last year recalled visiting the West Texas native in Albany, N.Y., after he had “packed up his cowboy boots.”

“I know he was lonely for home and family,” Dreyfus said during yet another celebration for Jones. “He treated me like family and treated me to an insider’s tour of the city: well-cooked sirloin, beer pong, and a reggae show.” (See “GCPA Members Honor Jones,” Overheard at GCPA’s 37th Fall Conference.)

Brad kept his cancer to himself and only those closest to him when he was first diagnosed last year. During his last board meeting in October, while his cancer was in remission, he told one former co-worker that his target for beating the disease was Nov. 26, his birthday.

Greene recalled a lunch in Fort Worth he and several other ex-TXU employees hosted for Jones during the summer. He said Jones was feeling great and was enjoying time with his family.

“September rolls around, his cancer has returned and it’s bad. We had a 10-minute conversation the first part of October. It was very emotional,” Greene said. “During the Cowboys’ game, it was a very different conversation. He started talking in a very calm voice. It was like he was describing a project to me. He said, ‘I’m feeling good, I’ve had time to be with my family, and I’m very grateful for this time.’

“It was the darndest thing. He was totally at peace. It was amazing. The last thing I told him, ‘You’re a braver man than I am.’”

Schein said Jones was a huge fan of Teddy Roosevelt. When he got his last call from Jones, Schein said Jones remarked that his Twitter feed was full of posts on Roosevelt during the weekend because it was the latter’s birthday.

“Brad said, ‘Teddy was also 60 years old when he died. I’m going to be 60 when I die. That’s one more thing that Teddy and I shared,’” Schein said.

“I told him, ‘I really wish you had admired George Burns. He was 99 when he died.’”

Schein and Greene have worked together to establish The Brad Jones Engineering Scholarship at Texas Tech, his alma mater. The scholarship fund is intended to honor Brad’s legacy and to reward junior-level engineering students and support them in continuing “the important work in the electric industry and for Texas, now and in the future.”

“I think that’s the best way that we can honor his legacy,” Hobbs said. “He was a selfless leader. He always wanted to give back and develop others. This is the best way to honor his legacy and keep it alive.”

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FERC Conference Highlights Challenges of Evolving Grid

Combating the “unprecedented” cybersecurity threats facing the North American power grid “requires constant monitoring and vigilance,” FERC Chair Willie Phillips reminded attendees at the commission’s annual Reliability Technical Conference Nov. 9. 

“The average cost of a data breach in 2023 was $4.45 million, and the global cost of cybercrime was estimated at $8 trillion in 2022, $11 trillion in 2023 and is predicted to be more than $20 trillion in 2026,” Phillips said. “Quite simply, this is a national security issue. And these quickly evolving threats present a challenge when assessing whether security controls adequately respond to the latest cyber threats.” 

The rapidly changing cyber and physical threat landscape comprised one of the three key issues addressed at the conference, along with the reliability risks posed by extreme weather and the power grid’s changing resource mix. Participants in one morning panel, including Electricity Information Sharing and Analysis Center CEO Manny Cancel, emphasized the “unprecedented” level of danger posed to the grid by both foreign states and organized criminals. 

Manny Cancel, NERC | FERC

Cancel said the willingness of nation-state actors to target the North American grid “isn’t subject to debate,” referring to the U.S. intelligence community’s 2023 Annual Threat Assessment, which identified China, Russia, Iran and North Korea as conducting active cyber campaigns against the U.S. and its allies. China, Cancel said, is believed to have sponsored attacks against multiple U.S. critical infrastructure organizations and Asian electric utilities, while the E-ISAC has detected “Russian-linked scanning in [its] information technology and operational technology systems … searching for security gaps.” 

While the sponsorship of hostile governments has enabled greater creativity from malicious actors, they also have benefited from a growing attack surface created by the addition to the grid of new, internet-connected generation types such as wind and solar facilities, along with distributed energy resources such as rooftop solar panels. These facilities have helped enable a faster transition to a lower-emission grid but constitute a potential vulnerability for adversaries to exploit.  

“When you think about it from a pure numbers perspective, you’ll have a larger coal plant retiring that may be 300 [to] 800 MW, and obviously what’s coming online … is more. [Wind and solar facilities] tend to be smaller plants,” said SERC Reliability CEO Jason Blake. “In addition to that they’re [also] more digitized. They need additional tools to perform their functions.” 

Despite these risks, Blake said he remains “comfortable and confident” in the ability of grid operators to adapt to the evolving threats because NERC’s Critical Infrastructure Protection (CIP) standards “provide a very strong base” for grid cybersecurity. However, Blake and his fellow panelists also acknowledged there still is work to be done, particularly in updating the CIP standards to allow the use of cutting-edge technology in grid operations. Maggy Powell, a principal security industry specialist for Amazon Web Services, said CIP standards “are very device-centric” and “were written without contemplating virtualization [and] before cloud [computing] was really a thing.” 

Jonathan Tubb, director of industrial cybersecurity for Siemens Energy of North America, added that in his experience utilities are looking for “lighter weight and scalable solutions” to address the cyber needs of large-scale distributed generation. But even if these solutions are available, he said, operators may feel unable to make use of them because of compliance concerns. He urged NERC and FERC to push for changes to the CIP standards that will allow the use of flexible distributed cyber defense software. 

Robb Highlights IBR, Gas Issues

In the morning’s other panel, which focused on the grid’s changing resource mix, NERC CEO Jim Robb acknowledged the “paradoxical” fact that “although the [grid] is performing exceptionally well,” with misoperation rates and human errors down and transmission availability rising, “all of our reliability assessments show an expansion of risk, both geographically and [in] severity.” He attributed the growing risk “largely … to grid transformation,” particularly the spread of inverter-based resources like wind and solar plants. 

NERC CEO Jim Robb | FERC

While Robb said these new generation sources are “incredibly exciting technologies,” he warned that they come “with real issues.” In addition to their potential cyber vulnerability, the behavior of IBRs is not as well understood as that of older generation types, which has prevented their full integration into system models and simulations.  

Robb also acknowledged the recent release of FERC and NERC’s report on Winter Storm Elliott, which he called “very sobering.” (See FERC-NERC Elliott Report Calls Winter Outages ‘Unacceptable’.) He reflected that while the “heroic” actions of gas and electric utilities kept the natural gas system from collapsing under the strain of the storm, if temperatures in the Northeast had not warmed up when they did, the grid could have “been in a real world of hurt.”  

The difficulties of gas and electric coordination during Elliott pointed out another area where work is needed, Robb said. He reiterated his support for the formation of a gas reliability organization that could create mandatory standards similar to the ERO and called for NERC and other industry stakeholders to continue working with the gas industry to improve their collaboration efforts.  

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PJM Monitor Petitions FERC to Change Capacity Performance Penalty Calculation

PJM’s Independent Market Monitor on Nov. 7 filed a complaint with FERC against the RTO arguing that its Capacity Performance (CP) construct for incentivizing generation performance during emergencies through penalties and bonuses is overly punitive and undermines reliability (EL24-12).

The Monitor told the commission the penalty rate calculation, based on the cost of new entry (CONE), should be revised to be based on the Base Residual Auction (BRA) clearing price instead. The penalty rate would be set to the clearing price per megawatt-year divided by the number of intervals in 30 hours for each interval a resource is unavailable, with an annual stop loss set at 1.5 times the resource’s annual capacity revenues.

While the capacity market overhaul PJM filed with FERC on Oct. 13 would set the stop loss at 1.5 times capacity revenues, the Monitor noted that it would base the penalty rate on CONE and argued that it would continue to expose market sellers to “excessive nonperformance penalties.” The Monitor also said the proposal ties too many changes to the Reliability Pricing Model (RPM) too quickly for the markets to properly adjust to, increasing uncertainty and the risk that unintended consequences may be introduced. (See PJM Files Capacity Market Revamp with FERC.)

“Because PJM has repeatedly failed to propose rules that would correct its flawed market design, this complaint is necessary to remove the flawed rules for penalty rates in the existing rules, adopt just and reasonable replacement rules, and maintain the existing schedule for RPM auctions,” the Monitor said.

The IMM argued that lowering CP penalties has broad stakeholder support, noting that the Members Committee endorsed an identical change to the penalty structure. PJM’s Board of Managers, however, opted to file changes only to the triggers that initiate a performance assessment interval (PAI), during which generators are subject to penalties for underperforming. While no proposals received sector-weighted support during the Stage 4 meeting of the Critical Issue Fast Path (CIFP) process Aug. 23, the Monitor said its proposal to base CP penalties on capacity revenues was the only one to receive more than 50% support. (See PJM Stakeholders Vote Against All CIFP Proposals.)

During the discussions at the Markets and Reliability Committee in May, stakeholders calculated the changes would result in a penalty rate of $394/MWh and a stop loss of $17,744/MW-year, compared to a status quo penalty of $3,177/MWh and stop loss of $142,952/MW-year, based on 2023/24 clearing prices.

Revising the penalty calculation would reduce market risk and the potential for PJM to be involved in lengthy litigation in the event major penalties are incurred in the future, while also creating market certainty for the next two delivery years in a way that is straightforward for market participants to understand, the Monitor argued. It requested its proposal go in effect for the 2025/26 delivery year, as well as the following one.

The Monitor said the high penalties have undermined the goal of the CP construct of incentivizing performance during emergencies and instead created artificial risk that resulted in increased costs for consumers without a corresponding reliability benefit.

“Abstract discussions of incentives and penalties led some to the conclusion that if high prices provide incentives at times, then even higher prices or extreme penalties are even better incentives. One of the lessons of the winter storms Uri [of February 2021] and Elliott [of December 2022], in very different market designs, is that extreme prices and penalties do not have the intended incentive effect and do have a destructive effect, in the energy market and in the capacity market,” the Monitor said.

The RTO itself has identified flaws in the penalty rate, the Monitor argued, pointing to its response to the 15 complaints that generation owners filed in the wake of $1.8 billion in penalties being assessed against market sellers because of their underperformance during Elliott. (See Settlement over PJM Elliott Penalties Receives Broad Support.)

“PJM nominally defended its actions related to determining the existence of PAI, associated penalties and acceptable excuses,” the Monitor said. “Yet PJM implicitly agreed that the combination of high penalties and unclear rules made the results of nonperformance assessments during Winter Storm Elliott unworkable when, after multiple detailed and extensive complaints were filed at the commission raising specific questions about PJM’s implementation of the PAI rules, PJM proposed to immediately begin settlement judge proceedings and, after actively participating in those proceedings, entered into and filed a settlement agreement.”

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NERC: Grid Risks Widespread in Winter Months

The winter storms of recent years are weighing on NERC leaders’ minds heading into the 2023-2024 winter season, with the ERO’s 2023 Winter Reliability Assessment warning that much of the North American continent faces elevated or high risk of energy shortfalls during extreme weather conditions. 

The assessment, released Wednesday, covers the months of December through February and was developed by subject matter experts within the ERO’s technical committees and industry groups, NERC Director of Reliability Assessment and Performance Analysis John Moura said in a media call. Moura said the report spotlights worrying trends around reliability. 

“For decades, the system has mostly been built and planned around summer peaks, the concept there being that we have higher demand during the summer period, and therefore we need to make sure we’ve got a lot of capacity to serve that demand,” Moura said. “However, what we’ve seen in … probably the last 10 years is an increased vulnerability to wintertime. That’s not because of the peak demands … but mostly because of generator outages” from cold weather. 

Natural gas-fired generation capacity contributions to the 2023-2024 winter generation mix | NERC

Moura acknowledged that the assessment was released “on the heels of” Tuesday’s publication of the final report from FERC and NERC’s joint inquiry into the winter storm that caused more than 90 GW in coincident unplanned outages over Christmas 2022, also known as Winter Storm Elliott. (See FERC-NERC Elliott Report Calls Winter Outages ‘Unacceptable’.) He noted that the Elliott report “reiterated some of the very same findings we’ve seen year after year during these winter impacts,” including inadequate winterization of generation plants and disruptions to fuel supply, particularly for natural gas facilities. 

Those issues appear again in the assessment, which highlights the fact that declining natural gas production during Elliott contributed “to wide-area electricity and natural gas shortages.” Mark Olson, NERC’s manager of reliability assessments, said that while “nearly all areas have adequate resources for normal peak demand,” extreme, long-duration cold weather events could lead to similar disruptions this winter, despite industry efforts to prepare for the worst. 

Multiple Regions Face Elevated Risk

NERC noted that SPP, MISO, ERCOT, PJM and parts of the SERC Reliability and Northeast Power Coordinating Council regional entities are all at elevated risk, indicating the potential for insufficient operating reserves in above-normal peak conditions. Only Canada’s Saskatchewan province was assessed as high risk, meaning energy shortfalls could occur during normal peak conditions. All other regions expect to have sufficient operating reserves for normal peak conditions. 

The report attributed the high risk in Saskatchewan — where reserve margins have fallen 8% compared to last winter — to increased peak demand projections and the retirement of a 95-MW natural gas unit, as well as planned maintenance that will leave generators out of service. NERC said that during extreme winter conditions and large generation forced outages, SaskPower — the principal electric utility in the province — might need to turn to demand response programs, power transfers from neighbors, maintenance rescheduling or short-term load interruptions. 

For MISO, the report noted that available resources have increased more than 9 GW from last winter, thanks to the addition of new wind and gas-fired generation and the extension of some older fossil fuel plants. However, NERC added that an extreme cold weather event that affects MISO’s southern areas could lead to outages at inadequately winterized generators or issues with natural gas supply. 

Three subregions of NPCC face elevated risk, according to the report: Québec; the Maritimes provinces and Northern Maine; and New England. All three subregions could see energy shortfalls during periods of peak demand; in the case of New England, the challenge is exacerbated by the need to use natural gas for both electricity generation and consumer space heating, potentially stressing the area’s limited gas delivery infrastructure. 

In PJM and SERC’s East and Central areas — which cover the Carolinas, Tennessee and portions of Georgia, Alabama, Mississippi, Missouri and Kentucky — generating resources “have changed little [since] 2022,” while forecasted peak demand has risen over the last year in the areas hit hardest by Elliott. While NERC said PJM and SERC “have adequate resources for normal winter conditions,” extreme conditions could lead to generator derates and outages. 

SPP’s anticipated reserve margin of 38.8% stands more than 30 percentage points lower than last year’s forecast, NERC said. The drop is mainly from rising demand and reduced resource capacity. Notably, the report pointed out that SPP’s “vast wind resources” could be a help or a hindrance depending on the level of wind activity. 

Winter 2023-2024 anticipated and prospective reserve margins compared to reference margin levels | NERC

Finally, in Texas, as in other regions, “robust load growth” has not been matched by corresponding growth in dispatchable resources. As a result, NERC said the risk of reserve shortages has risen since last winter, though ERCOT “is taking steps to procure additional capacity” heading into the winter months and has implemented a new firm fuel supply service to help offset lost generation capacity from limited natural gas supplies. 

NERC’s recommendations for utilities in the elevated-risk areas include reviewing seasonal operating plans and ensuring operators are trained and familiar with manual load-shedding procedures in advance of severe weather. The ERO also advised balancing authorities that short-term load forecasts may “underestimate load in extreme cold weather events” and that they should be prepared to manage potential reserve deficiencies. 

In addition, NERC recommended that reliability coordinators and balancing authorities conduct fuel surveys and prepare their operating plans for supply shortfalls. State and provincial regulators can help by “supporting requested environmental and transportation waivers as well as public appeals for electricity and natural gas conservation,” it said.