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October 30, 2024

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Wash. Lawmakers Pass Bill to Study Recycling of Wind Turbine Blades

Washington’s Senate on Monday unanimously approved a bill that directs Washington State University to study the feasibility of recycling wind turbine blades once they have reached the end of their useful lives.

The state’s House of Representatives had passed Senate Bill 5287 with some amendments, which the Senate reconciled on Monday. The bill calls for a study by the Washington State University Extension Energy Program to be turned in to the legislature by Dec. 1.

The legislation will go to Gov. Jay Inslee for signature.

“What we do with wind turbine blades has become an environmental concern,” said Sen. Jeff Wilson (R), who introduced the bill. “We’ve been putting up windmills on a large scale since the 1990s to make our energy green and clean. But those blades don’t last forever, and simply cutting them up and dumping them in landfills seems to defeat the spirit.”

SB 5287 calls for the study to cover:

  • the “cost, feasibility and environmental impact” of various methods of disposing of blades, including the potential for “reuse, repurposing and recycling;”
  • the availability of blade recycling facilities in Washington and other states;
  • possible incentives for creating recycling facilities in Washington;
  • “[v]arious mechanisms for establishing recycling requirements, or recycled content standards;”
  • options for “the design of a state-managed product stewardship program” for turbine blades.

The average lifespan of a wind turbine blade is 20 years, according to a Senate committee memo; the average length is 170 feet. Washington’s wind farms comprise about 3,400 MW of generating capacity. 

The study also would look at how a state-managed disposal program could be managed and examine the possibility of recycling blades made of steel, plastic and fiberglass.

Several weeks ago, the Senate Environment, Energy and Technology Committee heard testimony that the U.S. does not have a turbine blade recycling facility.

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New York Celebrates Completion of Renewable Projects

A spate of newly completed renewable energy projects in upstate New York — most recently, a wind farm on Friday — have brought the state 421 MW closer to its net-zero goal.

And downstate, after 22 years of buildout, the New York City area has surpassed 500 MW of installed solar capacity, most of it several kilowatts at a time on rooftops.

The progress upstate was announced Tuesday and keyed to Earth Week, as the eight recently completed projects are expected to reduce carbon emissions by nearly 600,000 tons a year.

The venue for the announcement was Grissom Solar, a 100-acre, 20-MW solar facility near Johnstown that was completed a month ago. Three other solar farms and three wind farms have been completed since last autumn and a small hydro facility was returned to service.

Dozens of additional projects are envisioned across the fields and hilltops of upstate New York as the state works to meet its statutory goals of 70% renewable energy by 2030 and 100% emissions-free energy by 2040.

The New York State Energy Research and Development Authority has a lead role in the process, not least by soliciting and contracting the projects.

 “Accelerating the development and completion of the dozens of wind and solar projects in our pipeline will continue to be a priority for NYSERDA,” NYSERDA President Doreen Harris said in a statement.

Progress has been steady if not blazingly fast. The eight recently completed projects celebrated Tuesday were awarded contracts in 2016 and 2017. New York has modified the process since then, creating the Office of Renewable Energy Siting to streamline the review of large renewable projects.

The 120 large-scale renewable energy and transmission projects now in New York’s pipeline total 14.2 GW, enough to bring the state to within a few percentage points of its 70% renewable goal if all were completed.

Many, of course, will not be built. Nevertheless, NYSERDA expects to announce contract awards in the summer for projects totaling at least 2 GW as a result of its sixth competitive solicitation.

Also on Tuesday, Con Edison (NYSE:ED) announced the solar generation owned by its customers in New York City and adjacent Westchester County has surpassed 500 MW of combined capacity.

Much of the densely built area is unsuitable for large-scale solar development. The 500 MW of capacity is spread among more than 55,000 individual solar systems.

New York City’s Queens borough, with its many low-rise neighborhoods, hosts 18,501 of those systems, while high-rise Manhattan has just 388. Suburban Westchester County, with its smaller population and lower density, has 44% fewer solar installations than Queens, but its total capacity is 5% higher, indicating larger installations are more common there.

“In spite of the obvious challenges for solar in the New York City region, with limited space and a dense population, the solar market continues to find ways to innovate and grow,” Con Edison distributed generation ombudsman Joe White said in a news release. “Solar energy saves customers money, creates local jobs and is a critical tool in New York’s fight against climate change.”

Progress to the 500-MW mark initially was slow but has been accelerating.

Con Edison said the first solar system was connected to its distribution grid in 2001, and it took 15 years to reach 100 MW combined capacity. In 2022, by contrast, a record 89 MW was installed.

The utility said it expects installations to continue at a similar or greater rate over at least the next decade.

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Has Dynamic Pricing’s Time Come?

Price-responsive demand has long been supported by economists, but despite the significant investment in advanced meters, it has yet to take off outside a few jurisdictions.

The Energy Systems Integration Group (ESIG) is releasing a series of papers this year, which Associate Director Debra Lew said are intended to raise awareness in the industry of how important it is to make the demand side a more active player going forward.

“We’re going to need that flexibility for high levels of renewables and high levels of electrification in the future,” Lew said in an interview.

In EPA’s recent rule, which it expects to greatly increase the number of electric vehicles purchased, it specifically pointed to time-varying rates as a way to charge all those cars without overloading the grid. (See EPA Releases Emissions Rules Aimed at Boosting EVs.)

Plenty of attention has been paid to programs such as demand response, or the aggregation of distributed energy resources under FERC Order 2222, but less focus has been paid to reducing demand through some kind of time-varying rate.

“Every time I bring up pricing, I always get told, ‘We don’t want to touch that with a 10-foot pole,’” Lew said. “So, I think it’s a really important, critical piece of the problem, and we’re hoping to shine a light on it, and to get industry to pay more attention to this, because it is a critical way of getting demand to provide that flexibility.”

Pricing should be part of the industry’s holistic planning process, where they can help avoid major spending on new resources, she said.

“If you’re thinking about adding storage to your system, maybe you should do time-of-use rates instead,” Lew said. “Think about some of these rates as replacements for resources that you might add to your system. If you’re thinking about adding a gas peaker, maybe instead you should do a peak-time rebate or critical-peak pricing.”

The idea of making the demand side more active is far from new, with the first DR programs going back decades and advanced metering infrastructure being rolled out to most customers in the country over the last decade-plus.

“As of 2021, I think there are approximately 115 million installed smart meters, and this is representing roughly 80% of all U.S. residential customers,” Brattle Group Principal Sanem Sergici said in an interview. “But when you go to [the U.S. Energy Information Administration] and look at their most recent data, only about 6% of the residential customers are on some sort of a time-varying rate.”

Time-varying pricing has not followed the rollout of smart meters because of inertia around how electricity has already been priced and some fear of the unknown, said Sergici, who contributed to ESIG’s reports and has tracked the issue for Brattle for years.

“Although, if you ask me, it’s not unknown anymore,” she added. “I mean, we have so much data. We have so much experience under our belts at this time when it comes to understanding customers response to these dynamic prices.”

Many industry veterans have bad memories about the first wave of DR programs 30 years ago that did not work as well as expected, but Lew noted much has changed since then. The industry has access to more advanced communications and control technology; the changing dynamics of the grid make the need more acute; and sophisticated customers such as data centers have shown that they can be very flexible if they get the right signals from the grid.

“I don’t think this is rocket science,” Lew said. “I think that it’s kind of ridiculous that it’s taken us this long to take this seriously.”

What to Charge?

Economists generally favor raising prices when demand is higher and having them lower when it is not, but former FERC Chair Jon Wellinghoff, who is now the chief regulatory officer at the aggregation firm Voltus, said that that would never fly politically. Dynamic pricing means customers must pay more when they use power the most, such as running their air conditioners on the hottest days of the year.

“That’s a penalty for consumers,” Wellinghoff said. “What they should be doing instead is rewarding consumers for not using energy during that time and paying them to not do that. And if they, in fact, gave them a reward, instead of a penalty, it would flip the whole thing on its head; it would make it much more palatable and much more acceptable for consumers.”

Voltus is working with Ameren Illinois to pay some of its mass-market customers who have smart thermostats to reduce usage during peak demand times. Wellinghoff argued that is much more attractive to customers than any kind of time-varying prices.

Price-responsive demand programs were sold as the key to advanced meters’ consumer benefits, but despite the meters being rolled out to most consumers, such programs have not been to nearly the same extent.

“I think it was oversold as to actually what it would be able to do and how it would be able to help consumers,” Wellinghoff said of advanced metering.

The meters rolled out to most residential customers are only collecting prices every five minutes, which makes them inadequate to really help with the sophisticated load management programs that Wellinghoff supports, he said.

FERC Order 2222, which requires RTOs to accept aggregations of distributed energy resources, is one way that the industry will be able to get the demand side into the market, but that transition needs to happen faster, said Wellinghoff. Getting Order 2222 fully implemented and demand more into the markets is going to require some changes from the distribution utilities.

“I think they’re sort of feeling afraid of being left out. And they’re not sure what their role should be. And they don’t want to accede their role to simply being a wires company. They want to do other things. But they’re not good at doing those other things, because they have never had experience in the competitive arena.”

Having the utilities focus on expanding the distribution system, while an independent distribution system operator (DSO) handles balancing various resources with flexible demand would lead to the kind of grid Wellinghoff sees in the future.

Utility Perspective

The concept of a DSO is just an idea at this point, so balancing all the activity on the distribution system is still firmly in utilities’ control. That has made implementing Order 2222 tricky, Portland General Electric Senior Vice President of Advanced Energy Delivery Larry Bekkedahl said in an interview.

“I don’t think that folks really thought through the full extent of the impacts on the distribution system, when we have traditionally been really good in the transmission generation space and bidding and markets in that space,” Bekkedahl said. “But to go to the distribution, you’ve got to be able to communicate with those that are operating the distribution system in the same way you do with the generators and transmission folks. We have not been set up for that.”

Without significant additional work bringing the utilities that run the distribution system into that picture, it will never be fully optimized, and it just has to deal with whatever extremes are placed on it, he said.

While Bekkedahl has some doubts about opening everything to third parties, virtual power plants and increased demand flexibility are a key part of the Oregon utility’s plans to keep the grid balanced. Going forward, Bekkedahl expects about a quarter of all supplies will come from distributed resources and that growing percentages of the rest will be from intermittent renewables.

“If we’re going to get to our decarbonization targets … we absolutely need as much flexibility in the load as possible because we’ve added all this variability in the generation side with wind, solar, etc.,” he added.

That flexibility will benefit from distributed batteries and direct load control (DLC) programs, in which customers can sign up for programs that allow utilities to turn up their thermostats a few degrees on the hottest days.

Most utilities in the country use their assets at about a 30 to 35% range, but PGE is starting to exceed its peaks on that usage, and it would like to be able to bring its asset usage up to 40 to 60% while meeting peak demand, Bekkedahl said. That is going to require significant flexibility.

In September 2022, the Western grid hit its all-time peak demand at 167 GW, and prices were up to $2,000/MWh, when normally they sit around $100/MWh at most. Those kinds of peaks make demand flexibility very cost effective.

“So being able to flex with customers and what used to be demand response programs now become these flexible programs that can keep the lights on for everybody,” said Bekkedahl. “And it also helps us to meet our greenhouse gas emission targets.”

How High Can Prices Go?

Reflecting the system conditions to mass market customers can be handled in a variety of ways, from standard time-of-use rates that go up over predetermined hours and are lower in others, to just passing the wholesale price signal directly to consumers.

The experience of the retailer Griddy in the winter storms that knocked out power to millions of Texans in February 2021 often came up in interviews with RTO Insider as an unfortunate, cautionary tale. The firm had grown its customer base by passing along normally cheap wholesale rates without any markup to cover the cost of hedging. But then the winter storm came through, pushing up natural gas prices, knocking power plants offline and eventually leading the Texas Public Utility Commission to set prices at $9,000/MWh for most of a work week. (See Texas Court Reverses PUC’s Uri Market Orders.)

Those wholesale prices led to some ridiculously high electric bills that customers ultimately did not have to pay; Griddy was forced out of the market, and its business model banned by subsequent legislation.

“ERCOT was living in this imaginary world were very infrequent, really high prices would automatically take care of all the issues that a capacity market takes care of in PJM,” PJM Independent Market Monitor Joe Bowring said in an interview. “It clearly didn’t work when push came to shove, and you had extreme weather. That’s the problem because then prices are extraordinarily high, and you can do a massive amount of damage in a very short period of time to companies as well as the customers.”

Some retailers ran into similar issues when PJM faced similar conditions during the polar vortex of 2014, though the RTO kept the lights on.

“In order for it to work, we have to have wholesale pricing that reflects shortages but does not reflect it to an extreme degree,” Bowring said. “I mean, some economists say that really high prices are essential. I don’t think that’s true.”

Prices can go up to $1,000/MWh, or maybe $2,000/MWh in extreme conditions, and still send the right signals to the market, including any customers on time-varying rates, he added. Prices also generally should not stay that high for long because they are only meant to go up to attract additional resources that tend to bring them back down.

Load-serving entities can design rates that would never expose their customers to such high prices, having a hedge kick in before prices shot up to their highest possible levels, Bowring said.

While the capabilities of smart meters were oversold, Bowring said, part of the reason dynamic pricing at retail has not taken off is that often third-party firms do not get access to the data that utilities have from those meters that would enable such programs. Bowring has long argued that DR should come from retail programs because he believes the wholesale DR programs PJM runs are far less efficient than that alternative.

Every time demand is triggered, it automatically leads to higher prices, which is the exact opposite effect demand is supposed to have, Bowring said.

“The place for demand side and where it can be most valuable to real customers is to have it on the demand side and to empower people to be able to reduce loads when they need to and to pay less for capacity and energy when that happens,” he added.

Some Skepticism from Consumer Advocates

California is one state that has defaulted to time-of-use rates for its residential customers, but that program needed a carveout for low-income customers in the hotter parts of the state, such as the Central Valley, Marcel Hawiger, staff attorney for TURN – The Utility Reform Network, said in an interview.

“Dynamic pricing has the potential to lower rates if, and only if, any actual reductions in demand flow through to real reductions in utility spending,” said Hawiger. “We hope that happens.”

But charging more money for power when customers need it the most can also harm them, especially low-income customers who lack the ability to pay for the automation and changes in lifestyle needed to maximize its benefits, he added. When it comes down it, dynamic pricing is “using prices to ration a needed commodity.”

“If you can afford it, you’ll just use as much as you want on a hot summer afternoon and cool your home,” Hawiger said. “And if you can’t afford it, you’ll cool less and have a warmer home because you can’t afford it.”

Many decry utility DLC programs, but they offer voluntary opportunities for customers to have their major appliances controlled by the utility in exchange for a rebate, which appeals to more customers and offers utilities more certainty over the resource, he added.

California only recently moved to default time of use rates for customers and TURN fought to exclude those who could not adequately respond. TURN looks forward to getting a look at the data on how the new rates in California have impacted customers, Hawiger said.

Where Else Has it Taken off?

Outside of California, some kind of time-varying rates have been fully deployed by Detroit Edison in Michigan, Xcel Energy in Colorado and the Long Island Power Authority in New York. Arizona Public Service and the Salt River Project in Arizona have high levels of participation in their programs, said Brattle Group’s Sergici.

Those programs show that dynamic pricing can work, Sergici said, and it is just a matter of willpower between the industry and regulators to get it in place in more jurisdictions. The transition the grid is going through, with the growth in renewables and more distributed resources, will only grow its benefits.

The shift to renewables means that instead of generation having to constantly track shifting demand, generation will be intermittent and would benefit from having the demand-side track its output at least somewhat, he said.

“Pricing actually is a very great tool to moderate the pace of that investment cycle that we’re going to go into because if you can manage some of the capacity growth through dynamic pricing, that means that you need to either defer that capacity build or you can even avoid some capacity build,” Sergici said. “And that will only help to make this transition more affordable and reliable.”

While dynamic pricing has been slow to take off, Sergici believes that is likely to change soon as the grid changes and more and more of the industry gets comfortable with it. The change will be like Ernest Hemingway’s description of how a character went bankrupt in “The Sun Also Rises”: “gradually then suddenly.”

“I think that it’s happened very slowly for a very long time,” Sergici said. “And I am now seeing this big momentum. And I think that it will happen suddenly, in the next five years, that more and more utilities will decide to have time-varying rates to be the default rates for their customers.”

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FERC Terminates MISO Show-cause Order

FERC approved MISO’s reworked ratio for its capacity auctions on Monday, a day before the grid operator began accepting its first offers. It said the RTO’s recalculation ensures it will be “deriving [seasonal accredited capacity] values” consistent with its tariff.

The order also terminated the commission’s show-cause order as it found that MISO satisfactorily recalculated the ratio, which will mean some thermal generators are entering the planning year with lowered capacity accreditation values (EL23-46).

MISO’s Resource Adequacy Subcommittee convened Tuesday, the same day that staff opened the offer window, delayed by FERC’s show-cause order, for its first seasonal planning resource auction. (See MISO Unveils New Seasonal Auction Timeline, Ratio.)

Scott Wright, MISO’s executive director of resource adequacy, said MISO staff is “doing everything [they] can” to carry out the more complicated seasonal auction in a timely fashion. He said he appreciated stakeholders accommodating the dynamic auction schedule. MISO expects to reveal auction clearing prices May 19, about a month later than usual.

MISO’s Durgesh Manjure said that following the auction, MISO stands ready to hear stakeholders’ advice on how to improve it for subsequent years.

“Resource adequacy at MISO is definitely a team sport,” he said.

The auction’s delay hinged on an unforced capacity-to-intermediate seasonal accredited capacity ratio that it uses to determine supply. The ratio helps MISO navigate its new seasonal landscape, converting resources’ seasonal accreditation into unforced capacity terms. The grid operator expresses its planning needs according to unforced capacity values.

The RTO was forced to redo the ratio after a computer error caused some previously exempted planned outages to be counted against some resources’ accreditation values. The grid operator asked FERC that it be allowed to revise individual accreditation values but leave the systemwide ratio alone, as some market participants had already relied on the flawed ratio to enter bilateral capacity arrangements outside of the voluntary auction.

However, FERC ruled that the ratio had to be updated with resources’ latest seasonal accreditation values.

FERC said MISO’s tariff doesn’t afford it “with discretion to decide whether to update the ratio; rather, MISO must calculate the ratio consistent with the formula set forth in the tariff.”

FERC said while it was “sympathetic to arguments” from Vistra and the Electric Power Supply Association (EPSA) that market participants already relied on the erroneous ratio to make supply plans for the planning year, those arguments cannot supersede MISO’s duty to follow rules outlined in its tariff.  

Earlier this month, Vistra and EPSA, a trade group representing competitive suppliers, asked FERC to terminate the proceeding and issue an order to prevent MISO from updating the ratio and lowering resources’ capacity credits. Both said a reworked ratio stands to affect careful supply plans that load-serving entities have buttoned up for weeks based on MISO’s first published capacity values. (See Vistra, EPSA Protest MISO’s Show-cause Order.)

FERC also said the ratio recalculation doesn’t intrude on MISO’s tariff provision requiring LSEs to opt out of the auction and submit a fixed resource adequacy plan before the upcoming a planning year.

Finally, the commission said it disagreed with ESPA’s claim that it was interfering with MISO’s auction.  

“Rather, we are ensuring that the correct values for auction parameters are being used,” FERC said.

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PJM OC Briefs: April 13, 2023

Gas Supply Issues During December Storm Reviewed

PJM presented the Operating Committee a review of the issues that contributed to insufficient natural gas supplies during Winter Storm Elliott, one of the leading causes of generation being offline during the storm.

Gas pipelines took numerous actions in the days leading up to the storm, PJM’s Brian Fitzpatrick said, including restrictions on non-firm contracts and requiring daily balancing of supply and demand. But the actions were insufficient as the storm rolled in and caused force majeure declarations and losses in upstream supply. PJM was aware of the precautionary actions through its daily updates with pipeline operators, however the scale of the production loss was unforeseen, he said.

“We’ve never seen that level of supply loss in the history of Marcellus and Utica,” Fitzpatrick said of the gas producing regions.

One stakeholder said insufficient gas supply is an issue for other RTOs as well, in part because the reliability analyses conducted by pipeline operators are minimal. Pipelines were originally sited to provide fuel for building heating, rather than for delivery to gas-fired generators. With the future of gas uncertain, the stakeholder said, it’s unlikely there will be sufficient investment to simultaneously meet both needs.

Pipeline Operating Conditions (PJM) Content.jpgA PJM graphic shows the alerts and conditions gas pipeline operators supplied the RTO during the December 2022 winter storm. | PJM

Though the majority of generators that experienced outages related to gas fuel supply had non-firm delivery contracts, many generators with firm fuel also experienced interruptions. On Dec. 24, the day with the most outages, generators with non-firm fuel accounted for nearly half of offline capacity by percent of installed capacity (ICAP), while those with firm fuel represented more than a quarter.

Mike Bryson, PJM senior vice president of operations, said PJM generators with all forms of gas supply contracts saw their deliveries curtailed. The RTO is exploring ways of addressing the issue in its critical issue fast path (CIFP) proposal. (See PJM Presents More Detail on CIFP Proposal.)

“This needs to be part of a flexibility attribute going forward,” he said.

Gregory Poulos, executive director of the Consumer Advocates of PJM States (CAPS), questioned whether there will be similar analysis on other major causes of forced outages during Elliott, noting that boiler issues across generation types accounted for more offline capacity than fuel supply for gas generators alone. Fitzpatrick said physical failures constituted around two-thirds of outages and will be the topic of future presentations.

Proposals Seek to Address Transmission Outage Coordination

Stakeholders continued discussion on two proposals to address how PJM and utilities coordinate extended transmission outages. The proposals seek to avoid the surge in congestion pricing caused by line work in Virginia’s Northern Neck peninsula. (See “Transmission Outage Coordination Proposals Discussed,” PJM OC Briefs: March 9, 2023.)

A joint package from PJM, DC Energy and Public Service Enterprise Group (NYSE:PEG) would direct RTO staff to review approved Regional Transmission Expansion Plan (RTEP) projects for any extended outages that may be required and work with the utility to evaluate the impact of any such outages and expand outage information shared by PJM. Upgrades to facilities may be considered if outages are expected to cause significant operational issues.

The Independent Market Monitor’s proposal would aim to identify congestion impacts in advance of projects being approved and request proposals from TOs. It would also treat a request to reschedule an outage as a new request or as a late submission if TOs try to reschedule too far out, seek to reduce or eliminate approval of outage requests after FTR bidding opens and prevent TOs from bypassing rules for long duration outages by breaking them into smaller segments.

Both proposals require that enhanced rating information be consistent with FERC Order 881, which is set to be implemented by July 12, 2025.

Jim Davis, of Dominion Energy (NYSE:D), said the Monitor’s proposal is overly prescriptive and approaches transmission upgrades solely from a markets perspective without taking construction realities into account. Upgrading a large line in one project without segmenting it could create significant impacts on reliability and markets, he said. Other provisions in the Monitor’s proposal would slow the outage process further and increase the risk of projects not being completed on time, he said.

“We as transmission owners need this flexibility because the transmission outage process is dynamic … especially as conditions change in the real time. As for the [Monitor’s] recommendation that PJM not permit transmission owners to segment long duration transmission outages, that’s just not how things work in reality,” Davis said.

 

Other OC Discussions:

  • Stakeholders discussed sunsetting the Synchronous Reserve Deployment Task Force following an August 2022 FERC order rejecting PJM’s Intelligent Reserve Deployment (IRD) proposal. Since the order, the task force has found that the scope of its issue charge and problem statement limit its ability to address the commission’s concerns. PJM’s Vijay Shah stated that there are no proposals currently before the task force.
  • PJM Chief Information Security Officer Steve McElwee encouraged members to ensure their software patches are up to date to avoid falling victim to hackers. He noted that a Canadian utility was attacked on Thursday, with a pro-Russian group claiming responsibility in retaliation for the nation’s backing of Ukraine.
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FERC Approves Termination of FTR Trader’s Member Status

FERC on Friday granted PJM’s request to terminate the membership of Hill Energy Resource & Services following the company’s failure to pay several invoices for financial transmission rights transactions on time in 2022 (ER23-423).

PJM declared Hill to be in default on its credit obligations three times in January 2022 totaling more than $18 million, as well as being in default on five payments between January and February totaling $4,301,233.96, according to the RTO’s filings.

The company argued that PJM’s approval of the Lanexa-Dunnsville transmission line into Virginia’s Northern Neck peninsula led to volatile pricing in the region, compounded by tariff violations that Hill alleged PJM committed by issuing collateral calls and subsequently preventing the company from liquidating FTR positions. (See PJM Weighs Options on Hill Energy FTR Default.)

“Essentially, PJM took actions that resulted in abnormal market conditions, those actions led to unjust and unreasonable rates, and PJM now asserts that Hill Energy’s failure to post collateral for the unjust and unreasonable rates is a legitimate basis upon which to terminate Hill Energy’s membership,” Hill stated in its protest. The company did not provide comment on the order Monday.

After work began on the Lanexa-Dunnsville line in January 2022, Hill said prices began fluctuating between the energy offers of the limited number of combustion turbines sited on the peninsula and the $2,000/MWh transmission constraint penalty factor (TCPF), leading to “substantial losses leading to payment defaults that otherwise would not have occurred.” It argued that given the unique circumstances — which led to a separate PJM stakeholder process and FERC filing to permit the RTO to temporarily suspend the TCPF in the region — a permanent termination of the company’s membership was not warranted. (See FERC Approves Pause of PJM Tx Constraint Penalty Factor in Va.)

“Absent the application of the TCPF and the resultant unjust and unreasonable rates, Hill Energy believes it would have had positive returns or much smaller and manageable losses, and defaults likely would not have occurred,” Hill’s filings say.

The protest also argued that that PJM’s first $921,500 collateral call on Jan. 11, 2022, constituted a tariff violation, citing section VI.C.7, which states that the RTO could only declare a credit default after a market participant failed “to satisfy a request for collateral for two consecutive auctions of overlapping periods, e.g., two balance of planning period auctions, an annual FTR auction and a balance of planning period auction, or two long-term FTR auctions.”

The collateral call created a “cascading effect” once the company did not supply the additional funds by leading PJM to revoke the company’s ability to sell open FTR positions and prevent it from accessing market data to continue mitigating its obligations. The company stated that by liquidating open positions, it aimed to reduce its collateral requirement under section VI.C.7, but that action was not immediately taken by PJM after the company made its request. The third collateral call on Jan. 13 for $17 million “crippled” the company’s operations, as it believed it was required to first pay its collateral before addressing invoices.

“The timely sale or liquidation of these positions would have reduced its collateral requirement, thereby allowing Hill Energy to pay its January and February 2022 invoices on time, avoiding any payment defaults,” the company said.

Responding to the protest, PJM stated that section VI.C.7 is limited to particular FTR auctions, rather than general credit defaults and is not applicable to Hill’s circumstances. It described the issues raised by the company as “attempts to confuse the issues and raise disputes that do not stay PJM’s obligation to terminate Hill Energy’s membership.”

PJM also said that any appeals to a membership termination must be done through its dispute resolution process, although the initiation of an appeal does not stay the ability to seek termination. Though Hill added an alternative request to its protest asking for the commission to consider instead approving a suspension of its membership while it engaged in that process, the order did not address the request.

In approving the request to terminate Hill’s membership, FERC focused on the five invoices the company failed to pay between Jan. 25 and Feb. 23, finding that the company did not provide any tariff provisions supporting its case for excusing its nonpayment. Provided that is reason enough for termination, the commission said it does not need to address whether PJM followed its tariff in issuing the collateral calls. Responding to the company’s argument that it would have been able to use revenues from its sell-only FTR bids to pay its invoices if PJM had submitted them when originally requested, the commission said it found that to be “speculative and uncompelling.”

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NERC Says Changes Coming to Physical Security Standards

NERC told FERC in a report Friday that it will soon begin a new standards development project to examine changes to reliability standard CIP-014-3 (Physical security) in response to the ongoing threat of physical violence against grid assets.

FERC ordered the report at its December open meeting citing recent physical security incidents, primarily the Dec. 3 gunfire attack on two Duke Energy (NYSE:DUK) substations in North Carolina, which left 45,000 customers without power for as long as four days (RD23-2). (See FERC Orders NERC Review on Physical Security.)

Physical security has remained a pressing concern since then because of subsequent sabotage events in Seattle and Las Vegas, as well as the arrest of a neo-Nazi leader for plotting to attack electric substations in Baltimore. (See Feds Charge Two in Alleged Conspiracy to Attack BGE Grid.) NERC CEO Jim Robb said in a statement that the “heightened physical security threat environment and the high-profile attacks … in the fourth quarter of 2022” made the new report a priority for the ERO Enterprise.

“Our study outlines actions to strengthen the physical security standard and foster robust stakeholder engagement to consider additional risk-based enhancements,” Robb said. “The actions outlined in our report will help further secure critical bulk power system assets and ensure the foundational protections of CIP-014 are keeping pace with a dynamic risk environment.”

Standard Modifications Planned

CIP-014-3 was approved by FERC last year with the purpose of identifying and protecting transmission stations and substations that, if damaged in a physical attack, “could result in instability, uncontrolled separation, or cascading within an interconnection.” It requires transmission owners to perform periodic risk assessments of their transmission facilities and control centers to determine which of them are critical to reliability, evaluate their potential physical security threats and vulnerabilities, and develop a security plan to address those threats.

The commission wanted NERC to assess the effectiveness of CIP-014-3 in light of the North Carolina attacks. FERC ordered the ERO to evaluate the adequacy of the standard’s applicability criteria, the adequacy of the required risk assessment, and whether a minimum level of protection should be required for all substations on the North American grid.

In the report, NERC said that the criteria are still appropriate to “focus limited industry resources” on the most critical grid facilities, and that its evidence suggested that expanding the criteria would not identify any additional critical substations. As a result, the ERO recommended against expanding the criteria.

However, the ERO also acknowledged that “supplemental data” such as “expansion plans, future year realized conditions, impacts of grid transformation, and other similar projections that alter year-to-year … could alter substation configuration” and bring currently unqualified facilities under the jurisdiction of the standard. NERC plans to hold a technical conference with FERC to identify the type of substation configurations to be studied, and to establish data needs for conducting those studies; the conference has not been scheduled.

NERC did find that the standard’s language requiring TOs to study the effect of losing a substation needs “additional clarification as [to] how registered entities must conduct the assessments.” The report said that utilities’ approaches to the studies are inconsistent in both their methods and their frequency. Although this can occur because they lack in-house subject matter experts, the root cause is “a lack of specificity in the requirement language,” NERC said.

The ERO said it will begin a new project to examine the issue and determine how the standard could be modified to provide more clarity. Suggested objectives of the project include clarifying the methods for studying instability, uncontrolled separation, and cascading; clarifying the documentation and usage of criteria to identify instability, uncontrolled separation, or cascading; and clarifying the risk assessment to account for adjacent substations of differing ownership.

Conference to Address Minimum Security Requirements

Finally, in response to FERC’s question about requiring that protection be implemented on all grid facilities, NERC suggested that a “more holistic approach [would] provide greater long-term flexibility and minimize the impacts of physical attacks on [grid] reliability.” The ERO acknowledged that a uniform set of protections might prevent some physical damage but warned that it would not “guarantee the protections will safeguard against more sophisticated or coordinated attacks.”

However, NERC also suggested a second technical conference to evaluate “the appropriate combination of reliability, resiliency and security measures that would be effective in helping to mitigate the impact of physical security attacks.” Topics covered by the conference will include:

  • the appropriate approach to identifying the objective of a minimum level of protections, risks to be mitigated and industry resources necessary to meet minimum requirements;
  • expanding the use of planning studies to evaluate physical security attacks and develop corrective action plans to deal with inadequate performance;
  • enhancing operational planning assessments to include loss of assets from physical attacks; and
  • enhancing transmission planning and TO requirements to ensure spare equipment pools are appropriate to respond to security incidents.

NERC will use the technical conference as a basis for determining its future moves, including additional changes to its reliability standards. The conference, like the one dedicated to the applicability criteria, has not been scheduled.

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Calif. Agency Seeks to Transform Wildfire Safety Culture

INCLINE VILLAGE, Nev. – A relatively new California agency is working to transform utilities’ wildfire safety culture by shifting away from penalties and enforcement to a proactive, learning-based approach.

The California Office of Energy Infrastructure Safety was established through state legislation following devastating wildfires in 2017 and 2018, according to Caroline Thomas Jacobs, the office’s director. The agency got its start as the Wildfire Safety Division within the California Public Utilities Commission but became a standalone department in July 2021.

The office, known as Energy Safety for short, is now about three years old.

Thomas Jacobs talked about the new initiative during a panel discussion at last week’s joint meeting of the Committee on Regional Electric Power Cooperation (CREPC) and the Western Interconnection Regional Advisory Body (WIRAB).

Energy Safety’s activities are based on a shift from “a compliance-based, reactive, penalty-enforcement approach to issues of safety to implementing a new, proactive planning-learning-improvement regulatory cycle,” Thomas Jacobs said.

Among its duties, the agency reviews utilities’ wildfire mitigation plans and assesses their safety culture each year. Wildfire mitigation plans are based on a “maturity model” in which utilities explain where they are in terms of wildfire prevention activities and where they expect to be as a result of safety investments.

In the safety culture assessment, utilities survey their employees and contractors — from frontline inspectors to senior managers — on their understanding of and approach to wildfire safety. Energy Safety then makes recommendations on how safety culture could be improved and follows up to see if the recommendations are being implemented.

But enforcement isn’t disregarded: Energy Safety also conducts inspections, audits and investigations to see whether utilities are complying with their approved wildfire mitigation plans.

Panelist Brian D’Agostino, vice president of wildfire and climate science at San Diego Gas & Electric, said the new framework is “having a real impact” on the utility’s culture and helping it maintain focus on priority safety areas.

“These safety culture assessments don’t come back and say everything’s great top-to-bottom,” D’Agostino said. “It gives us areas where we can really focus on and areas where we can improve.”

Panelist Sumeet Singh talked about how safety culture has changed at Pacific Gas and Electric, where he is executive vice president of operations and chief operating officer.

“Frankly, the wildfire risk is something that surprised PG&E,” Singh said. “One of the big reasons for the surprise was the significant drought that happened in 2014 to 2016 that completely changed the environment in which the overhead electric assets operated.”

The change was initially missed because of the utility’s focus on reliability and running assets to failure, Singh said. Now, he said, PG&E has adopted a mindset seen in high-hazard industries.

The Camp Fire, which destroyed much of the town of Paradise in November 2018 and killed more than 80 people, along with a series of Northern California wine country fires in October 2017, forced PG&E into bankruptcy and led to a multibillion-dollar settlement with fire victims.

In June 2020, the utility pleaded guilty to 84 counts of involuntary manslaughter and one count of arson in connection with the Camp Fire. In February, PG&E pleaded not guilty to 11 charges stemming from the September 2020 Zogg Fire. (See PG&E Pleads Not Guilty to Manslaughter Charges.)

Singh said that mitigations in the utility’s wildfire safety plan include plans for undergrounding 10,000 miles of distribution lines and replacing bare lines with covered conductor or insulated wire in high fire-threat areas. (See PG&E Scales Back Plan to Underground Lines.) PG&E is also turning to remote grids and microgrids in situations where a handful of customers in remote areas are served by distribution lines that run across risky terrain.

But Singh said PG&E is also working to change its safety culture. One goal is to make sure that employees who know the assets feel empowered to speak up if they spot a problem, he said.

Another issue has been the different perception of risk among employees ranging from inspectors to supervisors and executive leadership. The focus now is to “align on the perception of risk,” Singh said.

He gave as an example an employee who has been working on electric systems for a long time.

“They may have been OK at one point in time to look at [an] adverse condition in the health of a tree and say, you know what, we can actually remove or address that in six months,” Singh said. “That’s not the case anymore. That’s an immediate safety issue that actually needs to be addressed right away.”

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House Hearing Examines State of the Nuclear Power Industry

House lawmakers heard from nuclear industry experts Tuesday as they get started on legislation aimed at helping the deployment of advanced reactors across the U.S.

“To expand the industry, it is vital we encourage regulatory certainty and make sure our reactor licensing processes enable the safe and broad deployment of nuclear technologies,” said Rep. Jeff Duncan (R-S.C.), chair of the House Energy and Commerce Subcommittee on Energy, Climate and Grid Security. “This is especially important for advanced reactor technologies.”

Nuclear power now provides about 20% of the country’s electricity, including about half of its carbon-free energy, and it can help eliminate emissions on the grid, said the subcommittee’s ranking member, Rep. Diana DeGette (D-Colo.). But several things need to happen for nuclear to remain a key part of the generation mix going forward, she said.

“The United States must develop a comprehensive science-based strategy to dispose of spent fuel — a strategy that does not cause harm to public health or our environment,” said DeGette. “If we don’t have a long-term permanent solution for disposing of nuclear waste, then we will struggle to be able to use this source of carbon-free electricity.”

She said the other key challenge is figuring out what do with the existing fleet, which has seen some scattered retirements in recent years, but only one new nuclear plant coming online: Southern Co.’s Vogtle plant.

Once Vogtle’s units are online, the country will have 94 reactors operating, and it will be important to extend their operating lives while securing them a more stable source of uranium, said Idaho National Laboratory’s Jess Gehin.

“Currently, our nation imports 90% of our uranium needed for our reactor fleet,” Gehin said. “This includes imports from Russia; eliminating these imports from Russia requires us to establish an expanded uranium-enrichment capability domestically and with our close allies.”

Some of the proposed new reactors such as TerraPower’s natrium reactor in Wyoming and X-energy’s Xe-100 planned for deployment at a Dow Chemical facility on the Gulf Coast need a stable, domestic supply of high-assay, low-enrichment uranium that is not produced here at all, said Gehin.

Duke Energy (NYSE:DUK) has the largest fleet of 11 “regulated” nuclear units at its vertically integrated utilities in the Carolinas, and the North Carolina Utilities Commission has approved its early investment to consider building new, advanced reactors, said Regis Repko, the company’s senior vice president of generation and transmission strategy.

“We plan to add unprecedented numbers … of solar energy, storage [and] wind power to the grid as we continue to retire our aging coal fleet,” Repko said. “However, we must have firm, dispatchable resources, such as nuclear and natural gas, to support renewable energy resources. Our customers depend on us, and we must not jeopardize reliability or affordability in this transition.”

Duke’s 11 plants are all set to retire between 2030 and 2046. To avoid losing those plants, which produce half the energy and 80% of the clean energy for its utilities in the Carolinas, the company would like to extend their licenses another 20 years. Duke also plans to build 8 GW of new nuclear power.

The firm plans to work with stakeholders and the Nuclear Regulatory Commission to ensure the licensing process for those new reactors is effective, efficient and in line with the safety of the new reactor designs, Repko said.

The bipartisan support seen at the hearing, recent advances in Europe and California’s decision to extend the life of the Diablo Canyon nuclear plant all point to the increased support the technology has seen in recent years, said Clean Air Task Force Executive Director Armond Cohen.

“The problem is that we’re just not moving at any scale and pace that’s relevant to climate. To be relevant to climate, nuclear is going to have to be churning out something like 100 GW/year globally,” said Cohen. “That’s about in the range of where we were with coal and gas in a sustained way for a few years. We have to be really running at that scale. We’re about 10 GW/year, so, we need to be 10 times where we are.”

To have an impact on global climate change, the U.S. nuclear industry will need to export its technology because domestic emissions only amount to 15% of global emissions, he added.

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NYISO Seeking to Increase Emissions Transparency

NYISO on Monday presented the Installed Capacity Working Group/Market Issues Working Group (ICAP/MIWG) with proposed methodology for measuring implied marginal emission rates (IMERs) to increase transparency around New York’s emissions output by providing real-time data.

The ISO chose the IMER “heat rate” methodology to measure emissions production over other options because, staff said, it is highly variable and granular, performs well in grids with clearly defined marginal fuel types, and helps identify persistent congestion patterns.

The methodology uses LMPs, fuel prices, emissions costs, and variable operation and maintenance costs as inputs to estimate the implied heat rate, which is then used to estimate the real-time zonal IMER in tons of carbon per megawatt-hour for a given implied marginal fuel.

Stakeholders requested NYISO publish real time marginal and average zonal emissions rates data to help them comply with state energy and climate legislation, particularly Local Law 97, which set strict carbon reduction standards for large New York City buildings. (See NYC Proposes Rules to Implement Building Emissions Law.)

Aaron Breidenbaugh, director of regulatory affairs at CPower Energy Management, asked why stakeholders had requested this project, to which William Acker, executive director of the New York Battery and Energy Storage Technology Consortium, responded that his organization, along with state agencies and other stakeholders, need this information to support LL97 compliance.

“We need to have at least hourly marginal numbers available for the accounting under [LL97], and secondly, it’s valuable to have something that is forward looking and that isn’t simply scorekeeping but is actually actionable by people managing buildings in New York City,” Acker said.

NYISO will return to the ICAP/MIWG either next month or in June to share additional information on the methodology’s inputs and is targeting the fourth quarter to deliver the functional requirement specifications.

Renewable Regulation Requirements

NYISO also presented the ICAP/MIWG with proposed revisions to the regulation requirements for renewable resources in the state.

As New York installs more wind and solar projects, the ISO has been required to regularly update its regulation requirements, starting in 2010 and again in 2016, to ensure that these resources are not negatively impacting its ability to balance the bulk power system or disrupting voltage requirements.

NYISO modeled two scenarios that predict the total amount of installed nameplate capacities of land-based wind (LBW), offshore wind (OSW) and solar at the end of a given year: Scenario 1 projects that 3,000 MW of LBW, 125 MW of OSW and 7,651 MW of solar will be installed by 2024; while Scenario 2 projects 3,700 MW, 125 MW and 9,768 MW, respectively, will be installed by 2026.

NYISO is proposing that Scenario 1’s set of new regulation requirements be implemented on June 1, and that Scenario 2 be implemented in 2025. The ISO would send stakeholders market notices in case capacity levels approach those in the scenarios earlier than projected.

NYISO will seek approval for its proposed scenarios and their implementation timelines at the Operating Committee’s meeting Thursday.