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October 1, 2024

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How to Quicken Transmission Development Discussed at NARUC

The U.S. used to be able to build massive infrastructure projects such as the Empire State Building and the Pentagon in just a year, but nearly a century later that is far from the case with electric transmission, Maryland Public Service Commission Chairman Jason Stanek said at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit on Monday.

With billions in dollars in new federal incentives aimed at expanding clean energy, the pace of transmission development needs to speed up in order to take full advantage of those.

“As a state commissioner, I’m disappointed,” Stanek said. “I’m disappointed that over my five years at the commission, I haven’t been able to site and build 1 inch of interstate transmission.”

The Inflation Reduction Act and the Infrastructure Investment and Jobs Act (IIJA) are setting the country on course for the largest investment in infrastructure installation in 100 years, said Jeff Dennis, deputy director of the U.S. Department of Energy’s Grid Deployment Office.

“But we know that a significant portion of those benefits — as much as 80%, according to a Princeton study — of the emission reduction benefits that Congress expected from the IRA won’t happen if we don’t increase the pace at which we build transmission,” Dennis said.

The past decade has seen the grid expand at a clip of about 1% per year, but that needs to exceed 2% to meet those goals, he added.

Much of the funding DOE received for transmission in those recent laws is for “commercial support” rather than the loans it has used most often in the past, said Dennis. The money will help finance and speed up the development of transmission.

The IIJA included $2.5 billion the department can use to facilitate transmission by doing things like becoming the anchor-customer on a line to help it get financed and then sell off that space as the project is developed. The IRA has another $2 billion that DOE can use to help support transmission projects deemed in the national interest, Dennis said.

DOE also has new loan authorities, including some aimed at repowering existing corridors so that they can transmit more energy than they do now, Dennis said.

The IRA offers $100 million for addition regional and interregional transmission lines.

New England is expecting major changes to its grid, as it will have to greatly expand clean energy to meet future demand, which is on pace itself to grow from 25 GW today to 43 GW in the future because of electrification, said Digaunto Chatterjee, vice president of system planning for Eversource Energy.

“The best way to deploy IIJA funds is to surgically address specific transmission upgrades on your system and create new landing sites for offshore wind,” Chatterjee said.

While the industry has a daunting task of expanding its transmission grid and turning over to new sources of generation, it is a job that it has successfully performed in the past, said National Grid Clean Energy Development Director Terron Hill.

“When you think about the 1970s, we had a huge buildout of the transmission network in order to pick up electrification needs and new industries,” said Hill. “We saw the same type of buildout of the transmission network as we transitioned away from oil and coal to natural gas.”

New England has added about 300 MW of renewable energy per year, but to meet its carbon-mitigation goals, the pace of infrastructure development will need to be closer to 3,000 MW, Hill said.

“That is a huge challenge, but it’s a challenge that we can meet,” Hill said. “I was told very early in my career, that if you give engineers and planners a problem to solve, they will come up with the best solutions.”

Part of the solution is getting more efficiency out of the existing transmission grid through the adoption of dynamic line ratings, topology optimization and advanced power flow controls, said Hilary Pearson, vice president of policy for LineVision. The firm’s technology has helped New York wring more transfer capability out of its grid, which has historically been congested in power flowing from west to east and north to south, limiting the amount of load served by clean energy.

“By using dynamic line rating sensors in the western part of the state — very renewable-rich but has constraints and congestion on the system — we’re going to be able to eliminate 320 MW of existing wind energy curtailments, while creating another 190 MW in headroom for new renewable energy projects to be able to come onto the grid,” she said.

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DC Circuit Upholds FERC on Montana PURPA Project

The D.C. Circuit Court of Appeals on Tuesday upheld a FERC decision that allowed a solar-and-storage project in Montana to be certified as a qualifying facility under the Public Utility Regulatory Policies Act even though its total power production capacity exceeded the law’s 80-MW limit (21-1126).

FERC had justified its March 2021 decision under its longstanding “send-out” analysis, which determines a facility’s capacity based on the electricity it can actually deliver to an interconnecting electric utility.

Broad Reach Power’s Broadview Solar project included solar panels with a gross capacity of 160 MW DC and a 50-MW battery, but the project’s inverters allowed it to produce and deliver only 80 MW to its interconnection with NorthWestern Energy’s (NASDAQ:NWE) transmission system.d.

“The commission’s determination that Broadview is a qualifying facility with a ‘power production capacity … not greater than 80 MW’ because its component parts, working together, produce no more than 80 MW of grid-usable AC power was reasonable and well-supported by the statute’s text, structure, purpose and legislative history,” the D.C. Circuit said in its decision.

In upholding FERC’s order, the court rejected challenges by NorthWestern and the Edison Electric Institute, which argued that FERC exceeded its authority because the “power production capacity” of Broadview’s facility should be the total amount of DC power generated by the solar array and not the grid-usable AC power produced by the inverters working in conjunction with the solar array and battery.

PURPA was enacted in 1978 to encourage alternative energy generation by “qualifying small power production facilities” (QFs). It requires utilities such as NorthWestern to purchase a QF’s generation output, “providing those facilities with a guaranteed market,” the court noted.

Montana has been an especially contentious front for PURPA disputes in the West, where utilities contend the law requires them to integrate large volumes of QF renewable resources at contracted rates far above market rates.

Circuit Judge Justin Walker dissented in part from his colleagues on the three-judge panel, Circuit Judge Cornelia Pillard and Senior Circuit Judge David Sentelle, who drafted the majority opinion.  

PURPA “gives lucrative benefits to small facilities that produce solar power,” Walker wrote. “It defines them as facilities with a ‘power production capacity’ of no more than 80 MW. … Because Broadview can produce 80 MW for its inverters while it simultaneously produces 50 MW for its battery, Broadview’s facility is capable of producing more than 80 MW of power. So it is too large to be a ‘small facility.’ For that reason, I would grant the petitions, vacate the rehearing orders and remand to FERC for reconsideration.”

The case took an unusual twist at FERC before reaching the appeals court.   

In September 2020, FERC broke with its own precedent by deciding the Broadview project could not be certified as a QF because it exceeded the 80-MW cap despite its limited interconnection. Its decision aligned with the arguments of NorthWestern and EEI.

The commission’s lone Democrat at the time, Richard Glick, dissented. The commission’s decision, Glick wrote, “will make QF status turn on the capacity of any one component of the facility, rather than the actual power production capacity of the facility itself. That conclusion finds no support in the statute, our precedent or common sense.” (See Montana Hybrid Ruling Departs from PURPA Precedent.)

In March 2021, with Glick now chairman, FERC set aside its prior ruling, reinstated its send-out analysis, and determined Broadview could be a QF. (See FERC Reverses Ruling on Montana QF.)

“It is not fathomable to conclude that Congress would be more concerned about the electricity a project could theoretically generate on its own but not deliver to any customer,” Glick said at the time. “Instead, since the statute is all about the sale of a project’s output, the appropriate way to look at a facility is to assess how much can actually be sold to the purchasing utility.”

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NARUC Panelists: Rate Design Key for the Clean Energy Transition

Getting rate design right is important to the clean energy transition because it will help determine the best resource mix and ensure customers have opportunities to cut their bills with demand response and distributed resources, experts said at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit this week.

“The reason that I think there’s no more exciting topic than rate design is because it truly sits at that intersection of every other aspect of the energy system: affordability, reliability; all of the conversations we’re having around grid modernization, integration of different resources, customer choice,” said former Virginia State Corporation Commissioner Angela Navarro, now head of state regulatory affairs for Richmond-based climate technology company Arcadia. “All of those things are central to determinations on rates.”

Smart meters are on most homes in the country now, while rooftop solar and electric vehicles are becoming increasingly common; how those resources impact rates is very important, Navarro said. Storage has huge potential, but that can only be harnessed with the right rate design that informs its owners when to charge and discharge.

On the other side, the right rate design can help avoid negative impacts on the grid, such as by encouraging customers to charge their EVs during off-peak hours, she added.

Supply is going to be more variable in the future because of the growth of intermittent renewables and more common extreme weather, said Lon Huber, Duke Energy vice president of pricing and customer solutions.

“But fortunately, with technology, we have an increasing number of tools to use to start shaping load to match the more variable supply out there,” Huber said.

Sending those price signals far and wide requires approval from regulators and the right technology; it cannot happen overnight, he added. On top of smart meters, utilities need field area networks, data management systems and updated billing systems that can take years to put in place.

Smart meters have been rolled out to 75% of the nation’s customers and despite being in place for years in many jurisdictions, their use rarely matches their potential, said Travis Kavulla, NRG Energy vice president of regulatory affairs.

“We’re still talking about single-digit percentages of those smart meters that are used to do anything to actually interact with customers in terms of sending a price signal or any other incentive to flex demand,” Kavulla said.

Kavulla recently wrote a paper for an Energy Systems Integration Group effort looking into how retail pricing could be used to get customers to respond to grid needs, called “Why is the Smart Grid So Dumb? Missing Incentives in Regulatory Policy for an Active Demand Side in the Electricity Sector.” It has been a more than a decade since federal stimulus dollars gave most states the push to install advanced metering, and despite soaring rhetoric from that time, the investment has done little to make demand an active part of the electric industry, he argues.

“My basic proposition is this: that someone somewhere has to face the clear price incentives to accurately manage demand in order for it to happen,” Kavulla said. “And all too often in our regulatory schema that we set up for ourselves, regulated utilities themselves lack clear incentives to do so. And even for competitive retailers like NRG, we face an incomplete set of incentives to make these kinds of investments in demand flexibility.”

Getting the rate signals right could mean huge savings, with New York state estimating it could cut the cost of compliance with its climate mandates by a third, while PJM identified retail rate design as one of five key focus areas for successfully decarbonizing the grid, he added.

Kavulla would like to see more jurisdictions set up opt-out time-of-use pricing to tap the demand resources that advanced metering has made available. Customer adoption of complex rates under opt-in constructs are too low.

“As much as my inner libertarian would like to avoid this, regulators really cannot escape making solid decisions on behalf of customers in highly regulated industries like these,” Kavulla said.

Opt-in regimes usually produce better responses from customers who affirmatively decide to participate, said Huber. The system works too, with Huber noting Arizona has seen up to 60% participation in time-of-use rate programs.

“I think opt-in in the long run is better, but it takes time,” Huber said. “And it takes a lot of marketing [and] a lot of education to get it done.”

The Future of Solar

Getting rate design right is important for the solar industry as rooftop panels become increasingly common in many jurisdictions, leading to often thorny debates about how to pay for their excess output going forward, experts said an earlier panel on Sunday.

“Increasingly some of the issues that we’re beginning to tackle are how do we sort of evolve the industry from what has been a traditional approach to behind the meter resources,” Solar Energy Industries Association Senior Director of Utility Regulation and Policy Kevin Lucas said. “And how do we evolve that in a way that’s going to make sure that regulators, policymakers, customers and utilities are getting the most bang for the buck out of the resources that they’re putting onto the grid?”

SEIA is working in Arizona now to get a system in place that encourages more growth of solar-plus-storage than its current “net billing” structure, which does favor storage but incentivizes its use to shave the customer’s own peak rather than the system peak. Customers get paid less for exporting power to the grid than they do shaving their own demand.

SEIA would like to see batteries controlled by utilities in a program where they can be called on up to 30 times a year for up to three hours at a time and they get paid based on response to those signals.

“So, if a customer chooses to participate in a given event, they will export energy, that energy is going to be measured, and at the end of the year, they will get a credit based on how well they perform during these specific calls,” Lucas said.

Some 760,000 customers have solar installations on their homes, but just 47,000 customers around the country have adopted storage, said Sunrun Senior Manager for Public Policy Thad Culley. Most of the customers with storage have bought systems to improve their resilience because they live in areas that experience outages more often.

Expanding that market to a bigger number of customers and getting them to work with the grid is going to take some new rates, Culley said.

“You’re going to need to have some kind of predictable value stream going forward to motivate the customer to want to play nice with the grid and do the types of grid support services that are valuable,” Culley said.

With the right incentives, those customers could even provide more specific services that benefit the local grid, he added.

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FERC OKs WEIM Changes for Washington Cap-and-trade Costs

FERC on Friday approved Western Energy Imbalance Market (WEIM) tariff revisions to allow generators to include costs associated with the Washington cap-and-trade program in their default energy bids and commitment costs.

The commission approved the revisions over the objection of the Utah Division of Public Utilities (UDPU), which argued the rule changes run afoul of the U.S. Constitution because they impose an unlawful “border tax” on electricity imported into Washington (ER23-474).

WEIM operator CAISO filed the tariff changes late last year in anticipation of the Jan. 1 roll-out of Washington’s cap-and-trade regulations, which require any in-state emitters of more than 25,000 metric tons of carbon a year — including electricity generators — to acquire allowances to cover their emissions. The rules also apply to any electricity imported to serve Washington demand.

CAISO’s rule changes have to do with the reference levels the ISO uses to calculate a resource’s default energy bids and commitment costs for the WEIM. In its filing with FERC, the ISO proposed to alter the reference levels to allow generators selling into Washington to reflect GHG compliance costs in their market bids to ensure that those resources don’t appear be less expensive than their actual costs.

CAISO modeled the changes on tariff provisions already in place to accommodate California’s cap-and-trade program, which is administered by the state’s Air Resources Board (CARB). Under those provisions, the reference levels used in the default energy bid and commitment costs are based on a GHG allowance price derived from the average of two index prices published by separate vendors.

Washington’s cap-and-trade program is not tied to CARB’s, and the Washington-specific provisions approved by FERC on Friday differ in their details because the state’s Department of Ecology will not be holding an allowance auction until later this month, meaning there is not yet a published allowance price available to set the reference level. CAISO instead proposed a three-phase rate that will change in response to certain “triggers,” FERC noted.

In the first phase, before the first auction, CAISO will rely on a reference rate of $41/metric ton (MT), the halfway point between the Ecology Department’s floor and ceiling prices of $19.70/MT and $72.29/MT, respectively. For the second phase, CAISO will use the clearing price from the most recent quarterly auction until index prices become available. In the third phase, the ISO will rely on the average of two index prices from separate vendors, similar to its treatment of the CARB program.

The ISO contended that an index price would eventually provide a more accurate reflection of the price for Washington allowances.

“CAISO indicates that while the auction price is a starting point, as Washington’s cap-and-invest program evolves, CAISO expects market participants will engage in bilateral trading, which will cause deviations from the auction price.  According to CAISO, an index price, updated daily on weekdays, provides a timelier estimate of the allowance price,” FERC wrote.

Constitutional Questions

In approving the WEIM tariff provisions, FERC rebuffed the sole protest by the UDPU, a Utah agency charged with investigating consumer utility complaints and monitoring utility operations to ensure compliance with state Public Service Commission rules.

The UDPU contended that the tariff changes violate the Constitution’s Supremacy Clause because they subject out-of-state generators to Washington’s state-levied allowances, contravening FERC’s “exclusive authority to regulate the sale of electric energy at wholesale in interstate commerce.”

“UDPU states that the CAISO adders for compliance with state-specific cap-and-invest programs will affect the set of resources selected for generation in the WEIM, causing commission-jurisdictional markets to clear in significantly different ways than they would in the absence of those directly-imposed bid costs,” FERC noted.

The agency had also argued that Washington’s cap-and-trade program is unconstitutional under the dormant Commerce Clause because it imposes a “border tax” on energy imported into Washington. And it additionally contended that the program provides preferential treatment to in-state interests because Washington utilities are provided a free allocation of GHG allowances, buffering the state’s ratepayers from the burden of some compliance costs.

The commission said it was “not persuaded” by the UDPU’s arguments, noting that it could only consider whether the tariff provisions were just and reasonable under the Federal Power Act, and not the legality of the underlying law motivating the provisions.

FERC wrote that the revisions “simply allow generators to incorporate compliance costs associated with Washington’s cap-and-invest program in their default energy bids and commitment costs, which account for the variable costs of generation and provide generators a reasonable opportunity to recover their costs.” Those revisions are consistent with other commission-accepted tariff provisions that accommodate the compliance costs associated with state environmental requirements — including in the WEIM, the commission said.

The commission similarly found the UDPU’s “border tax” argument to be aimed at the constitutionality of the cap-and-trade program, saying a FERC proceeding was not the proper venue for addressing such a question.

“In any case, if the commission were to reject CAISO’s filing based on constitutional grounds, and if Washington’s cap-and-invest program were not ultimately enjoined by a federal court, generators would be deprived of the opportunity to recover costs that they are legally obligated to incur,” the commission said. “As long as the tariff revisions at issue apply to the mandatory compliance costs incurred by generators within the borders of Washington and which are subject to Washington’s jurisdiction, we are required to allow the opportunity for their recovery.”

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PJM OC Briefs: Feb. 9, 2023

No Consensus on IROL-CIP Cost Recovery

VALLEY FORGE, Pa. — PJM and its Independent Market Monitor gave first reads of their proposals exploring whether generators should be permitted to recover upgrade costs for facilities determined critical for interconnection reliability operating limits (IROLs) under NERC Critical Infrastructure Protection (CIP) standards.

PJM’s proposal would create a cost recovery mechanism similar to black start service, where expenses can be submitted to both the RTO and Monitor for review and monthly payments would be made from revenue socialized across the RTO. PJM argued that the investments needed to comply with the standards are above what is typically required of generators and there is not a sufficient look-ahead in the analysis its staff does to identify critical facilities for a generator to include its expenses in future Base Residual Auction (BRA) offers. (See “Revisions to IROL CIP Issue Charge Rejected,” PJM Operating Committee Briefs: Dec. 8, 2022.)

Steve McElwee 2022-07-13 (RTO Insider LLC) FI.jpgPJM Chief Information Security Officer Steve McElwee | © RTO Insider LLC

IMM Joseph Bowring said the concept of “cost recovery” is part of the old-fashioned cost-of-service regulatory model that is not relevant to markets. Bowring said it’s already possible for generators to represent their IROL-CIP costs in market offers and it would be inappropriate to create out-of-market cost recovery for the expenses. His proposal would memorialize that there is no cost recovery structure in PJM’s governing documents.

“PJM runs markets,” he said. “PJM is not a regulator.”

Rather than this being an issue for PJM to resolve, Bowring said generators should bear the costs. He compared the situation to investments facilities must make to comply with environmental regulations. No separate cost recovery mechanism was created for those costs, even though they were much larger than the IROL-CIP costs. Bowring also noted that there is no profitability test and that PJM plan proponents have no idea whether the identified generators are already more than covering all costs.

Greg Poulos, of the Consumer Advocates of the PJM States (CAPS), said state advocates are interested in seeing the most reasonable and best costs realized through markets. Creating cost-of-service structures creates a pathway for market participants to argue that each of their unique characteristics is a service that should be compensated.

Jim Davis of Dominion Energy said the comparison to black start is flawed because it is a voluntary service, while IROL-CIP critical status is determined by PJM. He said since that status is reevaluated annually, a facility may undergo significant upgrades only to have its critical marker removed after 12 months.

“The risk those resources have is [that] the rug could be pulled out from under them at the very last minute and have their status reverted back to low,” he said.

Security Update

PJM’s Steve McElwee urged stakeholders to be on the lookout for hackers impersonating known figures and report any suspicious activity to the RTO. He said members recently reported a “phishing” attempt impersonating PJM staff and contacting members saying their accounts are being suspended.

“It really is that partnership for us to be working together,” he said.

Dynamic Line Rating Task Force Update

Stakeholders endorsed the conclusion of the Dynamic Line Rating (DLR) Task Force following the wrap-up of the group’s work providing education as stakeholders and PJM drafted and implemented a new framework to incorporate the technology into its operations.

PJM’s Natalie Tacka Furtaw told the OC that if future issues related to DLR arise, they can be addressed with a new problem statement and issue charge.

Stakeholders approved a problem statement and issue charge alongside a proposed solution under PJM’s “quick fix” process at the April 2022 OC, and PPL went live with the technology in October. The task force continued to monitor the implementation of DLR and its impact to auction revenue rights and financial transmission rights trading; however, there have not been any new requests for information since its December meeting. (See “Dynamic Rating Issue Endorsed,” PJM Operating Committee Briefs: April 14, 2022)

Fuel Supply Overview

Fuel inventories are moving in the right direction, despite natural gas well freeze-offs and the derailment of a train in Ohio disrupting a major cog in the rail system for the eastern PJM region, Brian Fitzpatrick, PJM’s principal fuel supply strategist, told the OC. With stockpiles improving and major transportation risks averted, namely the potential for a railroad strike, PJM is shifting to collecting inventory data biweekly rather than weekly.

“Generally speaking, we’re starting to see an increase back in onsite inventories,” he said.

A cold snap over Feb. 2-4 resulted in freeze-offs amounting to around 2 bcf/d in Appalachian supply, but mild weather has helped build a nearly 7% inventory surplus relative to the five-year average. Fitzpatrick said the impact to supply was minor compared to Winter Storm Elliott, which caused the loss of 10-11 bcf/d. Aside from the Dec. 23-24 storm, he said it has been an otherwise smooth winter for natural gas thus far.

The derailment of a Norfolk Southern train in East Palestine, Ohio, has not caused major issues transporting coal, and Appalachian production remains around 5% above last year’s outputs.

The mild winter has also helped East Coast inventories of diesel and residual fuel oil recover from being notably below the five-year average throughout 2022.

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Environmentalists Applaud Whitmer Budget on Climate Change Issues

Gov. Gretchen Whitmer’s (D) 2023-24 budget proposal calling for about $500 million to fund efforts to reach Michigan’s net-zero goals won praise last week from environmentalists.

Whitmer’s budget, the first of her second term in office, proposes slightly more than $79 billion in total spending, meaning the climate change mitigation spending makes up less than 1%.

But Derrell Slaughter, with the Michigan office of the Natural Resources Defense Council, said Whitmer’s “budget proposal points to the clean energy transition moving forward in Michigan.” While the investments are small overall compared to the entire budget, Slaughter said they would boost jobs, cut consumer electricity bills and lower overall pollution.

And when paired with other spending proposals on issues improving home weatherization, the budget will help many Michiganders, especially those in lower-income households, save money, said Lisa Wozniak, executive director of the Michigan League of Conservation Voters. Whitmer’s proposed budget “puts money back in Michiganders’ pockets while investing in our communities, expanding clean energy and protecting our health,” Wozniak said.

Included in the spending plan is:

  • $150 million in grants for school districts to run electric school buses;
  • $45 million, mostly in federal funds, for the Michigan Clean Fleet Initiative to encourage counties, airports and regional transit systems to upgrade to electric vehicles;
  • $40 million in one-time state general fund monies to help local governments get ready to develop renewal resources;
  • $43 million to help harden the state’s electric grid against natural disasters and severe weather incidents; and
  • $100 million for environmental justices projects.

Whitmer also called for the state to temporarily suspend the sales and use taxes on the first $40,000 of the cost of an electric vehicle.

Charles Griffith with the Ecology Center said the organization would continue lobbying for even more funds to meet the goals of the MI Healthy Environment Plan, but he called Whitmer’s proposal “a great step forward.”

Michigan’s fiscal year runs from Oct. 1 to Sept. 30, and typically the Legislature completes work on the budget by early summer.

The budget has been criticized by Republicans for proposing to spend almost all the nearly $9 billion surplus Michigan received from the federal government, leaving just $250 million that would be allocated to the state’s Budget Stabilization Fund, used during economic recessions to minimize budget cuts.

Republicans also worried the plan is designed to forestall a required income tax cut if the state finds itself with a large budget surplus. Top state officials have not been shy about saying an alternative tax proposal pushed by Whitmer is designed in part to keep the required income tax rate cut from taking place, and thus preventing the political anguish of trying to raise the rate in the event of a recession.

Democrats narrowly hold the majority in both houses of the Legislature: by just one vote in the Senate, and two votes in the House of Representatives.

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FERC OKs Changes to MISO Retirement Studies

FERC on Friday ruled that MISO generation owners must now give a year’s advance notice to the grid operator before they can retire or suspend resources.

The commission approved MISO’s request to double  the amount of time it has historically required GOs to submit the notices under Attachment Y of the tariff, effective Monday (ER23-630). 

The RTO’s requirement that notices be submitted four full quarterly study periods in advance is just one piece of a more rigorous generation-retirement proposal. The grid operator will now conduct retirement reliability studies in batches on a quarterly basis and include extra analysis of thermal, voltage, stability and import limitations. Staff will also halve the time, from 75 to 150 calendar days, that they’ve allotted themselves to notify GOs whether their resources are needed for reliability purposes. (See MISO to File More Stringent Generator Retirement Study Process.)

MISO said it needs the additional notice to better analyze an anticipated slew of retirement requests. FERC agreed.

“As MISO explains, it expects to continue receiving a substantial amount of Attachment Y notices for generator suspensions and retirements,” the commission wrote. “We find that the revisions will enhance the study process by allowing MISO more time to conduct the Attachment Y study that is needed to assess whether the reliability of the MISO transmission system is impacted by specific unit suspensions and retirements.”

FERC’s order also stimulated debate over whether the RTO should share some details of the confidential retirement notices it receives.

The footprint’s industrial customers asked FERC to require more transparency from MISO about its members’ retirement plans, saying the grid operator is “falling short of promoting full and robust transparency that enables forward market signals regarding generation suspensions and retirements for resource adequacy and transmission planning.”

The RTO should immediately and publicly disclose Attachment Y notices it receives so utilities can make timely plans for new generation or demand management, the customers said. FERC said the request was beyond the scope of the proceeding.

Commissioner Allison Clements said though she ultimately agreed with the decision, the secrecy surrounding MISO generation retirements might need some loosening. She said the extended-notice requirement could lead to GOs keeping their suspension and retirement plans under wraps longer.

“Transparency in this context requires a balance between generation owners’ desire for confidentiality and the consumer benefits of earlier notice to allow market forces and planning processes to efficiently respond to generation supply changes,” she wrote. “However, I am not convinced that MISO’s current confidentiality provisions strike that balance appropriately.”

Clements encouraged MISO and its stakeholders to discuss whether “more timely public notice of forthcoming suspensions and retirements is feasible.”

“The primary basis for MISO’s proposal in this proceeding is that the number of generator suspension and retirement requests has substantially increased in recent years, and MISO expects that trend to continue. This means that potential negative effects of insufficient transparency will only grow as the fleet transition continues,” she said.

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RF Panelists: Executive Buy-in Key to CIP Success

Electricity industry leaders are still not taking their critical infrastructure protection (CIP) compliance programs as seriously as they should, speakers at a webinar hosted by ReliabilityFirst warned Monday.

“Every entity I’ve seen since I started working as a CIP auditor back in 2009 … claims to have executive support for their CIP program. And mostly that’s true — but what does support mean?” Lew Folkerth, RF’s principal reliability consultant for external affairs, said at the regional entity’s monthly Technical Talk.

In most cases, he said, “it means that they get some money [and] some people for it, and that’s about as far as it goes. The truly great entities have executives that become directly involved in the CIP and O&P [Operations and Planning] compliance programs.”

As an example of healthy management buy-in, Folkerth described a company he encountered where the CEO had weekly meetings with the CIP team “during a particularly rough period,” and “responded immediately and effectively” when the team described their needs.

Zack Brinkman (ReliabilityFirst) Content.jpgZack Brinkman, ReliabilityFirst | ReliabilityFirst

Zack Brinkman, RF’s manager of CIP compliance monitoring, seconded Folkerth’s sentiments, adding that having access to top executives is “just the beginning.” Beyond paying attention to the CIP team, leadership must speak up for the team within the organization to ensure that staff from other departments take their recommendations seriously, he said.

“You really want to look at executive engagement [and] executive involvement … to have a successful program. You need ownership and accountability,” Brinkman said. “NERC’s CIP [standards touch] all sorts of different departments within an organization, and one of the things we’ve seen here and in the past is … that executive support is really key to trying to break down those silos.”

The discussion also touched on practical tips for making the best impression during CIP compliance audits. Robert Vaughn, a CIP auditor with SERC Reliability, said his top recommendation to electric utilities is to ensure they have as much documentation for their CIP program and potential issues as possible. Vaughn jokingly called documentation “auditor kryptonite,” explaining that “with good documentation, we don’t ask questions; good documentation explains itself.”

“It’s like a good recipe,” he continued. “You don’t have to list every single thing in it, but you want something that is repeatable. You want to be able to produce the same thing over and over again. … I can understand that I won’t know how to do it how entity X does it, but your documentation should carry me 60 to 70% of the way down that road.”

Full documentation can also ensure that entities aren’t too reliant on individuals and their memories, Vaughn told listeners. He recalled visiting a utility whose compliance regime documentation listed three tests that were performed regularly, then speaking with the compliance manager who told him of three more tests that he performed often but did not record. In this situation, Vaughn warned, an unexpected absence by the responsible person could lead to required tasks not being done, or not being done in time.

“You don’t want a situation where Bert and Pete win the lotto and don’t come back from lunch, and nobody can do their” jobs, Vaughn said. “That’s the problem we run into a lot of times; I have … a big flowchart that has a person’s name in [it], and we’re like, what happens if [he] takes a vacation? [They say], ‘Oh, it’s never come up before.’ … That’s not a good process. … You want something that is specific, generic [and] that can survive the test of time.”

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PJM Weighs Options for Winter Storm Elliott Follow-up

PJM last week updated stakeholders on its progress in collecting up to $2 billion in non-performance penalties from capacity sellers who did not meet their obligations during Winter Storm Elliott.

In a filing submitted to FERC Feb. 2, PJM sought approval for a tariff amendment that would allow those charged with capacity performance (CP) penalties to elect to extend their billing period up to nine months when the charges are levied near the end of a delivery year (ER23-1038).

Under current practice, PJM typically takes three months to send out penalty notices after a performance assessment event (PAI) in which generators do not meet their capacity obligations. The penalties must then be paid by the end of the delivery year.

The Winter Storm Elliott PAI event, which occurred at the end of 2022, would leave generators about three months to make the payments, exacerbating concerns that the scale of the penalties could lead to defaults. (See PJM Gas Generator Failures Eyed in Elliott Storm Review.)

PJM’s proposal would allow for the RTO to extend the billing period when the timing of the determination of the charges would leave fewer than six months to make payments, with the tradeoff of any payments made in the next delivery year being subject to interest at the FERC prevailing rate.

Since both options carry downsides, neither is being considered the default and PJM is asking those assessed penalties to notify staff of which billing timeline they are opting for by March 17, PJM CFO Lisa Drauschak said during a Feb. 8 presentation to the Market Implementation Committee. The RTO’s FERC filing requests an order by April 4 to potentially allow for the new system to be put in place before stakeholders elect their timelines.

Drauschak said PJM hopes that extending the time for making payments will maximize the RTO’s ability to collect non-performance charges while reducing the reliability risk from a significant number of resources defaulting and leaving the capacity market.

PJM released preliminary unit-specific data on CP charges and bonuses to relevant generators on Friday; however, Drauschak said the RTO does not usually publicly release preliminary aggregate figures.

Constellation’s Jason Barker said he was disappointed that PJM has yet to release a more refined estimate of the total expected penalties, adding that he’s unconvinced by PJM’s argument that it hasn’t been past practice given the magnitude of the emergency.

PJM Changes Data Collection System

PJM is allowing generation owners to revise their ticket submissions in its eDART outage reporting tool, which the RTO’s Dan Bennet said is used to derive CP performance data and the scale of any non-performance charges applicable for a given resource. Bennett presented to the Operating Committee on Feb. 9.

“We rarely make retroactive ticket changes, but given the nature of this event, … we wanted to make sure the data was accurate,” he said.

After reviewing data submitted to eDART and NERC’s Generating Availability Data System (GADS), the RTO and its Independent Market Monitor have found a wider difference than expected. While some discrepancy is to be expected given the real-time nature of eDART and the more precise data entered into GADS after an event, the usage of eDART data in determining performance charges makes accuracy crucial.

Calpine’s David “Scarp” Scarpignato said that in the heat of events, generation operators often enter data at control centers rather than at the individual units and tend to be more conservative in representing their outages to ensure compliance.

Several stakeholders reported having trouble with updating their eDART data; PJM recommended that anyone running into issues reach out to its staff and the Monitor.

PJM has also opened a new SharePoint site to submit unit-specific inquiries and documentation regarding performance during the 277 PAIs over Dec. 23-24. PJM’s Melissa Pilong recommended that submissions be made prior to March 6 to give PJM time to respond prior to the start of the billing period.

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PJM MIC Briefs: Feb. 8, 2023

Vote on Multi-schedule Modeling of Combined Cycle Units Deferred

VALLEY FORGE, Pa. — The PJM Market Implementation Committee deferred a vote on adopting a problem statement and issue charge to discuss combined cycle modeling in the market clearing engine (MCE).

Following a lengthy back-and-forth on how broad the scope of the issue charge should be, PJM revised its proposed framework for the process.

The use of multi-schedule modeling for combined cycle is being considered as MCE software provider General Electric collects design preferences from PJM while building its Next Generation Markets Systems (nGEM).

Much of the discussion has focused on what types of schedules and selection methodologies should be considered in scope. PJM had initially presented a narrower issue charge that would have limited the scope to the “schedule selection process for commitment and dispatch for day-ahead and real-time energy market for all resource types outside of the MCE.” (See “Feedback on Issue Charge, Problem Statement for Combined Cycle Modeling,” PJM MIC Briefs: Dec. 7, 2022.)

After several stakeholders expressed concern that the issue charge was too narrowly focused on a specific solution rather than an issue, and Deputy Monitor Catherine Tyler presented an issue charge with a broader approach, PJM agreed to include a handful of items to be in scope.

Tyler said that of the six options that PJM had identified in its white paper as solutions to the issues, PJM had attempted to define four options as out of scope and therefore not part of the discussion.

PJM opposed the Monitor’s proposal to include additional education in the issue charge, and stakeholders ultimately voted, with 60.8% in support, to defer adoption of the problem statement and issue charge to the MIC’s March meeting to allow for more time to review the revisions.

In a white paper that PJM’s Keyur Patel presented to the MIC, PJM stated that applying multiconfiguration modeling to its enhanced combined cycle model would allow for the MCE to capture the characteristics of individual resources and improve their dispatching. The number of configurations and schedules combined cycle units can present could lead to exponentially increasing times for the engine to complete optimization calculations.

PJM believes the best solution would be to adopt a design that would only enter one schedule to the MCE for commitment, according to the white paper. In seeking to limit the scope, the paper said that PJM is seeking to resolve the calculation issue while minimizing the impact to the current market rule.

Patel also said PJM is on a time crunch to reach a solution by the third quarter, when GE is set to begin incorporating the RTO’s guidance into a new software package.

Tyler argued that PJM’s preferred solution of using a specific and flawed predefined formula for schedule selection would weaken market power mitigation rules and fail to address issues with their implementation that the IMM has identified for many years.

Stakeholders Consider Recognition of Local Impacts to Net CONE

PJM presented a first read of the updated default gross cost of new entry (CONE) and avoidable cost rate (ACR) figures it is proposing through its quadrennial review. The new parameters will be used for the 2026/27 delivery year.

All resource types, except storage, would see their gross CONE figures increase, largely because of the Inflation Reduction Act’s changes to the investment tax credit (ITC) and new reference resources used for combined cycle and onshore wind resources.

The main changes to gross ACRs proposed are the addition of steam oil and gas as a new resource type, additional data from the Nuclear Energy Institute on nuclear costs, and refined property tax and insurance costs. Single-unit nuclear generators were the only resource type to see a decrease in default ACR.

Gas resources would see the largest increase under the new numbers, with combined cycle units increasing to $540/MW-day of nameplate output from the 2022/23 gross CONE of $320, a nearly 69% increase. Combustion turbines would go up to $427/MW-day from $294, a 45.2% increase.

Local Considerations for Net CONE

Stakeholders also discussed their interests and goals as they consider whether to allow PJM to include state and local issues in the formation of net CONE.

The items added to the interest identification matrix include ensuring that the net CONE established for an area reflects the most environmentally restricted asset life; avoiding substantial changes to the methodology of setting the end figure without considering the impact to the variable resource requirement (VRR) curve; and ensuring that the role of net CONE and the VRR curve are consistent with state policies that impact the parameters.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said he supports having an estimate of the CONE for constrained locational deliverability areas (LDAs) in instances where there are environmental restrictions such as legislation or regulations reducing the asset life.

“The reason this issue has been brought up is because of what’s been going on in Illinois and potentially in New Jersey,” he said. “Clearly they’re moving in the direction of a much cleaner fleet, and that eventually could have implications.”

First Read of PJM Proposal on Co-located Load

PJM presented a proposal to define market rules for load behind a generator’s meter months after the MIC rejected two competing proposals from the Monitor and Constellation Energy and Brookfield Renewable Partners. (See “Limited Support for Co-located Load Proposals,” PJM MIC Briefs: Dec. 7, 2022.)

The previous discourse around the proposals centered on their treatment of co-located load that is not directly interconnected with the wider PJM grid and whether the generator should be permitted to retain its capacity interconnection rights (CIRs) for the portion of its output that serves that load.

Constellation argued that when the behind-the-meter load is highly interruptible and the generator can quickly shift its output back to the grid to fill its capacity obligations, it should be permitted to retain its CIRs.

During a first read of the RTO’s proposal Wednesday, PJM’s Lisa Morelli said generators would be able to retain their CIRs under such an arrangement, but the generator would be subject to ancillary services charges, such as black start, regulation and reserves, for the load. Even without a direct connection to the grid, Morelli said it’s PJM’s belief that the load indirectly benefits from those ancillary services through the generator.

PJM’s Tim Horger said that if a generator and co-located load would not be able to operate independently of the grid, it is reliant on the grid and should have to pay the charges.

Constellation’s Jason Barker said the company is opposed to the proposal, saying it effectively requires host generators to pay for ancillary services that PJM attributes to retail load, who are not PJM members.

Adrien Ford, of the Old Dominion Electric Cooperative, said she is opposed to allowing generators with co-located load to retain the output earmarked for the load and said PJM is trying to draw parallels between co-located load and behind-the-meter generation. She also said there has not been adequate weigh-in on whether co-located load is under FERC or state jurisdiction.

Monitor Joe Bowring indicated his surprise that PJM was now taking the initiative to support Constellation’s proposal, given that it had received no stakeholder support in the RTO’s poll and, he argued, would undermine markets.

No Consensus on Changes to MSOC

Stakeholders were divided on changes that could be made to the marker seller offer cap for the 2025/26 Base Residual Auction to reflect the impact of December’s Winter Storm Elliott. Much of the discourse was in line with the discussion at the Resource Adequacy Senior Task Force’s Jan. 31 meeting, with stakeholders stating that they want additional information about how the 277 performance assessment zones on Dec. 23 and 24 will affect units’ Capacity Performance quantified risk (CPQR) and related parameters. (See PJM Stakeholders Discuss Capacity Market Changes After Winter Storm.)

Jeff Whitehead of GT Power Group said market sellers currently have no insight on how their unit-specific offer caps will be evaluated by the Monitor and PJM. Without a firm understanding of what the status quo looks like, he said it is difficult for stakeholders to start working on solutions.

Bowring said it is fairly simple to include the data from the storm into the IMM’s assessment of their risk, but that risk will vary widely for individual generators, preventing him from speaking in general terms. He encouraged generators to reach out to the Monitor for unit-specific information, but he said no generators had contacted it yet.

Bowring said that for some units, the impact of Elliott would be to reduce their CPQR risk, while for poorly performing resources, the impact would the opposite. “On average, the impact of Elliott on CPQR risk is relatively small. This is the first significant event since the introduction of the Capacity Performance market design.”

PJM’s Dave Anders said implementing changes in time for the 2025/26 BRA, scheduled for June, would have to follow a tight timeline with two possible pathways: delaying the auction, or keeping the bid and clearing timing and seeking FERC approval to alter the pre-auction timeline. Wrapping up Wednesday’s discussion, Anders said he had not heard a preference for either option.