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November 5, 2024

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Vegetation Eyed in AEP Ohio Outages Following Storms

VALLEY FORGE, Pa. —American Electric Power (NASDAQ:AEP) has identified vegetation as a likely cause of the transmission line failures that left more than 240,000 customers in Ohio without power for up to two days following violent storms in June, PJM officials said last week.

PJM ordered load sheds on three of AEP’s 138-kV lines to prevent overloads and cascading outages June 14 after a storm identified as a derecho downed power lines. (See AEP Under Fire as Load Sheds Persist in Ohio.)

Although the cause of the line tripping remains under investigation, AEP said vegetation was a contributing factor, Paul McGlynn, PJM executive director of system operations, told the Markets and Reliability Committee on Wednesday. “Whether vegetation was blown into the lines or whether there were encroachment issues, we don’t have the answers yet,” he said.

Monday, June 13: Load Forecast Falls Short

McGlynn and other PJM officials gave the MRC an in-depth briefing on the RTO’s challenges in mid-June, which began Monday, June 13, when load peaked around 136 GW, well above the forecasted 128 GW. McGlynn said PJM’s under-forecast was 1,800 MW during the “valley” overnight, rising to 8,000 MW by noon.

The load forecast fell short because of weather that was warmer and more humid than expected, and storms expected to provide cooling did not arrive until after the evening peak. “If we had perfect weather knowledge, [the load forecast] would have been spot on,” McGlynn said, citing backcasts the RTO did after the event.

The RTO also saw generation losses of about 1,150 MW and a constraint, followed by an overload, on the 500-kV Peach Bottom-Conastone line that impacted what resources the RTO could bring online. It responded by taking transmission loading relief procedures, “something we don’t do all that frequently,” said McGlynn.

It also called on little-used combustion turbines to maintain reliability. The RTO activated almost 26,000 MW of CTs, versus the 16,000 MW it had expected to use.

“It was tighter than we anticipated, but we were reliable through the whole operating day,” McGlynn said. The result was “some fairly high prices through the peak period.” LMPs peaked at $2,643/MWh in the 4-5 p.m. ET hour.

Independent Market Monitor Joe Bowring said PJM exported about 4,000 MW to MISO “when it was economically illogical.”

“We will investigate the reasons,” he said in an email after the meeting.

PJM dispatch also approved 35 shortage intervals between 2:55 and 6:05 p.m., said Phil D’Antonio, director of energy market operations.

“I’m surprised we would dispatch so tight to the timing of a thunderstorm,” said Public Service Enterprise Group’s Gary Greiner.

“Storms are sometimes a challenge to predict as to when they will occur” and where, McGlynn responded.

Tuesday, June 14: Storms Down Lines, Poles

When the storms finally arrived late Monday night and continued into Tuesday morning, they were violent and set off tornadoes in Ohio, McGlynn said. AEP Ohio reported wind gusts as high as 95 mph, which downed poles and lines across its service territory.

Between 1 and 2 p.m. June 14, nine 138-kV facilities tripped in the AEP zone, with loads on several facilities above their load dump rating.

Timeline of performance assessment intervals (PJM) Content.jpgTimeline of performance assessment intervals, June 14-16. | PJM

Beginning at 2:02 p.m., PJM issued the first of several load-shed directives to AEP, triggering performance assessment intervals (PAIs), in which capacity resources face penalties for shortfalls in output.

Fearing multiple cascading overloads, the RTO also called on pre-emergency and emergency demand response in the Marion area of AEP at 3:50, followed at 7:21 by an additional load-shed directive to prevent a potential N-5 cascading outage on the 138-kV Beatty-Bolton line.

Wednesday June 15: More Line Failures

In the early morning hours of June 15, AEP returned to service several lines that had tripped the previous day. PJM cancelled its load-shed directive at 3 a.m.

But over a 10-minute period ending at 10:40 a.m., three 138-kV lines in AEP tripped. PJM issued a load-shed directive to relieve an overload on the 138-kV Gahanna-Hap Cremean line at 10:41, just a minute before that line also tripped, triggering another PAI.

At virtually the same time, AEP restored service to the 345-kV HyattCS-Hayden line, which had been recalled on Tuesday from a maintenance outage. McGlynn said the timing of the restoration was a coincidence and that officials don’t know whether an earlier restoration might have prevented the Gahanna-Hap Cremean overload. “It’s certainly something we’re looking at,” he said.

At 10:50, PJM again called for pre-emergency and emergency DR in the Marion area, followed 50 minutes later by another load-shed directive issued to prevent a potential N-5 cascading outage for the 138-kV Kenney-Roberts line.

It wasn’t until 10:25 p.m. that several lines returned to service and load decreased enough to end the load-shed directives and the PAI.

Thursday June 16: Hot Weather Alert

On Thursday, June 16, PJM issued a hot weather alert for the western part of the RTO. At 10:36 a.m. the 138-kV Corridor-Blendon line, which had tripped the previous day, tripped again, but there was sufficient generation to control the constraint.

PJM used contingency switching where it was able to manage thermal loading. But as load continued to increase, PJM — with no generation or switching available — issued several post-contingency local load relief warnings.

After the 138-kV Corridor-Morse line tripped about 12:18 p.m., PJM again called on DR for the Marion area about 12:30, initiating another PAI. The DR was canceled about four and a half hours later, following the return to service of the 138-kV Bexley-St. Clair and Morse-Spring Rd-Genoa lines.

In total, about 100 MW of DR was called to reduce load, but because operators had not defined a closed-loop interface, DR did not set LMPs. Instead, price was set by the worst contingency in PJM’s security-constrained economic dispatch.

McGlynn said the load sheds began with 160 MW and grew to “several hundred” megawatts.

Rebecca Carroll, senior director of market design, said there were 345 PAIs over about 11 hours during the week — the first PAIs since 2019, when 24 occurred.

Under PJM’s confidentiality rules, officials said, balancing ratios will not be posted for the PAIs because there were a small number of generation owners with capacity resources in areas affected by the emergency actions.

Mike Bryson, senior vice president of operations, said AEP, PJM, NERC and ReliabilityFirst are investigating and will produce “lessons learned” in four to 10 weeks, with updates at monthly Operating Committee meetings.

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Counterflow: Say It Ain’t So, Joe

tesla powerwallSteve Huntoon | Steve Huntoon

As the story goes, Shoeless Joe Jackson was leaving the Cook County Courthouse in 1920 amid the Black Sox scandal when a kid yelled, “Say it ain’t so, Joe!” [1]

I felt like that kid when I read that FERC proposes to wipe out competition in transmission.[2]  

What’s the public policy case for this? The oft-repeated claim that transmission competition isn’t working. I call this truth by repetition.[3]

The reality, as I pointed out five years ago,[4] is that transmission competition works great — when and where it’s allowed to work. The problem is that it’s been hobbled since its advent in FERC Order 1000. As Professor Paul Joskow concludes: “The progress has been slow but promising.”[5]

Transmission Competition Works 

Let me give you an example of how transmission competition works. PJM biennially identifies highly congested facilities and has a competitive solicitation for solutions. The table below shows the most recent PJM evaluation of proposed solutions to one source of congestion.[6]

PJM APS Proposals (PJM) Content.jpgPJM selected Proposal 756, which called for spending $770,000 on terminal equipment upgrades at the French’s Mill and Junction 138-kV substations, to improve market efficiency in the APS zone. Proposal 547, a new 500-kV line found to be slightly less effective, would have cost more than $136 million. | PJM

 

Proposal 756 above is 100% effective at mitigating congestion and costs $770,000; Proposal 547 is 99.97% effective and costs $136,070,000. Which should consumers have to pay for?

Here’s the rub: Absent a transparent, competitive process, how would anyone know about the $770,000 solution? And no one being the wiser, if the notice of proposed rulemaking is correct that adding rate base is what incents transmission owners,[7] why wouldn’t a TO want the $136,070,000 solution?

Please note that consumers are not well protected by regulatory oversight. As Joskow observes: “FERC does not have a well-developed process to scrutinize the costs presented to it for inclusion in the transmission owners’ revenue requirements or a history of disallowing unreasonable costs.”[8]  

Even when the competition is not in solutions, but simply in procurement of the same basic project, national and international experience suggests cost savings in the 20 to 30% range.[9] And this is capital cost savings, which does not include the additional savings from a lower cost, competitive capital structure for determining the annual revenue requirement.

Exceptions to Competition: NOPR Misdiagnosis and Misdirection

The NOPR says the problem with competition is that TOs are motivated to avoid it through exceptions, which leads to smaller, less expensive solutions.[10] As I said in my last column,[11] that can be a good thing! Why build large greenfield transmission lines when a simple upgrade relieves the problem (like the PJM example in the prior section)?

If there really is a problem with an incentive for less expensive solutions because of exceptions, the right answer is to minimize the exceptions. Not go the other way and eliminate competition!

The NOPR’s Substitute is Escher Stairs Leading to Synthetic Monopoly

Finally, a few words about the NOPR’s proposed substitute for competition: Requiring some sort of joint ownership of a given project. For anyone concerned about delays in getting new transmission built, please read NOPR paragraphs 358-382, and contemplate the endless squabbling and litigation that this concept portends. The possibilities are endless!

As for the NOPR notion that joint ownership could somehow provide “at least some of the potential cost-related benefits of competitive transmission development processes,”[12] let’s recognize that each joint owner would have a shared interest in building the most expensive project possible. That is a coordinated oligopoly, and it performs no differently than a monopoly.[13] Not to be confused with competition!

In Short

FERC, please preserve and expand competition, a better angel of our nature.

[1] Baseball buffs know that the story is mostly false. Some White Sox players were bribed to throw the 1919 World Series, but there’s no evidence Shoeless Joe Jackson was one of them. And there probably wasn’t a kid. More here: http://www.thisdayinquotes.com/2009/09/it-ain-so-joe-actually-wasnt-so.html

[2] Building for the Future Through Electric Regional Transmission Planning and Cost Allocation and Generator Interconnection, Notice of Proposed Rulemaking, 179 FERC ¶ 61,028 (April 21, 2022) ¶ 351-353; https://www.rtoinsider.com/articles/30016-analysis-ferc-giving-up-on-transmission-competition     

[3] For a compilation of transmission owner complaints about competition, please see the Reply Comment of the Harvard Electricity Law Initiative here, https://elibrary.ferc.gov/eLibrary/filedownload?fileid=708A1BD1-1F98-CFCD-9EE1-7D7298400000. 

[7] NOPR ¶¶ 350, 353, 355, 358, 375.

[9]  https://www.brattle.com/wp-content/uploads/2021/05/16726_cost_savings_offered_by_competition_in_electric_transmission.pdf, page 1. In SPP’s most recent competitive procurement, the successful bid was 43% less than the highest bid, and the successful bid had excellent other features.  https://www.spp.org/documents/66929/minco-pleasant%20valley-draper%20rfp%20iep%20public%20report.pdf, pages 67-69. 

[10] NOPR ¶¶ 350, 353, 355, 358, 375.

[12] NOPR ¶ 358.

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Oregon Moving to Adopt California’s Advanced Clean Cars II Rules

Oregon is setting a course to adopt proposed California regulations that would require both states to phase out the sale of gasoline-powered cars by 2035.

Oregon is already one of 17 states to have adopted California’s vehicle emissions standards under Section 177 of the Clean Air Act. That federal statute allows states to substitute the California Air Resources Board’s (CARB) strict emissions rules for the U.S. EPA’s less stringent ones.

CARB’s existing set of tailpipe rules, Advanced Clean Cars I (ACC I), cover the control of both smog-producing criteria pollutants and greenhouse gas emissions. A later amendment to ACC I added a “technology-forcing” component that requires automakers to sell a specific percentage of the cleanest cars available each year, including full battery-electric, hydrogen fuel cell electric and plug-in hybrid electric vehicles (PHEVs).

CARB’s proposed ACC II rules would expand the standards to require all cars sold in California to be zero-emission vehicles (ZEVs) beginning in 2035. The proposed rules would require 35% of the state’s auto sales to be ZEVs by 2026, 51% by 2028 and 69% by 2030. (See CARB Tuning up Advanced Clean Cars II Rules.)

CARB expects to release a draft final version of the rules this month, followed by a 15-day comment period.

Rachel Sakata, senior air quality planner for the Oregon Department of Environmental Quality (DEQ), said her agency thinks the CARB timeline for adoption is doable for Oregon, despite a current shortage of vehicles and the fact that ZEVs accounted for just 7.8% of the state’s passenger car purchases last year, compared with the state’s 4.5% requirement for 2021. ZEV sales are projected to hit 9.9% of total sales this year, exceeding the 5.3% requirement, indicating the state could meet the more aggressive ACC II goals.

“This is something that we as a state feel is going to be achievable for the manufacturers just given where they’re going with vehicle sales right now and what they are planning to do in the future,” Sakata said Wednesday during a DEQ webinar to launch the process for adopting the ACC II rules.

DEQ would be charged with administering the rules, if adopted. Adoption of the program would exceed the mandate laid out in Oregon Senate Bill 1044, which requires that at least 90% of all passenger vehicle sales in the state be ZEVs by 2035.

Mirroring California

During Wednesday’s call, Sakata acknowledged that the costs of most battery-electric vehicles (BEVs) still put them out of reach for many residents. But she expressed confidence the price gap with conventional cars will narrow as automakers scale up battery production, with price parity for most vehicle types projected to be reached around 2033. In the interim, she pointed out, Oregon offers incentives to make BEVs more affordable.

“We’re cognizant that until there’s this price parity, there’s going to be a little bit extra needed to help people make this transition to electric vehicles,” she said.

Although Section 177 gives states some flexibility in how extensively they adopt the full set of ACC II rules, Sakata said Oregon will be looking to “pretty closely mirror what California has proposed.”

That would include updating the program in which auto manufacturers earn credits for the number of clean vehicles they sell in the state. Oregon’s updates would likely follow California’s proposals, including a requirement that vehicles eligible for earning credits have a minimum electric range of 150 miles for BEVs and 50 miles for PHEVs.

A “durability” component of the credit program would require that vehicle batteries retain 80% of their certified range for 10 years or 150,000 miles and be equipped for Level 1 or 2 charging capability. Manufacturers would also have to make provisions for battery recycling.

The credit program would also mirror California’s overall design of allowing automakers to bank “historical” credits for future use after they fulfill a sales requirement in a given year. Manufacturers could also cash in “pooling” credits accumulated across other participating ACC II states with high EV sales.

The DEQ is also looking to adopt a provision in which automakers can earn environmental justice (EJ) credits through efforts to get EVs into disadvantaged communities. That would include offering discounted vehicles to community-based clean mobility programs, ensuring the availability of used EVs or making lower-priced EVs.

Following the California plan, Oregon would cap automakers’ annual use of historical credits at 15% of all credits and EJ credits at 5%. Pooling credits would be capped at 25% starting in 2026, declining to 5% in 2030.

One participant on the call asked whether Oregon has the grid capacity to handle the influx of EVs that would result from adoption of the rules.

Sakata said the state is working to increase the number of EV charging stations statewide, including a $100 million investment by the Oregon Department of Transportation over the next five years to install chargers along major road corridors and to increase charging access in rural areas, underserved communities and at apartment complexes.

“We’re working and talking with the utilities, as well as the Public Utility Commission about what’s going to be needed to ensure that there’s adequate infrastructure buildout and adequate charging capability to meet this demand,” Sakata said.

The DEQ will hold public stakeholder meetings to discuss the rules in July, followed by advisory committee meetings in July and August. Agency staff expect to post draft rules for comment in September and will seek approval of the final rules by the state’s Environmental Quality Commission in November or December.

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Report Examines Initial Wash. Cap-and-trade Prices

Initial prices for Washington cap-and-trade emissions allowances will depend on whether the state joins with the California and Quebec emissions trading system, according to economic analysis released Friday.

North America will soon have two cap-and-trade systems: the existing Western Climate Initiative (WCI) serving California and Quebec and another scheduled to go online on Jan. 1, 2023, in Washington.

Washington’s legislature passed a cap-and-trade law in 2021, ordering the state’s Department of Ecology to map out the regulations in 2022. Final regulations are expected to be adopted late this year. (See Cap-and-trade Project to Provide Wash. $500M Annually.)

Under the program, the Ecology Department will auction a still undetermined number of emissions allowances four times a year to smokestack industries. The first two auctions are scheduled for the first half of 2023, and the state will set the number of emissions allowances 60 days prior to the auctions.

Companies would bid on the allowances in clusters of 1,000 individual allowances. The number of allowances will be decreased over time to meet 2035 and 2050 decarbonization goals. Companies will be allowed to buy, sell and trade those allowances. If Washington chooses to join the WCI, it will expand its purchase and trading territory to those two areas.

For each auction, a specific number of allowances would be made available to bidders. All bids must be above a certain price level set in advance by the state.

The highest bidder would get first crack at the limited number of allowances, while the second highest bidder would get second crack, followed by additional iterations. The auction ends when the last of the designated number of allowances is bid upon. Then all the successful bidders pay the same clearing price set by the lowest successful bid. Bidding companies are limited to acquiring 4% to 10% of the total number of allowances, depending on various criteria.

Washington retained McKinsey & Co. subsidiary Vivid Economics to perform the pricing study, which examines three scenarios.

In the first, “linking” scenario, Washington joins the WCI by 2025.

In the second, “frontloading” scenario, Washington goes solo with a system in which Allowance Price Containment Reserve (APCR) allowances for 2023-2030 are placed into the APCR at the beginning for 2023. The APCR is designed to act as a safety reserve from which additional allowances can be sold if allowance prices rise quickly enough to potentially cause an economic shock.

The study’s third scenario has Washington going solo without linking to the WCI or frontloading the APCR.

In examining the “linking” scenario, Vivid found it more complicated to estimate prices than for the solo effort because the California-Quebec cap-and-trade market is five time the size of Washington’s and would be the dominating market force in setting auction prices.  Vivid said more analysis is needed to get a good grasp on floor prices with Washington, California and Quebec sharing the same program. The report anticipates that if a link-up occurs, Washington’s floor price would be $41 per metric ton (MT) in 2023.

In the “frontloading” scenario, Vivid calculated that the allowance floor price would be $58/MT beginning in 2023, $64/MT from later in 2023 to 2027, and $89 per metric ton from later in 2027 to 2030.

In the third scenario, Vivid estimates allowances would cost $68/MT in 2023, $71/MT from later in 2023 to 2027, and $89/MT from later 2027 to 2030.

A 2021 Washington Department of Ecology report put the state’s carbon dioxide emissions at 99.57 million metric tons in 2018. The report shows that from 2016 to 2018 the transportation sector was the largest contributor at nearly 45% of emissions, followed by industry (19%), electricity consumption (17%) and agriculture (7%). A 2008 law calls for overall emissions to be reduced to 50 million MT by 2030, 27 million MT by 2040 and 5 million MT by 2050.

The Vivid report said that roughly 68 million MT of Washington’s carbon emissions current fall under the cap-and-trade law’s jurisdiction.

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Mass. Sets New 2025, 2030 Emissions Goals

Massachusetts Secretary of Energy and Environmental Affairs Bethany Card adopted state emissions limits Thursday of 33% below 1990 levels of greenhouse gas emissions by 2025 and 50% by 2030. Along with the new goals, the Baker administration released a final version of its 2025/2030 Clean Energy and Climate Plan, a broad document illustrating how the state can meet those milestones.

The plan also sets individual industry submits, aiming for 49% reductions in heating and cooling by 2030, 34% in transportation, 70% in electric power and 82% in natural gas usage, all relative to 1990 levels.

In transportation, it calls for reducing vehicle miles traveled and putting 900,000 electric vehicles on the road by 2030. To support the EV transition, the plan calls for deployment of 75,000 EV chargers. Among the actions the state will take to expand charging will be development of a model building code that municipalities can adopt requiring make-ready charging in new commercial and residential buildings.

The building emissions plan relies on improving energy efficiency in buildings and converting heating systems to electric heat pumps. Under the state’s climate law, the Department of Environmental Protection must adopt regulations for heating sources that emit GHGs to ensure the state meets the new building sector emission sublimits. According to the plan, the department will initiate a stakeholder process this year on those regulations, with a goal of finalizing them by the end of 2023 to take effect “as early as 2024.”

Plans for decarbonizing the electric power system will focus heavily on cooperation with other New England states on electricity system and wholesale market planning, and the state will invest in offshore wind and grow its solar and storage industry, the plan said. The state also expects to work with neighboring states, federal agencies and ISO-NE to develop a regional plan for OSW transmission.

Among the state’s strategies for minimizing the growth of non-energy emissions is the possible adoption of new regulations on hydroflourocarbon gases to help curb emissions from leaking refrigeration systems and natural gas infrastructure.

The plan features a commitment to equity, with a focus on ensuring that decarbonization affects communities across the state equally.

Officials also announced Thursday that the state surpassed its 2020 goal of reducing emissions by 25% below 1990 levels, reaching an estimated 31.4% decrease.

But environmental advocates called on the state government to move more aggressively to curb emissions.

“It’s clear that the state is lagging behind where we need to be in slashing climate-damaging emissions,” said Caitlin Peale Sloan, vice president of Conservation Law Foundation Massachusetts, in a statement. “This administration and the next one need to prioritize real movement in existing policies to match the analysis in this plan, which relies heavily on vague proposals for programs yet to be developed.”

She said CLF will be pushing officials to improve on the plan.

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California Program Seeks Applicants for Hydrogen Fueling Projects

A program described as a first-of-its-kind incentive for medium- and heavy-duty ZEV infrastructure in California is now accepting applications for hydrogen fueling projects.

The program, called Energiize, opened the application period on June 30. The deadline to apply is July 14 at 5 p.m.

The competitive funding round will award a total of $17 million in incentives. The incentives will cover up to half the cost of a hydrogen fueling station project, helping to pay for equipment such as hydrogen dispensers, piping and point-of-sale systems.

The maximum incentive is $3 million. But so-called Jump Start projects are eligible for incentives covering 75% of costs, up to a maximum of $4 million.

Applicants potentially eligible for Jump Start include small businesses, certified minority businesses and veteran-owned small businesses. Public transit or school district projects built in disadvantaged communities may also qualify.

The program is open to commercial fleet or vehicle operators, or vendors applying on their behalf. The project may be a new fueling station or expansion of an existing station.

Speeding Infrastructure Roll-out

Energiize, whose full name is Energy Infrastructure Incentives for Zero-Emission Commercial Vehicles, is being funded by the California Energy Commission.

In March 2021, the CEC selected CALSTART to design and run the program. Energiize has a total authorized allocation of $276 million through 2026.

The CEC described the program as a first-of-its-kind project intended to speed the deployment of medium- and heavy-duty ZEV infrastructure to accommodate future ZEV fleets.

Energiize will help the state meet the goals of an executive order that Gov. Gavin Newsom issued in September 2020, requiring all medium- and heavy-duty vehicles in the state to be zero-emission by 2045, where feasible, the CEC said.

Energiize opened its first round of funding in March. Called EV Fast Track, the incentives were aimed toward charging infrastructure for commercial fleets of medium- and heavy-duty battery-electric vehicles.

The EV Fast Track incentives were offered on a first-come, first-served basis. The $16.24 million in incentives were snapped up within seconds.

The incentives went to nearly 40 applicants across California, to commercial transportation operations including drayage, refuse, school bus and delivery services. And 85% of applicants qualified for the larger Jump Start incentive, CALSTART said in a release.

In addition to the EV Fast Track and hydrogen fueling funding lanes, Energiize will offer incentives this year for public charging infrastructure and EV Jump Start applicants.

Application Process

EV Fast Track is the only Energiize funding lane that is first-come, first-served. Incentives in the other lanes, including hydrogen fueling, will be awarded on a competitive basis.

A recent CALSTART webinar explained the application and scoring process for hydrogen fueling infrastructure incentives.

Applicants must submit information including proof that they’ve met the project’s first “critical milestone,” which is securing the project site through means such as an easement or executed lease.

Applicants must provide confirmation from the local utility that the site is prepared to receive the energy needed for the infrastructure project.

Applicants must also answer three “qualitative” questions. The first asks how the infrastructure will target medium- and heavy-duty ZEVs, and how the operator plans to get the most use out of it over time.

The applicant is asked to detail community buy-in and support for the project. The third question is about benefits the project will provide for local residents, such as paid workforce development opportunities, expanded transit service or hydrogen fueling discounts.

Incentive recipients will be required to operate the equipment in California for at least five years.

“This is a big investment,” said Amy Gower, a CALSTART lead project manager. “We want to make sure that this infrastructure is in the ground for as long as possible.”

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PJM TOs, Consumer Advocates at Odds over DEA Inquiry

VALLEY FORGE, Pa. — PJM consumer advocates and transmission owners appear headed for a showdown over a proposed initiative to review the RTO’s use of designated entity agreements (DEA).

Consumer advocates narrowed their differences with TOs but were unable to “get across the finish line” with a consensus issue charge, Denise Foster Cronin, of East Kentucky Power Cooperative, told the Markets and Reliability Committee at its meeting Wednesday.

As a result, members will be asked at the MRC’s meeting this month to choose between two competing issue charges for a review of the DEA and PJM’s use of it, including potential changes based on the experience with the implementation of FERC Order 1000.

The major difference between the two issue charges, Foster Cronin said, was TOs’ insistence that revisions to the rights and responsibilities of PJM and the TOs under the Consolidated Transmission Owners’ Agreement (CTOA) be out of scope.

The initiative arose from a 2018 FERC order rejecting PJM’s request to revise the Operating Agreement to exempt incumbent TOs from executing the DEA (ER18-1647). (See FERC Rejects PJM Exemption for Incumbent TOs.)

PJM had proposed two changes to the competitive proposal window process mandated by Order 1000. The commission approved PJM’s request to allow transmission developers 60 days to accept a DEA after receiving it as the winner of a competitive project under Order 1000.

But the commission rejected the request to exempt incumbent TOs from executing a DEA for Regional Expansion Transmission Plan (RTEP) projects that the OA requires PJM to designate to an incumbent. Such projects include TO upgrades; projects that would alter the TO’s use of its right of way; and those located solely within a TO’s zone that are not cost allocated outside.

The commission rejected TOs’ rehearing request in 2019, saying that breaching a DEA is more expensive for nonincumbent TOs, which are subject to meeting construction milestones that may be delayed for reasons beyond their control while incumbent TOs only risk breaking the terms of a CTOA by missing scheduled in-service dates.

Unlike incumbents, nonincumbents must also “obtain a letter of credit or other financial instrument equal to 3% of the incremental project cost in the event of a breach,” meaning this extra cost must factor in project submissions, making the incumbent TO’s proposal cheaper by default, FERC said. (See Rehearing Denied on PJM Designated Entity Agreements.)

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said his group was unable to reach agreement on the scope of the issue charge despite six hourlong meetings with the TOs.

Poulos said the advocates question whether PJM is complying with schedule 6, section 1.5.8 of the OA, which requires entities assigned to construct and operate RTEP projects to comply with the DEA. PJM is not requiring incumbents to sign DEAs for all the situations identified in the OA, he said.

“We’re concerned that the language of the issue charge brought by the TOs could eliminate some of the projects” FERC intended to have covered by DEAs, such as immediate-need projects, he said.

The advocates’ issue charge includes a goal of ensuring “appropriate consumer protections” are followed by entities assigned to construct RTEP projects.

Steve Lieberman, of American Municipal Power, said PJM is “in a little bit of hot water” for not interpreting the OA as FERC directed.

“I’m not sure PJM would agree to that characterization,” responded Stu Bresler, the RTO’s senior vice president of market services.

“Our goal is making sure we’re treating everyone fair and equitably,” said Ken Seiler, PJM’s vice president of planning.

Foster Cronin said the TOs would like to review the DEA’s security requirements and development milestones to see if there are opportunities to streamline it based on PJM’s experience with Order 1000 over the last decade. “No developer should bear costs that don’t provide benefits,” she said.

Susan Bruce, representing the PJM Industrial Customer Coalition, said her group supports the broader look that CAPS proposed.

Alex Stern of Public Service Electric and Gas said the advocates’ issue charge doesn’t address the concern raised by FERC but raised a “new issue on how to apply more stringent requirements” on incumbents.

“It’s too simplistic to say PJM should just comply with the language” of the OA, he said. “We’re all confused.”

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PJM Markets and Reliability Committee Briefs: June 29, 2022

PJM Regroups After Opposition to Request for Service on FERC Filings

VALLEY FORGE, Pa. —Facing stakeholder opposition, PJM officials last week withdrew what they hoped would be a routine rule change requiring that the RTO be served with FERC filings affecting it.

PJM attorney Steve Pincus told the Markets and Reliability Committee on Wednesday that the RTO sought the change to ensure it can respond within FERC’s deadlines to any filings that affect it or its members.

The RTO’s current rules require only that transmission owners serve it with any Federal Power Act Section 203 filings. The rules do not cover waiver filings, settlements or reliability-must-run requests, Pincus said.

“This is a really bad idea,” American Municipal Power’s (AMP) Steve Lieberman responded, saying PJM’s proposed issue charge was overly broad and would create burdens for members. He recommended the RTO attempt a “more surgical approach.”

“AMP has a team of people … that monitor the dockets that get filed. I don’t know why PJM can’t as well,” Lieberman said. Members might inundate PJM with irrelevant filings out of concern that a failure to serve the RTO could lead to a FERC enforcement action, he argued.

Constellation Energy’s Jason Barker said his company would support PJM’s problem statement even though it disagrees with the RTO’s proposed solution. He recommended the RTO convene a meeting of FERC practitioners from member companies to devise a solution.

Susan Bruce, representing the PJM Industrial Customer Coalition, agreed. “The lawyers need to be in the room for this,” she said. “We all have that risk [of missing a filing], and we all look at the Federal Register.”

Adrien Ford, of Old Dominion Electric Cooperative, suggested that, rather than the MRC, the matter be considered by a special task force, the Risk Management Committee or the Governing Document Enhancement & Clarification Subcommittee, as others suggested.

Pincus assured members that PJM was not attempting to create a “compliance trap” for them but a “safety net” for itself. “We obviously monitor FERC filings, but the territory we have to cover is far greater than any other member,” he said. “To me it seems like a no-brainer. It seems logical that PJM would receive service.”

But Pincus acknowledged he was unaware of any instances in which the RTO was denied the ability to file comments because of missed deadlines.

“It’s a solution in search of a problem,” said Paul Sotkiewicz, representing J-POWER USA.

In the face of the opposition, General Counsel Chris O’Hara told members that the RTO would withdraw its request to approve the issue charge pending additional discussions.

But he said the rule change was needed, calling it “unconscionable that a generation owner can make a 203 filing [affecting PJM] and not serve us.”

Independent Market Monitor Joe Bowring said he shares the RTO’s concern about not being served in relevant dockets. “Whatever the solution is for PJM, we would like to apply to us as well,” he said.

Revised Operating Committee Charter Approved

Members unanimously endorsed a five-word change to the Operating Committee’s charter to reflect the RTO’s changing generation mix. The revised charter adds the words “reliability attributes and pertinent conditions” to paragraph 7, which refers to the committee’s oversight of operating practices and procedures relating to reliability.

Stakeholders Wary of ‘Narrow’ Change to Market Seller Offer Cap

Members and the Monitor expressed concern over PJM’s proposal to revise the market seller offer cap (MSOC) in time for the 2024/25 capacity auction in December.

PJM’s Pat Bruno said what he called a “narrow” change to the MSOC “seemed to have a broad consensus with stakeholders,” citing discussions by the Resource Adequacy Senior Task Force (RASTF).

Bruno said the change would ensure sellers are always able to represent the cost of their Capacity Performance risk when offering into the auction. The MSOC would be set at a level equal to the greater of the CP quantifiable risk (CPQR) or net avoidable-cost rate (ACR) inclusive of CPQR.

The change would address circumstances in which a unit with a positive CPQR value has that cost offset by an otherwise negative net ACR, which could result in a $0 offer cap.

Bruno gave an example of a wind farm with an ACR (excluding CPQR) of $80/MW-day, a CPQR of $20, and an energy and ancillary services offset (E&AS) of $150.

Under current rules, the generator would bid $0 ($80 + $20 – $150 = -$50). Under the proposed rules, the generator would offer at the CPQR: $20/MW-day.

“We think that’s consistent with how a market seller would set a competitive offer,” Bruno said.

PJM plans to seek endorsement of the change at the MRC’s meeting this month.

Jeff Whitehead of GT Power Group and Becky Robinson of Vistra said they support the change. But Bowring called the proposal “premature and inappropriate,” saying it would be a “significant redefinition” of the CPQR, undermining the capacity MSOC that protects against the exercise of market power.

“It’s not a problem that needs to be fixed,” Bowring said. “We haven’t had a $0 capacity clearing price, and we’re not likely to. But if we do, it would reflect competitive offers and a competitive outcome.”

Market sellers can include the cost of mitigating risk under the existing rules, Bowring said in an email after the meeting. He said although PJM has not defined CPQR in this proposal, the RTO has proposed a significant broadening of the definition of CPQR in RASTF meetings.

“If PJM wants to propose a change, PJM should make a proposal with all relevant elements clearly defined so that the full implications can be understood,” he said. “PJM has not explained why CPQR should uniquely not be part of gross ACR. PJM has stated, without explanation, that net revenues do not offset CPQR. That is not consistent with the definition of a competitive offer.”

AMP’s Lieberman also expressed concern, saying stakeholders should agree first on a definition of CPQR.

“Saying this is ‘narrow’ doesn’t make it so,” he said. “This is potentially setting a floor on the market seller offer cap.”

BRA Results Discussed

PJM’s Pete Langbein gave members a brief presentation on the results of last month’s 2023/24 Base Residual Auction.

Prices dropped by one-third to almost one-half in the auction, the first since the virtual elimination of the minimum offer price rule (MOPR) for subsidized resources and institution of a tougher offer cap. It was the RTO’s lowest prices except for 2012/13 and 2013/14. (See Low PJM Capacity Prices No Bargain, Coal & Gas Generators Say.)

Langbein said the Commonwealth Edison and Duke Energy zones didn’t bind, unlike in the prior BRA.

“We were concerned by the prices we saw,” commented Aaron Breidenbaugh, of Centrica Business Solutions. “It’s a disturbing trend if you’re on the supplier side.

PJM Senior Vice President of Market Services Stu Bresler said total capacity offered was about 11,000 MW less than in the previous auction.

PJM Sets Workshops on Extreme Weather NOPR

Ken Seiler, PJM’s vice president of planning, said the RTO will hold stakeholder workshops on July 21 and Aug. 12 on FERC’s June 16 Notice of Proposed Rulemaking on transmission planning performance requirements for extreme weather (RM22-10). The NOPR would direct NERC to modify reliability standard TPL-001-5.1 (Transmission system planning performance requirements).

FERC issued another NOPR on June 16 to solicit one-time reports from transmission providers detailing their “current or planned policies and processes for conducting extreme weather vulnerability assessments and mitigating identified extreme weather risks” (RM22-16, AD21-13). (See FERC Approves Extreme Weather Assessment NOPRs.)

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PJM Stakeholders Pump the Brakes on ‘Clean Energy Expertise’ for Board

VALLEY FORGE, Pa. — PJM members will take more time to consider a proposal to require that at least one of the nine members of the RTO’s Board of Managers has “expertise in the transition to zero-carbon energy resources.”

Dave Kolata, executive director of the Illinois Citizens Utility Board (CUB), proposed the change to section 7.2 of the Operating Agreement at the Members Committee meeting Wednesday, asking that it be brought to a vote at the committee’s July meeting. Albert Pollard, a former Virginia legislator who heads CUB’s CLEAR-RTO project, said the change would allow “strategic-level peer-to-peer leadership.”

After a lengthy discussion, the sponsors agreed to withdraw their request for an immediate vote; talks are expected to continue at the next MC meeting.

Kolata and Pollard noted that many of PJM’s utilities and most of its states have clean energy commitments and that the RTO’s interconnection queue is overwhelmingly solar, wind and storage.

“As the resource mix changes, PJM’s board will need an ever deeper understanding of the risks and opportunities of balancing the spectrum of clean energy resources (nuclear, wind, solar, [distributed generation and demand response]), as well as the need for dispatch of thermal resources,” CUB’s presentation said.

Cypress Creek Renewables and Jim Davis of Dominion Energy endorsed the proposal. Brian Kauffman of Enel X North America said the proposal is a “common sense next step.”

But John Horstmann of AES said he was concerned about changing the OA without going through the Consensus Based Issue Resolution (CBIR) process, with a problem statement and issue charge. “I have a concern about this setting a precedent,” he said. “There’s things many of us would like to change in the OA.”

“I think policy questions of this narrow scope are appropriate” for this format, Pollard responded.

Constellation Energy’s Jason Barker said his company supports the idea “in concept” and that the MC was the appropriate venue to consider such a change. But he said the proposal was vague as written. “It doesn’t say how the Nominating Committee should assess” the qualifications, he said.

Paul Sotkiewicz, representing J Power USA, said he shared Hortsmann’s concern over an immediate up or down vote and would oppose the proposal. “What about a board member for DR or combined cycle gas turbines or coal or nuclear units,” he said. “Where does it stop?”

Kolata responded that his goal is ensuring reliability. “The intent is not to provide preferences for any kind of resource,” he said.

Adrien Ford, of Old Dominion Electric Cooperative, said PJM should make sure any change doesn’t delay its current search for a replacement for Manager Sarah Rogers, whom Ford said is likely to resign after the July meeting.

Kolata said the change would require FERC approval and thus wouldn’t take effect immediately.

PJM’s Dave Anders asked whether the proposal could mean “open season on rewriting the qualifications” for board members.

“We view this as discrete. We don’t view this as open season,” Kolata responded. But he acknowledged “others may make suggestions.”

MC Chair Erik Heinle, who represents D.C.’s Office of the People’s Counsel, said the committee would have further discussion on the proposal this month.

Members Debate Change to CBIR Matrix Procedure

The committee also discussed a proposal by Horstmann to revise the RTO’s rules to allow PJM staff to “seed” the blank matrix used in the CBIR matrix with potential options before stakeholders begin work on it.

Horstmann said the change to Manual 34: PJM Stakeholder Process would improve efficiency as members consider options for each design component.

Ford said the change would be helpful. “It’s hard to start from a blank sheet,” she said. She said concerns that it would give the RTO an advantage in the subsequent debates were addressed by a change allowing other stakeholders to also submit options before the first meeting at which the matrix is developed.

But Independent Market Monitor Joe Bowring expressed concern. “I don’t think it’s a good idea. I think it does give PJM a first-mover advantage” even with the revised language, he said.

The committee will be asked to approve the change at its meeting this month.

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ERCOT Technical Advisory Committee Briefs: June 27, 2022

Members Continue to Work on Relationship with New Board

ERCOT stakeholders last week continued to review and tinker with their processes as they work to forge a stronger working relationship with the grid operator’s new Board of Directors.

The Technical Advisory Committee has been directed by the board to come up with a procedural framework to “better involve the board and help educate the board.” The committee’s leadership has also been tasked with creating opportunities to interact with the board’s newly created Reliability and Markets (R&M) Committee.

The new board group has not finalized its charter yet, but it will be responsible for overseeing ERCOT’s core functions: planning, markets, reliability and resilience, and technology-related functions like information technology and project delivery.

That would seem to place another layer between the board and TAC. The stakeholder committee, comprising 30 market participant representatives in seven market segments, is assisted by four subcommittees and makes recommendations to the board regarding ERCOT policies and procedures. TAC is also responsible for prioritizing projects through protocol revision requests, system change requests and guide revision processes.

However, TAC Chair Clif Lange said the group will still have a direct line of communication with the board.

“[We’ll] still report to the board any activities that we’ve undertaken, and any sort of decisions that we’ve rendered in terms of interacting with the R&M Committee,” he said during TAC’s monthly meeting June 27, basing his comments on discussions he and Vice Chair Bob Helton have had with Directors Bob Flexon and Peggy Heeg.

ERCOT Report Structure (ERCOT) Content.jpgTAC’s proposed reporting structure to the board’s Reliability and Markets Committee | ERCOT

The board now comprises eight independent directors, the Office of Public Utility Counsel’s interim public counsel and two nonvoting ex officio members. They replace a hybrid board of independent directors and market segment representatives that held office during the February 2021 winter storm and was criticized for not living in the state.

Flexon chairs the R&M Committee. He and Heeg will meet with Lange and Helton on July 11 to review TAC’s proposed procedural framework.

To prepare for that meeting, TAC members reviewed and discussed the results of their recent whiteboard session. (See “TAC Reviews Structure, Procedures,” ERCOT Briefs: Week of June 13, 2022.)

They agreed to put together a liaison delegation to advise and educate the R&M Committee on TAC decisions. The group would comprise TAC’s leadership and seated members as chosen by the seven market segments, with two representing the customer segment.

TAC wants to avoid a rigid formal structure with the delegation. Instead, members are recommending a conversational dialogue and inviting the board and R&M Committee to attend or listen to TAC meetings.

Addressing board concerns that ERCOT’s stakeholder-approval process takes too long, members have proposed a “shot clock” for revision requests by allowing a rule change’s sponsor to request a decisive vote be taken at TAC or the subcommittee level. A seconding motion would not be required, and motions to table would not be allowed to trump the vote.

June TAC Meeting (ERCOT) Alt FI.jpg

The June Technical Advisory Committee meeting | ERCOT

“The stakeholder process has been a very effective way to help ensure that we have as few unintended consequences as possible … and having all of these different viewpoints weigh in. We actually get a better product because of that,” Golden Spread Electric Cooperative’s Mike Wise said, expressing the concerns of several other members. “I don’t want to [bypass the stakeholder process]. I think we should be concerned about it. But to speed up the process, that’s another issue.”

TAC is also under pressure to accelerate directives from the Texas Public Utility Commission through the stakeholder process. Lange said the issue has been raised in several forums.

“Some commissioners have stated they have concerns with the time,” Lange said. “The board has explicitly stated that this was something they wanted stakeholders to address.”

The committee has responded by proposing that ERCOT continue to draft revision requests that result from commission orders and file them with the R&M Committee, which could endorse the request and advance it to the full board, refer it to TAC, or send it directly to a TAC subcommittee.

“I understand the commission’s frustration with the time to get some things done, but the problem is the devil’s really in the detail,” said Nick Fehrenbach, who represents the city of Dallas in the consumer segment. “It may be a great idea what they’re ordering us to do, but how do we change the protocols to where there’s not unintended consequences? Are we going to end up with a situation where we’re having to appeal approved protocols rather than the normal stakeholder process?

“The cure may be worse than the disease. We’re on very thin ice and a very slippery slope,” he said. “We need caution here.”

The committee is recommending the appeals process of its decisions remain the same, with appellants taking their claims directly to the board. It is also proposing appeals could also be made to the R&M Committee, with it providing an opinion to the board.

TAC is also proposing its members have five years of experience in the electric industry, with OPUC’s appointed representatives to a residential consumer seat being exempted. The members would be required to be certified by their employer that they are authorized to make segmental decisions, with alternate representatives expected to meet the same standards.

Bob Helton Clif Lange (ERCOT) Alt FI.jpgTAC leadership Bob Helton (left), Engie, and Clif Lange, STEC | ERCOT

“The board wants decision-makers, not note-takers,” Lange said.

Members pushed back against an earlier suggestion last year that TAC comprise officer-level representatives from their companies. (See “Members Push Back Against Revamped TAC Structure, Conservative Ops,” ERCOT Technical Advisory Committee Briefs July 28, 2021.)

TAC’s subcommittees are completing self-assessments to determine whether the groups are still necessary and whether additional efficiencies can be added as part of an annual review process. The subcommittee’s structural and procedural review meeting will be held in September.

SCT Project Moves Closer to Reality

TAC gave the Southern Cross Transmission (SCT) project — a merchant long-haul HVDC transmission line that would connect ERCOT with systems in the SERC Reliability region — its biggest boost yet by endorsing the final three ERCOT white papers addressing PUC directives to determine how to reliably interconnect the project. (See Texas Regulators Boost Southern Cross Project.)

The committee endorsed, without opposition:

  • Directive 1: creates a new market participant type, “Direct Current Tie Operator,” after consultation with stakeholders. SCT has told ERCOT it does not plan to join an appropriate market segment at this time, leading staff to conclude no bylaw revisions are needed at this time.
  • Directive 11: finds that costs identified by the PUC have been appropriately addressed by resolving each of the commission’s 14 directives and through a memorandum of understanding between ERCOT and SCT.
  • Directive 12: determines that costs associated with DC tie exports have been sufficiently addressed by the other directives’ resolution and that no further revision to any cost allocation mechanism is necessary.

Garland Power & Light, which owns the project’s western endpoint and holds a certificate of convenience and necessity granted by the PUC in 2017, abstained from all three votes. Calpine and Luminant joined GP&L in abstaining from Directive 11.

Assuming the ERCOT board approves the white papers during its August meeting, that will only leave Directive 2, which requires the grid operator to enter a coordination agreement with the balancing authority on the eastern end of the SCT project. The project’s developers have said that directive is not necessary to the PUC’s review and can be completed and closed at a later date.

The project would be capable of carrying 2 GW of power between Texas and SERC over a 400-mile, double-circuit 345-kV line. The project has FERC approval and a waiver from its jurisdiction.

The project has been under regulatory review for more than seven years. PUC Commissioner Jimmy Glotfelty has taken the agency’s lead on SCT and filed a memo in January that said it’s time that the commission and ERCOT “close a chapter” on the project and allow it to “stand or fail on its own economic merits.” He believes the review can be finished by the end of October (46304).

“It appears that both ERCOT and Southern Cross are on the same page and have been working well together over the years with the goal of completing the review [and] directives,” Glotfelty wrote.

He suggested that interconnection and transmission planning issues associated with DC lines be included in a PUC rulemaking that would add a consumer benefit test for new transmission projects.

Staff Apologize for Credit Error

Kenan Ögelman, ERCOT’s vice president of commercial operations, apologized to members for the math error that led to the board last month tabling a rule change endorsed by TAC that lowers counterparties’ unsecured credit limit from $50 million to $30 million. (See ERCOT Board of Directors Briefs: June 21, 2022.)

“We should have caught that error. It’s a relatively easy check. I should have caught it,” Ögelman said. He said staff are developing a process going forward “where we triple check those results and catch errors before they make it out publicly.”

Staff’s June presentation to the board included a slide designed to show the drop in outstanding unsecured collateral as the limit is ratcheted down. Instead of decreasing the unsecured collateral for participants above the $30 million limit, the error decreased it to zero.

Ögelman said TAC would see the revised calculations during its meeting this month, with the board again taking up the issue during its August meeting.

“We pride ourselves in providing accurate analysis to both TAC and the board, and I don’t think we met that standard with that presentation,” he said.

Controllable Load Resource Changes

TAC took up only three changes during the meeting, endorsing a nodal protocol revision request (NPRR) and an accompanying other binding document revision request (OBDRR) on its consent agenda.

  • NPRR1131: changes controllable load resource’s participation in non-spinning reserve from offline to online non-spin. The change sets a bid floor of $75/MWh, equivalent to generation resources’ offer floor when providing online non-spin. If a qualified scheduling entity also assigns responsive reserve (RRS) and/or regulation up service to a controllable load resource that has been assigned non-spin, the sum of RRS, reg-up and non-spin ancillary service resource responsibilities will be assigned a $75/MWh offer floor.
  • OBDRR040: removes the controllable load resource providing non-spin schedules and regulation service schedules from the capacity calculations to align with NPRR1131.

The committee tabled NPRR1127, which clarifies the ERCOT entities required to have hotline and 24/7 communications with the grid operator and requires them to answer each hotline call.