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November 5, 2024

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PJM MIC Briefs: April. 12, 2023

Stakeholders Endorse Manual Revisions for Real-time Values

VALLEY FORGE, Pa. — The PJM Market Implementation Committee overwhelmingly voted to endorse manual revisions to put limits on when generators can submit real-time values.

The revisions would only permit real-time values to be used for physical unit limitations or circumstances outside the generation owner’s control. Documentation of those factors would be required to be submitted to PJM and the Independent Market Monitor within three days. If real-time values are improperly submitted, PJM’s Lauren Strella Wahba said the RTO would have the ability to reject them after the fact and the option to refer the seller to FERC.

Real-time values are meant to be a temporary way for generators to provide PJM its operating capabilities when it cannot satisfy its unit-specific parameter limits or approved parameter-limited exceptions. The RTO has found that the values have been used to override parameter limits or exceptions in some instances, Wahba told the MIC, while in other circumstances dispatchers would only become aware of a deviation from operating parameters when they called upon a unit.

FERC rejected a previous proposal to codify real-time values in the tariff, stating in a May 2021 order that submissions would not have been based on actual physical or operational constraints. The commission also stated that PJM’s status quo governing documents could contain market power issues (EL21-78).

Several stakeholders questioned why PJM sought endorsement of new manual language rather than embarking directly on making tariff revisions. PJM’s Chen Lu said real-time values currently exist in the manuals without a requirement for physical constraints and by making manual revisions now, the changes can be implemented while stakeholders work toward a FERC filing on tariff revisions.

Quick Fix Proposed to Address Falling Synch Reserve Deployment Response Rate

PJM proposed initiating a quick-fix process to address synchronized reserve deployment times exceeding PJM’s 10-minute internal standard since it implemented an overhaul of the reserve market on Oct. 1, 2022. Nonperformance rates have also increased to around 49% during the eight reserve deployments since the implementation, excluding those during the December 2022 winter storm.

The quick-fix process allows for a problem statement and issue charge to be endorsed concurrently with a proposed solution. Under the proposed manual revisions, PJM would be able to extend the second step of the operating reserve demand curve (ORDC) process by taking nonperforming reserve resources into account, allow the addition of on- and off-peak periods, and require that the extended values be posted as they’re changed.

PJM’s Phil D’Antonio said the RTO believes that the issue lies in market participant training, rather than in the pricing of reserves, and ongoing outreach to generators will yield progress. Glen Boyle, also of PJM, said that because penalties are based on synchronized reserve revenues earned and clearing prices are low, penalties are also low at this time.

Monitor Joe Bowring said he believes the issue is not appropriate for a quick-fix solution, as there is no demonstrated reliability issue that would be addressed by the proposed change.

He noted that PJM’s proposal would nearly quintuple the second step of the ORDC, from 190 MW to 890 MW, without any quantitative support for that significant a change, which he argued would trigger shortage prices more often and increase the price of synchronized reserves. Bowring also pointed out that the Oct. 1, 2022, change in the reserve market design increased the supply of synchronized reserves and included a must-offer requirement. He argued reserve prices since Oct. 1 have not been too low but have appropriately reflected the balance of supply and demand.

Under the applicable NERC standards, only one spinning event has exceeded the limit, and that is under investigation, Bowring said. He agreed with PJM that individual unit response times have been a problem and that both the Monitor and PJM are contacting individual unit owners to investigate the reasons for the poor performance. Bowring also stated that PJM’s rules for not paying resource owners for nonperformance were too weak and contributed to the performance issues.

Stakeholders Fine-tune Design Components on Local Considerations for Net CONE

Stakeholders continued the identification of design components to include in the drafting of proposals on whether and how to include regional factors impacting the net cost of new entry (CONE), such as environmental regulations or taxes. The MIC also discussed interests and design components during the February and March meetings, with the next phase being the creation of packages. (See “Discussion on Local Considerations for Net CONE,” PJM MIC Briefs: March 8, 2023.)

James Wilson, a consultant for five state consumer advocates, recommended two design components: a transition mechanism when net CONE is updated, potentially capping any increase at 20% during years between Quadrennial Reviews; and consideration of changes to the variable resource requirement (VRR) capacity demand curve shape — the latter of which he acknowledged had previously been ruled out of scope, which he suggested could ultimately result in any proposal to just change net CONE rules being rejected by FERC.

Stakeholders discussed whether CONE values and the reference resource should be reviewed whenever an impact, particularly signed legislation, is identified, including in between Quadrennial Reviews.

The discussion also looked at whether the creation of a new CONE area should result in the original region parameters being recalculated to account for the different footprint, particularly if the reference resource was based in the excised area.

Discussion on Co-located Load Packages

Several proposals to define how configurations in which load is directly connected to generators fit into PJM’s rules continued to be discussed by stakeholders.

Much of the discussion was centered on whether generators co-located with load that does not have a direct interconnection to the transmission grid should be required to relinquish a portion of their capacity interconnection rights (CIRs) equal to the energy consumed by the load, as they currently are, or if they should be permitted to retain that capacity, as well as whether interconnection and ancillary services charges should be assessed. (See “Proposals on Rules for Generation with Co-located Load Presented,” PJM MIC Briefs: March 8, 2023.)

Exelon’s Sharon Midgley said the company’s proposal would allow generators to retain their CIRs, but the facility would be classified as a load-serving entity for the co-located load and all applicable LSE charges and credits would be applied to it. She noted the package currently only focuses on capacity resources, but it will be expanded in the future to consider energy-only generation, given the interest expressed by other PJM members as well.

“Our primary interest is having more clarity in PJM’s rules,” she said.

A proposal from the Advanced Energy Management Alliance would codify all status quo rules and practices, with the addition of creating penalties for the host generator if the co-located load is not curtailed when the generator is dispatched.

Two proposals from the Monitor and a joint package from Constellation Energy and Brookfield Renewable remain largely unchanged since the MIC showed less than 20% support in a November poll. Following the poll, Bowring — whose package largely codifies existing practices and adds administrative requirements and charges — suggested discontinuing the discussion, but stakeholders felt that clarified rules are needed.

The Constellation-Brookfield proposal would allow generators to retain their full CIRs without making either the generation or the load subject to ancillary service charges, under the argument that the load does not benefit from grid services. Former Constellation Director of Wholesale Market Development Jason Barker stated that the arrangement the company envisioned under the rules would be a nuclear facility supplying power for highly interruptible load, such as hydrogen electrolyzers. (See “Limited Support for Co-located Load Proposals,” PJM MIC Briefs: Dec. 7, 2022.)

Bowring argued that PJM should be required to assess the impact of diverting a significant amount of low-cost energy off the grid to meet new load added to the grid behind the generators. He also said that emissions would increase as a result because nuclear energy would be dedicated to the new loads while existing load would be met by the emitting resources at the top of the supply stack. A related result would be an increase in energy market prices that the Monitor had previously estimated as exceeding a billion dollars, Bowring said.

“Nuclear plants were never built to provide energy for a few hours per year. The promise to provide energy from the resources for a few peak hours a year is not consistent with the obligation of capacity resources.”

First Read on Smooth Supply Curve Quick Fix

PJM presented a proposal to initiate a quick fix process to clarify that the informational smoothed supply curves PJM publishes after Base Residual Auctions will not be created for Incremental Auctions (IAs). PJM’s Skyler Marzewski told the committee that PJM cannot create smoothed supply curves for IAs because of the lack of demand curves in those auctions and the risk that they could be used to expose market sensitive data.

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FERC Commissioners Discuss Western Markets ‘Dating Process’

INCLINE VILLAGE, Nev. — FERC Commissioners Allison Clements and Mark Christie offered their thoughts on Western market formation to a large gathering of state regulators and stakeholders at last week’s meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB).

Christie urged caution on joining an RTO, and Clements said “bigger is better” when it comes to organized markets. But both said the West will have to make its own decisions on market options.

Those options now include the Western Power Pool’s Western Resource Adequacy Program (WRAP), SPP’s planned RTO West and its Markets+ day-ahead offering, and CAISO’s extended day-ahead market for its real-time Western Energy Imbalance Market (WEIM). A legislative effort is underway that could eventually allow CAISO to become a multistate RTO. (See related story, Western Day-Ahead Markets Debated at CREPC-WIRAB.)

Clements compared the situation to a “dating process,” a metaphor she said she had borrowed from others at the meeting. And like other speakers, she noted the difference between pre-pandemic circumstances in the West and the current push toward Western regionalization.

“You really have made great progress in the last two and a half years,” she said. “Before COVID, everyone was just kind of looking around and checking each other out, and, wow, we come back from COVID and things have gotten serious.”

“I want to be clear that FERC’s job is not to be the parents to choose for you,” she said. “We’re not going to choose between the banker and the lawyer. We’re not going to choose between the banjo player and the marketer. Right? You are going to make a decision on your own.”

Clements pointed to the $3.4 billion in cumulative benefits obtained by participants in CAISO’s WEIM as evidence of the value of market development. The market allows participants to trade inexpensive renewable resources and to optimize dispatch across portions of 11 Western states and one Canadian province.

“The benefits of the EIM have really kind of shut the door on the question of whether or not increased market optimization works,” Clements said. “It feels like that conversation is done. Markets designed well save customers money. That’s the bottom line.”

She also praised the progress on WRAP, a first-of-its kind effort to coordinate resource adequacy across much of the Western Interconnection. FERC approved the program’s tariff in February. (See FERC Approves Western Resource Adequacy Program.)

Decisions about whether to join WRAP, the proposed day-ahead markets or to engage in interregional transmission planning could have long-term consequences and must be considered carefully, Clements said.

“The idea that you would choose one partner for resource adequacy and one partner for the day-ahead market and another partner maybe down the line for transmission system planning creates a lot of inefficiency and leaves a lot of savings on the table,” she said.

“You know, to my mind, it’s always the case that bigger is better,” she said. “The broader the interconnected nature of the system, the more ability you have to ensure reliability in extreme weather because the extreme weather won’t cover the whole system.”

A state-led market study in 2021 estimated that a West-wide RTO would save $833 million per year in production costs by 2030, Clements noted.

RTOs have seams agreements with each other and the ability to dispatch across those seams, and they can develop transmission while avoiding unnecessary costs and redundancies, she said.  

“There are a lot of benefits that come with the full-scale development of an RTO, and there are issues to deal with as well,” she said. “I won’t pretend it’s just a rosy walk in the park.”

Seams agreements between RTOs can be especially difficult, requiring “intensive coordination,” she said.  

“So, as regulators, you want to be at the table very early to think about how that coordination is going to get set up,” Clements said. “It’s not the kind of thing you want to leave and punt down the road and just see how it goes for a while.”

“Those are the questions I’m asking myself, as I see you all asking yourselves and engaging in these conversations around ‘what and where do we go from here?’” Clements said. “I will say I’m really impressed by where you are. And I look forward to continuing to watch you all and support you all trying to figure out your next steps.”

‘Lowest Rates in America’ 

In a separate session, FERC Commissioner Mark Christie weighed in on the question of whether Western states should join an RTO.

“You in the West will decide for yourselves what you want to do,” said Christie, who noted the range of options between doing nothing and joining “a full-scale RTO with all the bells and whistles.”

The West could come up with a unique construct that’s not being used elsewhere in the U.S., Christie said. Market choices, including real-time and potentially day-ahead market choices, could be meshed with a resource adequacy program such as WRAP, which Christie lauded as being creative, simple and voluntary.

“What could be more simple than having load-serving entities mutually pledge to reach certain resource requirements and to make available their excess resources when another participant needs it?” he said. “And to help each other in a reasonable way and on a voluntary basis.”

Another aspect of the RTO decision is what a state utility commission would relinquish in choosing to go with an RTO.

“If you want to give up your transmission planning, you’ve got to ask yourself, what am I giving up?” said Christie, who served 17 years on the Virginia State Corporation Commission before joining FERC in 2021. “Well, you’re giving up the ability … to control how assets are going to be deployed and how much money is going to be spent and how the costs are going to be allocated.”

“Maybe you want to do that,” he added. “Maybe that works for you. My point is, don’t accept unskeptically the benefits of any construct.”

Putting customers first should be the driving interest for state and federal regulators, Christie said. He pointed to three Western states — Utah, Idaho and Wyoming — that had the lowest electric rates in the nation as of the morning of his presentation.

“If the promise of an RTO is [that] it’s going to save us all this money, and we’re sitting here in these three states and we have the lowest rates in America, the question would be, ‘Seriously? … It’s going to save us money? How?’”

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Treasury Releases Revised List of EVs Eligible for IRA Tax Credits

The Treasury Department has released an updated list of electric vehicles that qualify for all or part of the Inflation Reduction Act’s tax credits, providing mixed news for U.S. and foreign automakers and prospective buyers.

Under the guidelines for meeting the IRA’s domestic content provisions, released last month, U.S. automakers fared well, with most of their models on the revised list, but some qualifying for only half the credit. The guidelines for 2023 models require that 40% of critical minerals in an EV’s battery and 50% of other battery components be sourced from the U.S. or from a country with which the U.S. has a free trade agreement. (See Fewer EVs May Get IRA Tax Credit Under New Domestic Content Rules.)

To qualify for the full $7,500, EVs must also meet the IRA’s limits on manufacturer’s suggested retail price (MSRP), and final assembly of the car must be in North America. The MSRP limits are $55,000 for a passenger EV and $80,000 for SUVs and light-duty pickup trucks.

A previous list, issued at the end of 2022 did not factor in the domestic content requirements, allowing more than 20 EVs and plug-in hybrid electric vehicles (PHEVs) to qualify for tax credits.  

All Tesla’s Model 3 and Model Y vehicles qualified for the full $7,500 tax credit on that list, but now the standard, rear-wheel drive Model 3 — with a range of 272 miles and a $42,000 MSRP — only qualifies for $3,750, signaling that its battery does not meet the domestic content requirements for the full credit. The topline Performance Model 3 is still eligible for the full credit.

Similarly, Ford’s F-150 Lightning electric pickup qualifies for $7,500, but the automaker’s popular Mustang Mach-e SUV is only eligible for $3,750.

All European and Asian models previously on the list were cut, including the Nissan Leaf, Volkswagen’s ID.4 and BMW’s 330e plug-in hybrid vehicle.

GM has the most models qualifying for the full $7,500 tax credit, with its Cadillac Lyriq and Chevy Bolt, Blazer, Equinox and Silverado still on the list, the result of its investments in domestic supply chains, the company said in a statement released Monday.

“Over the next 10 years GM will offer a broad selection of qualifying vehicles across numerous segments and price points, which will bolster our EV transformation as well as the U.S. production and adoption that these incentives were designed to support,” the company said.

Ford, which holds the No. 2 spot in the U.S. EV market — after industry leader Tesla — released its own list of models qualifying for tax credits earlier this month. Like GM, the company is promoting its plans for continued supply chain growth and delivering more EV models in the coming years.

Challenging but Achievable

Sen. Joe Manchin (D-W. Va.) wrote the domestic content provisions into the IRA to support the buildout of a home-grown EV supply chain and to cut U.S. automakers’ dependence on China for the critical minerals and other components in EV batteries. The law required the Treasury Department to issue guidelines for the EV tax credit by the end of 2022, but the agency only released partial guidelines, delaying rules on the domestic content provisions until March. (See Treasury Delays Key Rules for IRA’s EV Tax Credits.)

Manchin made an unsuccessful attempt to force implementation of the domestic content provisions with a bill he introduced in January, and he was not satisfied with the domestic content guidelines Treasury issued March 31. But he has not taken any further action. (See Transparent, Traceable Supply Chains Key to EV Domestic Content Rules.)

But as gas prices again edge up, the Biden administration is framing the slimmed-down list as still providing U.S. consumers with a good range of choices for purchasing an EV with the full or partial tax credit, while also supporting ongoing growth of domestic supply chains. Getting both halves of the credit may be challenging, but it is achievable, according to an administration official speaking on background.

The Treasury guidelines are clear, workable and having the intended effect, the official said. According to a preliminary administration analysis, close to 65% of EV sales in the first three months of 2023 met the IRA’s requirements on vehicle price and final assembly, qualifying them for at least the $3,750 credit, the official said.

Further, 90% of those vehicles also met the IRA’s domestic content requirements, the official said.

Other administration officials have been keen to point to the $45 billion in private sector investment in EV and battery supply chains that has been announced since President Joe Biden signed the IRA in August, For example, Korean automaker Hyundai is building a factory in Georgia expected to go into production in 2025, with an estimated production of 300,000 EVs a year.

Similarly, Japan’s Nissan announced a $500 million investment to transform a Mississippi plant for EV production.

EV Sales Continue to Grow

The big question is whether and to what extent the reduction in EV models eligible for the IRA tax credits might slow EV adoption and put a brake on Biden’s goal of EVs becoming 50% of all new passenger vehicle sold in the U.S. by 2030.

Phil Jones, CEO of the Alliance for Transportation Electrification, is expecting a “hiccup” in the EV market as automakers adjust to the domestic content guidelines and focus on domestic supply chains. “There will be some slowdowns for certain vehicles and certain manufacturers, obviously, because consumers are price-sensitive,” Jones said in a recent interview with NetZero Insider. 

“But I don’t think it’s going to be significant,” Jones said. “There’s so much pent-up demand for these vehicles out there, and the major issues, in my view … it’s chips; it’s semiconductors; it’s components of an automobile other than the battery.”

U.S. EV sales seem to support that view. EV registrations in the U.S. in 2022 topped more than 750,000, a 57% jump from 2021, according to data from Experian cited in insideevs. Tesla accounted for 64% of sales, followed by Ford and Chevy. EVs accounted for 7.1% of all new vehicle sales in January, according to Experian, with Tesla once again in the lead with sales of more than 46,000.

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PJM Seeks Settlement over Elliott Nonperformance Penalties

PJM asked FERC on Friday to initiate settlement judge procedures in its dispute with generators over nonperformance penalties for the December 2022 winter storm.

The RTO asked the commission to establish a “global settlement procedure” for the eight complaints filed by generators (EL23-53 through EL23-60) and “for any similar complaints that may be filed.”

PJM officials told stakeholders last week they had assessed more than $1.8 billion in performance penalties on generators that underperformed during the Christmas weekend storm dubbed Winter Storm Elliott. (See related story, PJM: Elliott Nonperformance Penalties Total More Than $1.8B.)

The RTO told FERC it properly implemented its emergency procedures and that the nonperformance charges follow its tariff and are just and reasonable.

“At the same time, however, PJM recognizes the potential benefits of a prompt resolution, to the extent possible, of the disputed assessment of these charges,” it said. “These disputes, considering the complaint, rehearing and appeal processes, could hang over the PJM market for years, affecting market participants’ conduct in ways that may be irreparable and not always desirable. The capacity market also is designed in large measure to signal the need for new capacity resource investment, and the expectations of the financial and investment community accordingly are an important backdrop to the operation of this market. Timely, consensual resolution of these disputes thus could, potentially, help support the long-term health of the resource adequacy construct in the PJM region.”

PJM noted that several of the complainants have also requested settlement procedures or alternative dispute resolution.

“A global proceeding would best provide, to the extent possible, a measure of principled consistency in any settlement outcomes of these multiple complaints,” it added. “To that end, PJM seeks a single overarching settlement process, led and coordinated by the commission’s administrative law judge(s), for all of these complaints.”

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SPP MOPC Briefs: April 10-11, 2023

Staff, Stakeholders See Resource Adequacy as Key Issue

SPP staff and stakeholders spent much of last week’s virtual Markets and Operations Policy Committee meeting discussing resource adequacy and the various initiatives the grid operator has rolled out to address the issue.

“Resource adequacy is a critical area for us,” SPP’s Casey Cathey said. “The regional fuel mix is consistently changing. The state of the future grid is extremely important. Loads are changing; pretty much everything’s changing that we know of in our industry, even HR.”

As director of grid asset utilization, Cathey runs a department responsible for planning a reliable and efficient bulk electric transmission system, with an eye on economically preparing SPP for the future grid. His staff facilitates generation interconnection and transmission service functions and operates resource adequacy across both the Western and Eastern interconnections.

Cathey’s department is not alone.

“Everything we’re doing related to resource adequacy is critical, which is why we have a number of different groups that are focusing on various aspects of resource adequacy,” COO Lanny Nickell said.

SPP’s Supply Adequacy Working Group (SAWG) handles immediate resource adequacy issues and the technical aspects of various studies. The Improved Resource Availability Task Force was formed after the February 2021 winter storm and is working on fuel assurance and resource planning and availability recommendations identified in the RTO’s review of the storm. (See SPP Board of Directors/Members Committee Briefs: July 26-27.)

The grid operator has also created the Resource and Energy Adequacy Leadership (REAL) Team under state regulators’ Regional State Committee. Chaired by Texas Public Utility Commissioner Will McAdams, the REAL Team has been tasked with the more strategic aspects of resource adequacy by assessing SPP’s current construct and anticipated challenges from resource mix changes, extreme weather effects, increased demand and evolving consumer behaviors.

Staff and stakeholders will be busy in the near term. SPP’s annual tasks include winter and summer season deliverability studies and, this year, a loss-of-load expectation study to help determine the planning reserve margin for summer. The study will address weather-forecast uncertainty by using 40 historical weather years dating back to 1980. It will also determine a winter resource requirement and PRM and an unforced capacity PRM.

Staff and the REAL Team are both looking at whether an expected unserved energy (EUE) standard needs to be developed. Then there’s the SAWG and Operating Reliability Working Group’s joint review of the planned and maintenance outage policy and a slew of other work.

Cathey noted SPP and the industry have traditionally followed the one-day-in-10-years LOLE standard, a legacy from a time when generation fleets primarily comprised thermal resources. He said the industry may be leaning toward a combined standard that combines LOLE with EUE and loss-of-load-hours.

“One thing that is missing in our LOLE study is forecasting climate change. There’s not a forecast or prediction or aspect to our LOLE study today, so that’s another area that we’d like to continue to explore,” Cathey said. “We have an urgency for resource adequacy, not the least of which is that resource adequacy is now one of our top corporate risks and also industry-wide. Everyone’s trying to figure out the potential policy changes.”

Nickell assured stakeholders that they will continue to have a voice in the resource adequacy work.

“I just want to deal with the impression that this is all happening behind the scenes and behind closed doors, and it’s just staff collaborating on this stuff,” he said. “That’s absolutely not true. We have been working with stakeholders along the way. … They will all have an opportunity to provide input.”

Responding to FERC’s Rejection

One of the REAL Team’s first actions has been to direct the SAWG to modify and “harmonize” two revision requests so they focus on equitable and appropriate treatment of resources in response to FERC’s recent rejection of SPP’s capacity accreditation methodology for wind and solar resources on procedural grounds.

The commission agreed in March with renewable energy developers’ arguments that it had erred with last year’s order accepting the RTO’s proposed tariff revisions to accredit wind and solar resources based on historical performance using an effective load-carrying capacity (ELCC) methodology (ER22-379). (See FERC Grants Rehearing of SPP Capacity Accreditation Proposal.)

“This was a surprise to SPP and SPP staff and members,” Cathey said, noting the ELCC was expected to be in place this summer.

The SAWG is working to separate the ELCC and performance-based accreditation into two separate RRs, with the ELCC request expected to reflect FERC guidance. The RRs have been targeted for final presentation to the board and RSC in October.

Cathey said the accreditation methodology changes for all resources should be filed together as a policy change and their implementation’s timing be consistent across all resource types. He said seasonal net peak demand should be defined in the tariff and modifications considered for ELCC allocation methodology.

FERC said in its filing that it expects staff to provide “sufficient detail in its tariff, consistent with the directives of this order, to allow the commission to act in a subsequent order without the need for additional record development.”

“We all know, especially since we passed the performance-based accreditation policy last summer, that we were working to become more equitable in our accreditation process across all fuel types,” Cathey said. “However, from a legal perspective, that was not in front of [FERC] in that docket, and so it’s certainly a lessons-learned for us.”

2024 ITP Scope Revisions OK’d

The MOPC approved a pair of Economic Studies Working Group recommendations to the 2024 Integrated Transmission Planning 10-Year Assessment’s scope that are more reflective of current grid conditions.

The first revision would include a winter weather analysis because of more frequent extreme conditions, such as the February 2021 and December 2022 storms. The MOPC and the Strategic Planning Committee both directed the ESWG to study extreme winter weather conditions.

The second increases the amount of assumed amounts of renewable capacity in the scope’s two futures, based on the amount of renewable interconnection requests in the queue. Both measures passed overwhelmingly, 80% and 93%, respectively.

Increased renewable energy assumptions (SPP) Content.jpgIncreased renewable energy assumptions in the 2024 ITP’s scope | SPP

 

The ESWG suggests building two distinct winter weather power-flow scenarios: one focused on operational conditions to better understand reliability issues that took place in December, and a generic model based on a set of historical winter regional stressors such as fuel availability, wind output, and transmission and generation outages.

“At the very least for December 2022 … we are going to have some outages baked in to be able to study what exactly happened in Winter Storm Elliot,” said ESWG Chair Derek Brown, of Evergy.

Brown said it could take as much as $600,000 for additional staff time to keep the 2024 ITP on schedule.

The ESWG also proposes to increase its assumptions for renewables added to the grid in the futures’ year 5 and year 10 scenarios. The studies will assume year 10 highs of 19.1 GW for solar in the reference case and 24.1 GW in the emerging technologies case; 54.9 GW and 59.1 GW for wind; and 5.7 GW and 9.6 GW for battery storage.

GI Backlog Tracking for 2025 Completion

SPP remains on track to clear its generator interconnection queue’s backlog by 2025 despite 599 active requests, Cathey said. The queue’s six cluster studies are all green thanks to the grid operator’s two-year-old, three-phase approach to processing generator interconnection requests in place since 2022 and its backlog mitigation plan.

The mitigation efforts began in 2022 with 898 GI requests for 171.5 GW of generation in the queue. As of Sunday, the requests are down to 593 for 118.1 GW of capacity.

“It’s mostly around restudies and ensuring that we’re not causing too much churn to the GI customers and making sure that we get through the backlog as each cluster of DISIS [definitive interconnection system impact studies] is captured,” Cathey said. “So far, it still appears to be effective.”

Even with the backlog, SPP has added almost 28 GW of capacity to the system since 2016 and executed 144 interconnection agreements. Complicating matters going forward is that a little over 41% of the queue’s requests (48.3 GW) are for solar. Wind (29.9 GW) and energy storage (21.8 GW) — all of it four-hour, lithium-ion batteries, Cathey said — account for much of the rest. Developers have 21 requests for 3.5 GW of thermal capacity in the queue.

“We’re trying to thread that needle in terms of where our fuel mix is going five, 10, 15 years in the future, coupled with our load profiles,” Cathey said. “We definitely need to work on those particular policies because even if they’re all approved, as massive as 119 GW are, it’s more than twice our peak load.”

Tx Service RR Remanded

The MOPC remanded a revision request back to the Transmission Working Group after Dogwood Energy’s Rob Janssen pulled it off the consent agenda for further discussion and vetting in the stakeholder process.

Dogwood abstained from the Regional Tariff Working Group’s vote on RR534, which is intended to clarify and correct tariff language that limits transmission service to the amount of interconnection service.

Janssen said 95% of RR534 is “perfectly fine,” but the inclusion of point-to-point service along with network service runs counter to FERC Order 888’s language that doesn’t allow limitations on parties purchasing transmission service in the absence of anticompetitive practices.

“While you do try to include both point-to-point transmission service and network service in this set of restrictions, my concern is that you actually increase the probability of gaming, because now you’re allowing a third party to buy point-to-point transmission service and effectively block a load-serving entity that might have a deal with a generator for being able to get transmission service for any deal that they put in place,” Janssen said. “That could result in a very significant problem for some parties as SPP’s grid gets more resource-constrained and parties are fighting for access to generating resources.”

The consent agenda, approved unanimously, included seven other RRs that are effective immediately and one, RR530, that requires the Board of Directors’ approval:

  • RR530: identifies consistent criteria for when it is acceptable to implement a transmission reconfiguration and outlines responsibilities for the reliability coordinator and transmission operator.
  • RR532: removes section 4.5.9.21 (Real-Time Joint Operating Agreement Amount) and adds the variable RtJoaHrlyAmt in the definitions section of 4.5.12 (Revenue Neutrality Uplift Distribution Amount) among other cleanup to revenue neutrality uplift language.
  • RR533: adds language to clarify how resources will be settled with operational tools downstream from the real-time balancing market and that cleared quantities are updated when a price correction is needed for the day-ahead market.
  • RR535: corrects the protocols for uncertainty products by clarifying summation for reserve zone additions, settlement variables and if/else replacements.
  • RR538: ensures the protocols and tariff clearly describe when emergency limits will be used and how market participants can know if the emergency limits are used.
  • RR540: ensures RR382 (Multi-day Minimum Run Time) is accurately implemented by revising governing language for day-ahead and reliability unit commitment make-whole payments.
  • RR541: clarifies that the credit customer, not the market participant, is the highest level for exposure tracking.
  • RR544: modifies the Transmission Owner Selection Process Task Force’s changes to the competitive transmission selection process to include cost caps and guarantees in competitive upgrades.
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PJM PC/TEAC Briefs: April 11, 2023

CAPS Pushes for More Transmission Upgrade Data

VALLEY FORGE, Pa. — State advocates would like to see more details when supplemental transmission projects are proposed to the Transmission Expansion Advisory Committee (TEAC), Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said in a presentation to the committee on Tuesday.

The data currently provided by transmission owners tends to be inconsistent and lacking enough information to allow for proposal of alternatives, Poulos said.

“I’d like to get that information in a way that’s most efficient” for transmission owners and advocates, he said.

In particular, he pushed for a breakdown of project costs beyond an overall estimate; increased clarity about whether a project falls under state jurisdiction; and the inclusion of contact information for a TO’s relevant planning staff.

He also argued that the long period of time between the presentation of a need and a proposed solution suggests the timeframe for submitting alternatives could be lengthened. Currently, comments and alternatives must be submitted within 10 days, which Poulos said is inadequate if there are follow-up questions about a proposed project or for a prospective developer to evaluate a need and create a solution.

Tom Schmidt, principal planning engineer at Buckeye Power, said alternative proposals are welcome, especially when expensive repairs are needed, but they’re not always feasible for a variety of reasons, such as when equipment fails. He noted that TOs provide a spectrum of information on projects, often providing a large amount of documentation.

“Some have plenty of details to support their spending and others it seems a little bit lighter,” he said.

No Plan to Extend Accreditation Uprate Study Application Deadline

PJM’s Pauline Foley told the committee that the RTO does not plan to lengthen the application period for generators to seek temporarily higher accreditation while PJM transitions to the modified effective load-carrying capability (ELCC) methodology FERC approved last week. The studies allow an existing or planned generator that is re-entering the transmission queue in order to increase its capacity interconnection rights to undergo annual transitory studies to determine if it can temporarily increase its capacity rating by utilizing existing transmission headroom. (See FERC Approves Revisions to PJM’s ELCC Accreditation Model.)

In its order accepting the ELCC changes, the commission recommended that PJM consider leaving applications open longer should it seek a delay to the 2025/26 Base Residual Auction, currently scheduled for June 2023. PJM filed with FERC to make that delay on April 11. (See PJM Seeks to Delay Capacity Auctions Through 2028 Delivery Year.)

Protests against the ELCC filing argued that PJM’s original intention of setting applications to close on March 3 violated noticing requirements under the Federal Power Act and left insufficient time for generators to make complicated decisions about unit accreditation. In a dissent, Commissioner Allison Clements agreed with those concerns and said the majority’s decision to allow applications through April 10 was also insufficient.

Foley told the PC that extending the application period would not conform to stakeholders’ intentions when they endorsed the filing’s language.

Reliability Analysis Update

Dominion (NYSE:D) proposed a $7.7 million upgrade to address a 300-MW load drop violation in the 2027 Regional Transmission Expansion Plan around the area of Dulles International Airport in Virginia.

The upgrade would cut the existing Brambleton-Poland Road 230-kV line and create a new 0.59-mile-long, double circuit 230-kV line between the Brambleton and Evergreen Mills substations. Both original substations would remain connected.

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Western Day-Ahead Markets Debated at CREPC-WIRAB

INCLINE VILLAGE, Nev. — Speakers debated whether the West would benefit more from the one day-ahead market run by CAISO or with another run by SPP at last week’s meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body.

The spring CREPC-WIRAB meeting took place as CAISO is drafting tariff language to add an extended day-ahead market (EDAM) to its real-time Western Energy Imbalance Market (WEIM) and SPP is developing its Markets+ program with a day-ahead market as its centerpiece. (See SPP: 31 Entities Join in Markets+ Development.)

Advocates for a CAISO-led day-ahead market and others backing SPP spoke on two panels Wednesday at the Hyatt Regency Lake Tahoe Resort, where Western regulators and stakeholders filled a large meeting room to capacity.

Ric OConnell 2023-04-12 (RTO Insider LLC) FI.jpgRic O’Connell, GridLab | © RTO Insider LLC

“Markets give us affordable and reliable energy through breadth, depth and transparency,” said Ric O’Connell, executive director of GridLab, a nonprofit technical advisory firm in Berkeley, California. “We need a market that’s broad enough to capture resource and load diversity, and we need a market that’s deep and liquid so that there’s a lot of energy traded in that market, either in real-time or in the day-ahead.”

A Western day-ahead market without California would lack those attributes, O’Connell said.

“California has close to half the load of the West,” he said. “California has massive transmission connections both to the Pacific Northwest and to the Desert Southwest, and it’s been trading with [entities in those regions] for decades … so I would posit that a Western market that does not include California is going to lack the breadth and depth that we need to unlock the benefits of affordable and reliable energy in the West.”

The Western Energy Imbalance Market encompasses 80% of load in the Western Interconnection and has achieved $3.4 billion in benefits for its participants, including $1.5 billion last year alone, he said.

“We have huge potential to increase those benefits if we move to a day-ahead market that covers that same 80%,” and even more if CAISO were to lead a Western RTO, he said.

Having two markets in the West and bifurcating those benefits would be a step backward, O’Connell said.

‘A Swiss Cheese Universe’

In a subsequent panel, Stefan Bird, CEO of PacifiCorp division Pacific Power said the benefits of CAISO’s WEIM are proven and substantial.

PacifiCorp co-founded the interstate trading market with CAISO in 2014 and was the first utility to commit to joining EDAM in December. The utility serves 2 million customers in California, Idaho, Oregon, Utah, Washington and Wyoming. (See PacifiCorp to Join EDAM, Final Plan Released.) The company is so far not among the 31 utilities and industry groups that have officially signed on to SPP’s effort to develop a Western market.

“It doesn’t matter if we’re in our red states or blue states. We save money, improve reliability and reduce emissions [through the WEIM],” Bird said. “It’s not theory. This is the real deal.”

PacifiCorp has derived nearly $600 million in benefits as a WEIM participant, much of it by buying cheap solar power from California and other Western states, he said.

“Prior to the EIM existing, we wouldn’t have been able to take advantage of all that low-cost solar that was being deployed very rapidly in California [without] enough load in California to use it all,” Bird said. “The alternative in California was to curtail it. But for the EIM being able to trade very rapidly intra-hour — as opposed to the old days [when grid operators would] pick up the phone and try to make trades on an hourly basis — that simply wasn’t possible.”

PacifiCorp has reduced its greenhouse gas emissions by 42.6 million metric tons since 2014 because it does not need to run its fossil fuel-burning plants as much when renewable power is available through the WEIM, he said.

“The morning sun comes up with all that solar energy in Utah and southern Oregon and California, Bird said. “We’re taking every bit of it we can, and we back off our coal fleet, our gas fleet. We’re not incurring those fuel costs. We’re not burning the emissions, and we save our customers money.”

“We don’t want to see those benefits disappear or get broken, and that’s precisely what’s being contemplated in a separate [SPP day-ahead] market that would be created on top of [the WEIM’s] footprint,” Bird said.

Having two day-ahead markets in the West would produce seams problems between balancing areas and provoke “situations of conflict where a peace treaty has got to be negotiated, and that’s going to take years,” he said.

It would be “a Swiss cheese universe that I think would really put a dent in those [WEIM market] benefits that are most important to us,” Bird said.

Independent Governance

Tom Bechard, CEO of Canadian energy marketer Powerex, said the seams issue was being overblown by those in favor of a CAISO-led day-ahead market. Powerex has been a WEIM member since 2018, but Bechard’s comments reflected a preference for SPP’s Markets+.

“There are some people in the room who are putting seams coordination first,” Bechard said. “I think that’s really kind of a misplaced priority. The [dialogue] I’m hearing about seams seems to be more fear-based than fact-based. And I know for a fact that seams can be managed efficiently through joint operating agreements.”

A higher priority for those weighing day-ahead markets should be governance, Bechard said. He recommended a model resembling SPP’s governance structure.

Stefan Bird Tom Blechard 2023-04-12 (RTO Insider LLC) Alt FI.jpgPacific Power CEO Stefan Bird (left) and Powerex CEO Tom Blechard debated the merits of day-ahead markets being developed by CAISO and SPP. | © RTO Insider LLC

 

“It is not just an independent board that’s required,” Bechard said. “You need to have stakeholders with voting rights, and you need to have an impartial operator. Having stakeholders with voting rights ensures that it’s the stakeholders that determine what goes to the board rather than the market-operator staff. And having an impartial operator ensures that the operator is not subject to undue influence from any particular state or set of states.”

SPP has an independent board, a committee of state regulators and stakeholder groups that develop and vet policy proposals. It plans to apply the same governance structure to Markets+.  

CAISO staff and management develop policy proposals with stakeholder input. The ISO is led by a Board of Governors appointed by the California governor and confirmed by the state Senate, resulting in all of its members being Californians. A legislative effort is underway to open the board to out-of-state members so CAISO can become an RTO. (See Lawmaker Introduces Bill to Turn CAISO into RTO.)

The WEIM Governing Body includes members from outside California and shares joint authority with the ISO Board of Governors over matters affecting the interstate market. EDAM also would be governed under a joint-authority model.

‘Grid of the Future’

Bechard contended that an SPP day-ahead market could offer greater benefits in the future through resource diversity, assuming new interregional transmission lines connecting it to the Pacific Northwest get built.

When envisioning a day-ahead market, “we shouldn’t be thinking about the grid that we have today,” he said. “We should be thinking of the grid of the future.”

As more solar comes online in the Desert Southwest and California and thermal generators retire, resource diversity and trading benefits between the regions will diminish, he said.

“They’re going to have the same resources, the same load, the same issues with solar oversupply and evening ramp and net peak load,” Bechard said. “We see that opportunity to trade between those markets declining.”

Resource diversity and economic value between the Pacific Northwest and SPP will be greater, he said. The Northwest has large amounts of hydropower, and SPP has 30 GW of wind power in an area with weather patterns and peak demand times different from the West’s, he said.

Bechard cited a Lawrence Berkeley National Laboratory report that showed some of the nation’s highest-value transmission lines could be built linking SPP to the West, alleviating congestion and allowing resource transfers. (See Lawrence Berkeley Lab Sees New Transmission Value Spike in 2022.)

If the 31 entities that have signed on for the development phase of SPP’s Markets+ program continue to its operational phase, the market would have a 50 GW peak load, he said.

California has a 54 GW peak load, so if CAISO were a separate market, there would be “two big markets … optimizing within their footprints” and potentially engaging in “robust and automated trade” in the day-ahead time frame, he said.

“It’s much better than the status quo,” Bechard said. “And it’s definitely not a step back from what we have today.”

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AEP, Liberty Call off Sale of Kentucky Operations

American Electric Power (NASDAQ:AEP) and Liberty Utilities (NYSE:AQN) have shelved their plans to exchange AEP’s Kentucky operations for $2.6 billion, ending two years of attempts to gain the transaction’s approval.

AEP announced Monday that it and Canada’s Algonquin Power & Utilities, Liberty Utilities’ parent company, have mutually agreed to cancel the deal two weeks before either party could independently pursue termination rights. In a press release, AEP characterized the sale’s collapse as a reaffirmation “of its commitment to Kentucky customers.”

The company said it now must take “swift and decisive action to be best positioned in the near term while continuing to develop a long-term strategy for Kentucky.” That means filing a base rate case with the Kentucky Public Service Commission for 2024 that will include securitizing retired coal generation.

“As a partner in Eastern Kentucky for more than 100 years, we’re renewing our focus on bringing opportunities to the region and supporting the communities we serve,” AEP CEO Julie Sloat said. “We are working diligently to reimagine our strategy with the goal of not just supporting Kentucky but being an essential part of its economic and energy future. “We believe there are opportunities ahead for our Kentucky operations, and we will focus our efforts on economic development, reliability and controlling cost impacts to customers.”

Late last month, the Kentucky PSC, the Kentucky Office of the Attorney General and Kentucky Industrial Utility Customers urged FERC to halt the sale for a second time. They argued that Kentucky customers would pay larger bills through increased zonal transmission rates under Liberty ownership. (See Kentucky Officials Ask FERC to Deny AEP-Liberty Deal.)

FERC first rejected the sale in late 2022, indicating that the companies needed to pledge more consumer protections.

In a separate press release, Algonquin Power CEO Arun Banskota said the management team and board of directors decided “after careful consideration” that the transaction was not in Algonquin’s best interest “in light of the evolving macro environment.”

“I would like to thank the teams who have worked tirelessly throughout this entire process. Looking forward, [Algonquin] remains supported by a high-quality asset base [and] a strong balance sheet, and is well positioned to deliver sustainable, long-term growth, capitalize on the energy transition and create value for shareholders,” Banskota said.

AEP also announced it had elevated interim Kentucky Power President and COO Cindy Wiseman to permanent president and CEO.

“Wiseman’s experience overseeing customer service, economic development and government affairs positions her well to redefine the company moving forward,” AEP said.

AEP reaffirmed its 2023 earnings guidance range of $5.19 to $5.39/share and an annual long-term growth rate of 6 to 7%. It said proceeds from its recently announced plan to sell its 1,365-MW unregulated, contracted renewables portfolio to IRG Acquisition Holdings for an expected $1.2 billion will compensate for previously forecasted proceeds from its Kentucky operations sale. AEP also said its equity financing forecast remains unchanged absent the transaction.

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Stakeholder Soapbox: Biden’s Cyber Strategy Risks Demonizing Biggest Ally: The Private Sector

Shahid Mahdi (Shahid Mahdi) FI.jpgShahid Mahdi

By Shahid Mahdi

April 16 marked 30 years since one of the seminal moments of our digital being. In 1993, amidst a need to keep up with the dizzying pace of technological innovation, the Clinton administration announced a cryptographic device that would enshrine itself in cybersecurity history.

The MYK-78 was developed by the National Security Administration to give the government a “back door” into all communications in the interest of national security. Nicknamed the “Clipper Chip,” it would permit federal, state and local law enforcement to access and decipher voice and data transmissions at their discretion.

Unsurprisingly, the notion of the government having a permanent opt-in method to eavesdrop on all cell phones, computers and pagers was met with a vociferous uproar. Sure enough, a meager three years and much backlash later, the Clipper Chip was scrapped.

The rise and very quick fall of the Clipper Chip is a cautionary tale of how a failure to understand the operational environment of privacy and tech can lead to failures in policy.

President Biden’s National Cybersecurity Strategy, published March 2, is not a failure in policy. It espouses objectives that are long overdue amidst a world of pervasive cyber threats. It includes the desire to eliminate malicious cyber actors from Russia and China and defend critical infrastructure like hospitals and power generation. “Its implementation will protect our investments in rebuilding America’s infrastructure, developing our clean energy sector, and re-shoring America’s technology and manufacturing base,” the Strategy says. It would expand “the use of minimum cybersecurity requirements in critical sectors,” building on those governing the electric industry.

However, one particular element of the Strategy must tread very carefully: “Shape Market Forces to Drive Security & Resilience.” It aspires to promote privacy and security of personal data, and, interestingly, aims to shift liability for software products from users to tech companies to promote security practices.

This comes at a time when relations between government and tech are at something of a nadir. Apple, Google and Meta have been vocal about their privacy practices: Tim Cook was obstinate in refusing to give the government a back door into iPhones; Meta promulgated end-to-end encryption loud and clear on its Messenger and WhatsApp platforms. The message here? Trust us as we’ll keep the government out of your pocket. And from Apple: Our privacy measures are way better than our competitors’s.

Federal Trade Commission Chair Lina Khan has dialed up government bellicosity toward the tech companies, and the Strategy will further empower this. The FTC may be one of the first agencies to take advantage of the ability to “shape market forces” if given the power by Congress to do so. Should the liability initiatives in the Strategy give birth to more lawsuits, tech companies will be hit with a deluge of regulations and policies — a tightening of the government leash on the so-called market forces.

And then battle will be done in the courts, as it’s being done already. The language “shifting liability” may be innately at war with the biggest, most substantial legal defense in a tech company’s arsenal: Section 230 of the Communications Decency Act, which Biden and company have been vocal about revamping. Section 230 exculpates a publisher from the content on its platform (i.e., you can’t prosecute Meta for a graphic video posted to Facebook). The Supreme Court is deliberating over a case predicated on Section 230 at the time of this writing.

Further friction between tech and government would also, ironically, weaken the Strategy itself. Why? The “Defending Critical Infrastructure” and “Dismantle Threat Actors” sections of the Strategy involve the promotion of public-private collaboration. Widening the existing wedge between tech and the government doesn’t sound like the way to do this.

Alphabet, Meta, Apple, Amazon, and Microsoft and company arguably have the most sophisticated, talented minds and data repositories that can safeguard the U.S. in a world of nefarious cyber threats. Why run the risk of antagonizing them?

Shahid Mahdi is product lead for EnerKnol, a provider of energy regulatory intelligence software.

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Researchers Modeling Jet Stream Interference with OSW

Researchers are seeking ways to mitigate wind patterns that could limit the output or cause excessive wear on the hundreds of wind turbines planned off the Atlantic Coast.

The National Renewable Energy Laboratory said last week that it and the General Electric Global Research Center (NYSE:GE) are applying ultra-powerful supercomputer modeling to the low-level jet stream (LLJ) patterns that exist on the Outer Continental Shelf along the eastern U.S.

The region, with its steady wind and shallow waters, is regarded as ideal for wind power generation, but there is little observed data on actual performance: OSW in the U.S. so far consists of two test turbines off the coast of Virginia and a pioneering Rhode Island wind farm whose five 6-MW turbines are much smaller and much closer to shore than what is planned to come.

The blade sweep of the largest OSW turbines can approach 10 acres of airspace and reach almost 900 feet above the sea surface. LLJs can occur at this altitude along the Atlantic Coast, and they can be strong, NREL said.

The researchers in their study said that depending on the detection criteria used, LLJs can be observed at least 2 to 7% of the time in the New York Bight, where multiple wind projects are envisioned. But the LLJ is categorized as a nonconventional wind event, they said. Its characteristics are not well understood, and it is not currently considered in some annual energy production calculations.

With exascale computer simulations, the research team has shown a propensity for LLJs to cause a severe wake-induced decrease in wind turbine power output and an increase in load on turbine blades. This could cause excessive wear and tear on the equipment, lower its efficiency and even cause shutdowns, NREL said.

But the simulations are also pointing toward strategies to mitigate the impacts of LLJs. In a news release, the principal investigators said this is a promising development.

“Site-specific, high-fidelity simulations of wind farms are typically beyond the scope of the wind energy design process due to the sheer complexity of the science and computational modeling involved,” said Balaji Jayaraman, a senior engineer at GE Research. “However, through advances in exascale computing algorithms and models for multiscale atmospheric flows — driven by the U.S. federal research labs including NREL and powered by the world’s leading supercomputing capabilities — we’ve been able to demonstrate the feasibility of new wind turbine designs previously not possible.”

“This team was able to accomplish all the goals originally proposed back in 2019,” added NREL’s Shashank Yellapantula.

NREL is the lead lab for the U.S. Department of Energy’s Exascale Computing Project. It has been spearheading an effort to simulate the air flow around wind turbines in a large wind farm with unprecedented accuracy using the latest generation of computing.

The NREL/GE team ran simulations on five- and 20-turbine arrays in a 10-km region with 2 billion points on a grid pattern to visualize the invisible impacts of flow dynamics and make conclusions.

They found LLJs caused a significant increase in load on turbine blades. In the larger wind farm, the LLJs led to deeper wakes that reduced wind velocity and increased turbulence, reducing power output.

Derating the turbines — running them at a lower power level to limit damage — has been the common response by wind farm operators to this scenario, NREL said.

Using the data and observations gathered so far, the team is now designing strategies to reduce the impact of LLJs while maintaining higher power output.

“We’ve never had this level of detail available to us before to understand that wind farms that are designed a certain way can withstand the power of LLJ phenomena,” Yellapantula said.

Bringing emissions-free OSW online is a priority for the federal government and many states as a strategy to limit the impact of climate change.

More than two dozen OSW lease areas are designated from Massachusetts to South Carolina; construction has begun in two, and plans for several others are under review by the U.S. Bureau of Ocean Energy Management. Manufacturers meanwhile are working to improve technology and expand factory capacity.