[NOTE: This story was updated to include additional appeals filed after April 21.]
The battle over FERC’s order expanding PJM’s minimum offer price rule (MOPR) moved to the federal courts this week as environmental groups, electric cooperatives and state regulators filed petitions for appellate review.
The filings were set in motion by the commission’s April 16 orders denying rehearing of its June 2018 order that declared PJM’s capacity market unjust and unreasonable (EL16-49-001, et al.) and most of its December 2019 ruling, which directed PJM to expand the MOPR to all new state-subsidized resources (EL16-49-002, et al.).
Four environmental groups, the Natural Resources Defense Council, Sierra Club, Environmental Defense Fund and the Union of Concerned Scientists (UCS), filed a joint petition late Monday with the D.C. Circuit Court of Appeals. Also filing petitions with the D.C. Circuit were the North Carolina Electric Membership Corp. and the American Public Power Association (APPA), filing jointly with American Municipal Power.
The Illinois Commerce Commission filed a petition with the Seventh Circuit Court of Appeals in Chicago.
The New Jersey Board of Public Utilities and the Maryland Public Service Commission filed a joint petition with the D.C. Circuit on April 27 and Energy Harbor, the former FirstEnergy Solutions, weighed in on April 21.
E. Barrett Prettyman D.C. Circuit Courthouse
John McCaffrey, APPA’s senior regulatory counsel, said he wasn’t certain if petitions would come from other organizations but noted that several other stakeholder groups previously filed protective appeals of the December order that were to be held in abeyance until after FERC’s ruling on rehearing.
State consumer advocates from New Jersey, Maryland, Delaware and D.C. asked the court on Feb. 29 to hold their petition for review in abeyance, acknowledging that it could be dismissed under the court’s “current precedent,” which holds that the commission’s rulings are not “final” orders ripe for judicial review while rehearing is pending. (See Consumer Advocates Appeal MOPR Order to DC Circuit.)
Also filing petitions for review in abeyance with the D.C. Circuit were the Natural Rural Electric Cooperative Association on March 31, Old Dominion Electric Cooperative on April 13 and the East Kentucky Power Cooperative on April 14.
As is customary, though, the petitions for review identify only the orders being challenged. The grounds for the challenges will be spelled out later in briefs. But the rehearing requests that FERC rejected outlined several potential lines of attack. One is whether the commission is intruding on state regulation of generation in violation of the Federal Power Act. The commission also is likely to be challenged on its decision to apply the MOPR to state-subsidized resources but not those benefiting from federal subsidies.
In a strongly worded joint press release, the environmental groups said the commission’s rulings could force 65 million customers in the Mid-Atlantic and Midwest to pay billions of dollars more for electricity while undermining state efforts to promote carbon-free resources.
“FERC has overstepped its jurisdiction with its reckless MOPR decision, which will worsen the dangerous health impacts of fossil fuel combustion in communities from Virginia to Illinois,” said Casey Roberts, senior attorney with the Sierra Club. “We plan to aggressively pursue FERC’s harmful orders through the courts, and to support states in exiting PJM’s capacity market so they can pursue the affordable clean energy policies needed to protect communities.”
Mike Jacobs, senior energy analyst at UCS said, “FERC’s choice to overlook numerous existing energy subsidies and attack states’ explicit efforts to reduce air pollution and carbon emissions is bad policy based on flawed and legally questionable reasoning. Every state in PJM has something to lose, and it’s a shame this must now be resolved in court.”
The court filings come even as PJM plans to implement the December order and reschedule the 2019 capacity auction. Comments on PJM’s compliance filing in response to the December order are due May 15.
In its ruling April 16, FERC agreed with PJM’s interpretation that voluntary renewable energy credits and participation in the Regional Greenhouse Gas Initiative will not subject capacity resources to the expanded MOPR. (See FERC: RGGI, Voluntary RECs Exempt from MOPR.)
ERCOT on Tuesday added two weeks to most of its COVID-19 coronavirus response measures, extending virtual meetings and barring most visitors from its facilities through May 17.
The ISO, which manages almost 90% of the Texas grid, said it is closely monitoring the outbreak and following health agency guidance in extending the measures through “an abundance of caution.”
The ERCOT service region accounts for 90% of the Texas grid. (ERCOT)
ERCOT closed its facilities to most outside visitors on March 3, directed all meetings be held virtually and restricted staff travel. It said it will consult with stakeholder leadership in determining how long meetings are held remotely. (See ERCOT, SPP Adapt to ‘New Normal’ in Pandemic.)
The grid operator required employees who did not need to be on-site to work from home beginning March 18. An employee task force has been charged with developing a strategy for returning to work on-site. The team will present its findings to ERCOT’s Pandemic Planning Team and executive leadership for final approval.
A spokesperson said there is “no guarantee” staff will be able to return to their offices on May 18.
ERCOT announced the extension as Texas joins other states in taking steps to reopen its economy. State parks opened Monday, and retail shops will be allowed to sell items for curbside pickup on Friday.
Texas ranks near the bottom of U.S. states in testing per capita at one test per 1,000 people. The state said Tuesday it has 19,548 confirmed cases and 495 deaths. A University of Texas model says the state will face a peak number for deaths on April 26.
SPP’s Market and Operations Policy Committee last week endorsed a revision request that would again eliminate Z2 revenue credits for sponsored transmission upgrades, overlooking some members’ concerns about a second regulatory defeat at FERC.
The commission in January rejected without prejudice SPP’s proposal to use incremental long-term congestion rights (ILTCRs) instead of Z2 credits, finding the modifications to the existing ILTCR compensation term to be unjust and unreasonable. However, the commission allowed the RTO to submit a revised proposal for the commission’s consideration without a cap limiting the terms and potential value of the credits’ replacement (ER20-453). (See FERC Order Keeps Z2, Aids EDF’s Sponsored Project.)
SPP has proposed two changes in its latest revision request (RR 401), removing “maximum” from the placeholder for the ILTCR’s term and removing the cap on the amount recoverable through the candidate ILTCRs. The latter change would allow for a term of at least 10 years, but not more than 20 years, making the candidate ILTCRs viable and tradeable.
“We are confident this revision request addresses the concerns that were raised and will be approved by FERC,” SPP attorney Tessie Kentner told the MOPC during its April 14 webinar. “Just because our ILTCR process is different than other ISOs and RTOs doesn’t mean it’s different from FERC’s requirements.”
SPP is required to file again with FERC by the end of April. It hopes to have ILTCRs replace Z2 credits by July 1.
Under Attachment Z2 of SPP’s Tariff, sponsors that fund network upgrades can be reimbursed through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade.
EDP Renewables’ David Mindham argued that because the latest Z2 filing fails to address substantive arguments raised in previous protests, it faces the “real risk” of being rejected by FERC. EDF Renewable Energy has said eliminating the Z2 credits would allow certain transmission customers to become “free riders,” as they would no longer have to reimburse the upgrade sponsors for directly assigned upgrade costs.
“What’s left after Z2 is removed is discriminatory, unjust and unreasonable,” Mindham said. “It’s clear from FERC precedent that all funders of transmission should be treated equally. This filing is a step back.”
EDF legal counsel Dan Simon charged that SPP’s ILTCRs are lacking, when compared to other RTOs and ISOs.
“The current rules for ILTCRs are just not as strong as they ought to be,” he said. “We continue to hear people refer to the ILTCR product as ‘worthless.’ That demonstrates pretty clearly that the ILTCRs … are not as good as other [RTOs].
“There needs to be some sort of rate recovery mechanism for the entity that pays for that upgrade. ILTCRs don’t serve that function in their current form,” Simon said.
EDP cast the only vote against RR 401. Seven other members, primarily renewable developers and independent generators, abstained.
Zonal Planning Criteria Meets Opposition
MOPC members also sought to address another nettlesome issue — the tension between transmission owners and customers in the same transmission zones — with their approval of RR 391.
As written, the change establishes uniform local planning criteria within each pricing zone under the Tariff’s Schedule 9, placing the responsibility on the host TO to facilitate a “consensus-driven” criteria for reliability upgrades. Schedule 9 pricing zones calculate network service request charges as a ratio share of the monthly annual transmission revenue requirement.
Transmission customers pushed back against RR 391 over concerns the process lacks transparency and does not treat all loads equally. The request hinges on the facilitating transmission owner (FTO), determined yearly by the network customer with the largest load, scheduling an open meeting with other TOs, transmission customers and firm-service customers to establish the zonal planning criteria or any changes to it.
“If you look at the definition of the FTO, one of the things it requires is that the largest load in the zone determine who the FTO is,” Kansas Power Pool’s Larry Holloway said. “I’ve never seen a more open violation of open access.”
“I know consensus can’t be forced, but this revision request does not even call for consensus,” said consultant Jack Madden, representing the East Texas and Northeast Texas electric cooperatives. “It calls for a meeting, maybe only one, in which others are invited. After that, the FTO does or doesn’t establish local planning criteria.”
Madden said the Holistic Integrated Tariff Team, which included the Schedule 9 planning criteria among its recommendations last year, “clearly” considered a process that would lead to consensus. (See SPP Board Approves HITT’s Recommendations.)
“That language has been left on the cutting-room floor,” he said.
Melie Vincent, director of operations for the Oklahoma Municipal Power Authority, referred to business clichés “hope is not a strategy” and “the past does not predict the future” in stating her case.
“Sure, we could have some blind faith. … I don’t want to hamstring efforts in the future, but I don’t feel it protects the smaller players in the market,” she said.
Oklahoma Gas & Electric’s Greg McAuley, warning against the “esoteric rabbit trails” so common during MOPC discussions, said, “I haven’t seen an example within SPP of anything like this being used in a heavy-handed way to force something down someone’s throat when reliability is the ultimate goal.”
“There’s a difference between trying to reach consensus and actually reaching consensus,” said Southwestern Public Service’s Bill Grant. “It’s important everyone gets to have input, and it’s important you try to develop criteria that applies to everyone in the zone. It’s in nobody’s best interest to come up with criteria that doesn’t work for everyone in the zone.”
Not surprisingly, it took an electronic vote to determine the motion had passed with an overall approval of 73.44%. Fifteen of the 17 TOs approved the motion, but the margin was much slimmer among transmission customers. They approved the motion 17-15, with 10 abstentions.
Members Reject 60-40 Split in ITP 2021 Futures
The MOPC revisited the consolidation of futures in the Integrated Transmission Planning process’ 2021 assessment, rejecting a working group’s recommendation for a more conservative blending of the scenarios.
Members voted down a motion to use a 60-40 split between the two futures: the “business-as-usual” Future 1 case that reflects current trends, and the “emerging technologies” Future 2 case, which is driven by assumptions that distributed generation, demand response, energy efficiency and energy storage will have a major effect on load and energy growth rates.
The motion came up short of the necessary two-thirds mark for approval with only 65.17% approval. The discussion was a carryover of an unresolved discussion during the January MOPC meeting. (See SPP Members Delay Decision on 2021 Tx Assessment.)
ITC Holdings’ Alan Myers, who chairs the Economic Studies Working Group that proposed the 60-40 split, said the weighting responded to concerns over favoring extra-high-voltage solutions without making a major change in the process. SPP has said a similar weighting would not have changed the results of the 2019 assessment. (See “MOPC Approves $336 ITP Portfolio,” SPP MOPC Briefs: Oct. 15-16, 2019.)
Renewable interests favored a more aggressive forecast that incorporates additional energy growth. Others, wary of increasing transmission costs, favored the more conservative approach. Future 1 projects about 32 GW of wind installations by 2031, while Future 2 foresees about 37 GW.
“The more renewables you have, the more risk you have in building transmission due to the uncertainty of where the wind will be sited,” said Golden Spread Electric Cooperative’s Natasha Henderson. “I’m more confident of the transmission being built in Future 1.”
“I’m concerned when you hear load-serving entities are committing their customers to these long-term assets,” said McAuley, who has long expressed his concerns over escalating transmission costs and proposed a 70-30 split. “Being the Saudi Arabia of wind is absolutely a positive thing, but [SPP has] spent $10 billion already in transmission. Our transmission rates are not going down. The question has to be who’s going to be paying for the transmission in this tsunami of wind that’s going to swamp this footprint.”
American Electric Power’s Richard Ross said the 50-50 consolidation would be the “appropriate rating,” given customers demand for renewable energy.
“We have to look out for the benefits customers get from delivering these resources and building the backbone we need for the increased transition of our fleet,” Ross said. “Some of you seemed to be quite happy with the [wind] facilities and construction of the system while meeting your needs. Now that we’ve gotten there, when we’re trying to take steps to build the last miles on the eastern side of grid, you’re opposed. That kind of mindset is short-sighted.”
SPP’s COVID-19 Load down 4-6%
SPP COO Lanny Nickell said the RTO will begin holding hourlong conference calls to update the MOPC on SPP’s responses to the COVID-19 pandemic. The first members-only call, to protect confidential information, will be held next week.
SPP’s forecast transmission outages for 2020, compared to the previous two years | SPP
Nickell said that like much of the rest of the electric industry, SPP has experienced a 4 to 6% reduction in load stemming from stay-at-home measures to halt the pandemic. The reductions have increased as temperatures have risen. The RTO has also noticed an uptick in canceled planned generation and transmission outages.
“There’s a 30% reduction in capacity that is currently scheduled to be out over the next couple of months, compared to the same time frame in the last few years,” he said.
In preparing his update, Nickell said he contacted each of the operations crews for their feedback.
“They said, ‘We just want to stay healthy so [members] can continue to do their work. We know our members rely on us to keep the lights on,’” Nickell said.
In a follow-up email to stakeholders, CEO Barbara Sugg said SPP has not had a confirmed case of COVID-19 among staff. She said the organization has adapted to the pandemic — the web-only MOPC meeting attracted 229 attendees at one point — and is already developing plans to ensure a safe and orderly transition.
“Like the rest of you, our staff anxiously awaits the end of the pandemic and our collective return to business as usual,” Sugg said.
Meter Ownership Still an Issue with Some
A Market Working Group recommendation to align the protocols with current metering standards was passed over the objections of several members who felt the revision request (RR 324) was not specific enough. A motion to endorse received six opposing votes and nine abstentions.
Several members pointed out market participants are not always the owners of the equipment they represent in the market and suggested replacing the term “market participant” with “asset owner” to more accurately represent who is responsible for the equipment.
“There’s not specific identification of who is responsible for paying for things and testing for things in the meters. It puts the market participant as responsible for everything,” said Tenaska Power Services’ John Varnell. He said other SPP documentation and FERC documentation are more specific, laying similar responsibilities on the interconnection customer.
Richard Dillon, SPP market policy technical director, said market participants sign documents that clearly state they are responsible for the meter and are required to have meter agents.
“We don’t know who owns it, who installed it, but the responsibility is on the market participant,” Dillon said.
Grant, who initially opposed RR 324, said he was comfortable to move along with the change because of his confidence that “meter agent agreements will cover this.”
MOPC Reorg ‘90%’ Complete
Nickell said SPP is “about 90% there” in its reorganization of the MOPC’s structure, which currently includes 16 working groups that report up to the committee’s leadership.
Working with Chair Holly Carias and Vice Chair Denise Buffington, Nickell said they have divided the groups into the committee’s primary responsibilities: markets, operations and planning. Their goal is to better align the group structure with SPP’s primary functions and oversight responsibilities, focusing MOPC on policy-level work while letting the working groups take care of tactical issues.
The effort will result in the retirement of a couple of working groups, while others will be repurposed as user groups or advisory groups that “facilitate advice when advice is needed to be given to those functional areas,” Nickell said.
For instance, the Business Practices Working Group will become the Transmission Service User Group. Other user groups will include Generation Interconnection, Operations Training, Security and Change.
“We’ll ensure … the appropriate functions are in the right place,” Nickell said. “This will facilitate a more effective and efficient approach to our work.”
MOPC’s current organizational structure, and the new structure for 2021 | SPP
Some stakeholder groups will become advisory groups, including the Seams Steering Committee. That will incorporate seams oversight into applicable functional areas, Nickell said.
The Value and Affordability Task Force last year recommended the reorganization after eight months of study. The senior-level group was created to search for ways to increase SPP’s value and improve affordability while maintaining and protecting its mission. (See SPP Value Group Finds No ‘Silver Bullets’.)
Saying he believes the benefits are “numerous,” Nickell said staff are still working on a cost-benefit analysis.
MOPC leadership also plans to recommend improvements to the revision-request process. “We want to make it clearer and streamline it and ensure we have the appropriate inputs for policy,” Nickell said.
The recommendations will be documented as a revision request, to be presented to MOPC during its July or October meetings.
SPP to Recommend Pausing Competitive Project
Casey Cathey, SPP director of system planning, told the MOPC that staff will recommend to the Board of Directors next week that they suspend a competitive, interregional project, pending FERC’s approval of an agreement with Associated Electric Cooperative Inc. (AECI).
SPP and AECI have agreed to perform a joint study that will include a 345-kV competitive project approved in January by the board as part of the 2020 SPP Transmission Expansion Plan. The $152 million, 105-mile Work Creek-Blackberry upgrade in Kansas and Missouri will be analyzed to determine whether there are any system reliability impacts. (See “SPP, AECI Agree to Joint Study,” SPP Seams Steering Committee: April 2, 2020.)
Cathey said SPP and AECI are developing a cost and usage agreement to execute once the joint study identifies whether the project will create any reliability issues. Should the study, which is expected to be completed in August, identify additional upgrades on the AECI system, staff will revisit the project with stakeholders and the Regional State Committee.
“We recognize this potentially delays issuance of a [request for proposals], but there’s so much uncertainty with outside entities associated with FERC,” Cathey said. “FERC is probably the biggest wild card here, because of the coronavirus.”
He said the delay may push the project’s energization date back one or two months.
Members Approve 1 RAS, Retirement of Another
The MOPC unanimously approved its consent agenda, which included one revision request, a remedial action scheme (RAS) retirement and five project cost reset recommendations, but not before discussing separately the creation of another temporary RAS.
Members approved Xcel Energy’s recommended RAS to allow its 522-MW Sagamore Wind Farm in West Texas to interconnect with subsidiary SPS’ Crossroads substation before an additional 345/230-kV transformer at Tolk Station is in place. The RAS would monitor the 345-kV Crossroads-Tolk line’s current, tripping the wind farm when the current exceeds a specified level in place. The second 345/230-kV Tolk Station transformer is expected to be in service in March 2022.
Grant said the utility is working “diligently” to upgrade its system, at which point the RAS would no longer be needed. Nebraska Public Power District, Tri-County Electric Cooperative, Missouri River Energy Services and GridLiance opposed the motion, and 11 other members abstained.
The committee also asked the Transmission, Operating Reliability and System Protection and Control working groups to develop policy around future RAS schemes.
The consent agenda’s approval also resulted in the retirement of a RAS in effect at the Oklaunion Power Station in the Texas Panhandle since the mid-1980s. The plant itself is scheduled to be retired in October. (See PSO Officially Retires Oklaunion Coal Plant.)
The Project Cost Working Group recommended baselines be reset for several previously approved projects. Three of the projects, located in North Dakota and belonging to Basin Electric Power Cooperative, were approved by FERC before Basin joined SPP in 2015 and are now in service.
The Basin projects included a nearly $30 million decrease, to $89.2 million, for a 70-mile, 345-kV line, a new switching station and an expanded substation; a $36.6 million decrease, to $95.7 million, for a 75-mile, 345-kV line, a new substation and necessary terminal upgrades; and a $27.3 million decrease, to $95.3 million, for a 58-mile, 345-kV line and new substation.
Other projects included:
SPS’ reconfiguration of a 230-kV bus tie into a double-bus and breaker scheme in West Texas. The project’s costs have increased by $8.5 million to $19.7 million.
Central Power Electric Cooperative’s 24-mile, 115-kV line in North Dakota. The project costs have dropped $8.5 million to $14.4 million.
The lone Tariff change request (MWG–RR383) revises the Integrated Marketplace protocols’ mitigation requirements by clarifying that energy offers below $25/MWh and operating reserve products below $10/MWh are not subject to the mitigation process. It also makes clear that energy offers for locally committed resources are not subject to the normal mitigation process, but are capped at 10% above their mitigated offer and removes language requiring market participants to contact the Market Monitoring Unit before submitting an offer above their conduct threshold.
SPP Board of Directors Chair Larry Altenbaumer last week asked the Strategic Planning Committee for an education session on congestion hedging following stakeholder disagreement over the best way to proceed with a recommended white paper.
“The SPC’s role needs to come into sharper focus,” Altenbaumer, who also chairs the committee, said during its conference call Wednesday. “The best way to be successful with these recommendations is if they come up through the stakeholder process.”
The Holistic Integrated Tariff Team (HITT) last year recommended that SPP develop a market mechanism to hedge load against congestion charges. The team suggested modifying the existing market design to use only excess auction revenues to fund counterflow optimization positions.
The HITT directed the Market Working Group (MWG) to develop a white paper documenting a recommended path forward. The group came up with three counterflow optimization options:
Assigning counterflow cost to the market participant after the annual auction revenue rights (ARR) auction’s first round.
Assigning the counterflow cost to ARR surplus after the annual transmission congestion rights (TCR) auction.
Creating a new round in the long-term congestion rights (LTCR) allocation, with the counterflow cost directly assigned to the market participant. If the LTCRs become infeasible, the cost is assigned to the ARR surplus.
The MWG rejected all three options during its February meeting, after having earlier voted to keep the current design for congestion hedging. The group has said the second option satisfies the HITT initiative, but the Markets and Operations Policy Committee rejected the option last week, directing the group to further develop the first option.
“You’re not going to get consensus on this, because a majority of the companies are happy with their hedging portfolios,” warned Bill Grant, with Southwestern Public Service. “When we designed the market, we decided against counterflows. The majority of the group is not recognizing there’s a problem. They’re looking at the monetary value their customers are receiving from current hedging activities.
“The do-nothing option seems to be the one that’s winning the day.”
Keith Collins, executive director of SPP’s Market Monitoring Unit, said his team doesn’t have a preferred proposal but is considering developing its own mechanism “that could address the concerns of HITT and others.”
“Our view, as a neutral entity, is that the options have pros and cons. There are no clear-cut winners,” he said. “These are very complex issues. The TCR process is complex, but some of these solutions have additional layers of complexity. We’re happy to be engaged to find a solution.”
Committee Endorses 2 HITT Recommendations
The SPC endorsed two additional HITT recommendations that passed the MOPC the day before: the establishment of uniform Schedule 9 local planning criteria and the elimination of Z2 revenue crediting.
The committee approved the local planning criteria 9-1, with three abstentions. The elimination of Z2 crediting passed 12-0, with one abstention.
SPC members repeated some of the same concerns they had expressed during the MOPC meeting. The measure cleared the MOPC’s two-thirds approval threshold at 73.44%, evidence of transmission customers’ pushback over their perception that the process lacks transparency and does not treat all loads equally. The revision request relies on a “facilitating transmission owner,” determined yearly by the network customer with the largest load, scheduling an open meeting with other TOs, transmission customers and firm-service customers to establish the zonal planning criteria or any changes to it.
Golden Spread Electric Cooperative’s Mike Wise, SPC vice chair, said he felt the criteria’s language fell short as he shared with the committee the concerns of transmission-dependent utilities.
“The wholesale customers within the zones really wanted a collaborative process to be at the table,” he said. “Secondly, they understood there would be no cram-downs by the TOs. They hate it. They’ve lived with it for 60 years. We have to ensure all loads within a zone are treated equally and affiliates would not be favored through local criteria.”
American Electric Power’s Richard Ross said the idea that all loads will be treated equally would be the easiest “to scratch off the list as being nonexistent.”
“There will be one, singular policy that applies across the zone,” he said. “You’ll have the RTO applying that policy equally. It does require a collaborative process. At the end of day, someone has to make a decision if there’s not 100% agreement. We just need some experience with it. If people are not happy with it, we can revisit it.”
SPP Engineering Vice President Antoine Lucas said staff have been working to determine what “consensus-building” means in the context of local planning criteria.
“We came to the conclusion from staff’s role of facilitating the overall process that, within the zones, it’s probably more appropriate that they work together to define their view of consensus, or what levels of agreement are appropriate for moving forward,” Lucas said. “Does everyone have to agree with it? Maybe some voting structure needs to be put in place.”
SPC Adds New Members, Contracts with Facilitator
Barbara Sugg’s promotion to SPP’s CEO position and director Bruce Scherr’s recent passing has resulted in several changes in the SPC’s membership.
Bruce Rew, SPP senior vice president of operations, has replaced Sugg as the SPC’s staff secretary. Sugg, meanwhile, joins the committee as a member, while Director Susan Certoma replaces Scherr.
The committee has also entered into an agreement with an outside consultant to help facilitate and guide its future discussions. Strategic Offsites Group, a boutique Boston-based firm, was selected last month.
“We’re at a point now, with the way things are changing in the industry; we need to give it a fresh shot of thinking,” Altenbaumer said.
“We do not prescribe answers. I feel you have plenty of expertise in the organization,” Cary Greene, a partner with the firm, told the SPC. “Our job is not to tell you to go left or right, but to have a process in place where you decide what the strategies are.”
Greene said he expects to have a final strategic plan put together for the board in April 2021.
A resource adequacy program that could eventually encompass eight Western states and two Canadian provinces is being planned by the Northwest Power Pool (NWPP) to ensure sufficient capacity at a time of increasing retirements and shifts toward renewable energy in the West.
The retirement of fossil fuel plants, especially those fired by coal, and the variability of wind and solar resources means a shortfall could be coming starting later this year, NWPP President Frank Afranji said in a webinar Friday.
The footprint of Northwest Power Pool, in blue, covers eight states and two Canadian provinces. | NWPP
“Soon, areas in the West may face a capacity deficit of thousands of megawatts. Deficits of that magnitude may result in both extraordinary price volatility and unacceptable loss of load,” Afranji said in his presentation to the online meeting, hosted by the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body.
More than 2,000 MW of coal generation in the Pacific Northwest will go offline by 2023, and another 1,500 MW will retire by 2029, Afranji said in a recent article. Only four new natural gas plants totaling 1,100 MW have come online in the Northwest since 2011, and battery storage for renewable resources hasn’t reached the point where it can replace traditional generation, he said.
“The conclusion is that the Northwest is on track to face capacity shortages as soon as 2020, with a capacity deficit of thousands of megawatts by the mid-2020s,” Afranji wrote.
“The scale of this challenge led a broad coalition of Northwest utilities to work together to find solutions,” Afranji said in a related web post.
Last year, NWPP issued a report titled “Exploring a Resource Adequacy Program for the Pacific Northwest.” It noted that resource planning is largely performed by states and utilities, using different standards and methods, and that, as a result, “the region lacks insight into its overall resource situation.”
After the report’s publication in October, NWPP and 18 of its member utilities moved forward to design an RA program intended to improve reliability and lower costs. Members funding the program’s design phase include Avista, BC Hydro, NV Energy, Portland General Electric, Seattle City Light and Tacoma Power.
“The plan is to start with the 18 entities that are currently funding the program, which will cover the majority of the NWPP footprint, and once the program is up and running, cooperate with others that may be interested to join,” Afranji said in an email to RTO Insider. “We strongly believe in building this program in building-block type fashion. Once we have the first building block in place successfully, others will be invited to join or may request to join.”
NWPP has a total of 34 members, including major utilities such as the Bonneville Power Administration, PacifiCorp and Xcel Energy, along with smaller public utility districts. Its footprint covers British Columbia, Alberta and all the states in the Western Interconnection except California, Arizona and New Mexico.
The RA program is in a preliminary design phase with more detailed design work scheduled for the second half of 2020. The effort to implement the program is scheduled to start in 2021.
As outlined in Friday’s presentation, the RA program would include a “forward showing” component, in which entities would have to demonstrate they meet capacity requirements months in advance, and an “operational” component for short-term resource sharing.
NWPP member Avista Utilities, formerly Washington Water Power, owns the Monroe Street hydroelectric plant in downtown Spokane. | Visit Spokane
NWPP planners have been studying the work of CAISO and SPP, which have their own RA programs, Afranji said.
The NWPP program would be unique because it wouldn’t operate as part of an RTO or ISO, but it could still fall under FERC jurisdiction if it includes binding agreements, planners said. It would be voluntary to join, but once a utility joins, it will be contractually committed to the program’s requirements, they said.
A public webinar on the proposed program is scheduled for April 24. The RA section of NWPP’s website features videos and other materials related to the program.
Capacity Shortfalls Ahead?
Concern about Western RA has been a recurring theme during the past year, based largely on the replacement of fossil fuel generation with renewable resources. The number of states and local jurisdictions passing carbon-reduction requirements continues to grow and now includes California, Nevada and Washington, which have 100% clean energy mandates by midcentury.
Some are worried the difference between those goals and existing capacity will lead to shortfalls. Price spikes in the Pacific Northwest last spring left many questioning the region’s RA. (See NW Price Spike a ‘Wake-up Call,’ Ex-BPA Chief Says.)
CAISO and the California Public Utilities Commission have said capacity shortfalls could arise as soon as this summer and worsen next year. The state’s policy goals of increasing reliance on renewable energy resources while phasing out natural gas plants is behind the potential problem, CAISO and CPUC officials said. The planned closure in 2024 and 2025 of the state’s last nuclear generating station, Pacific Gas and Electric’s Diablo Canyon Power Plant, could worsen the situation, they said. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)
In response, the CPUC ordered all load-serving entities under its oversight to collectively procure 3,300 MW of capacity, on a basis proportional to projected load, by August 2023. The CPUC voted in November to recommend that the State Water Resources Control Board allow four once-through-cooling gas plants built in the 1950s and 1960s to remain online even though they are the last of their kind and are slated to retire by the end of the year.
Concerns about a lack of coordination and oversight in Western markets have been raised in meetings of the Western Electric Coordinating Council. (See Western Reliability Margin is Thin, WECC Warns.)
A working group within WECC reported in February that the expected expansion of CAISO’s Western Energy Imbalance Market from a real-time only market to a day-ahead market will yield reliability benefits that could outweigh expected risks in the West. But those assurances haven’t done much to eliminate concerns. (See Study Gauges Reliability Benefits of EIM Day-ahead.)
WECC has an RA role, but it is more limited than that of the proposed program, NWPP said in its October report.
“Although both NERC and WECC publish information on resource adequacy planning, ensuring resource adequacy is the responsibility of utilities, state utility commissions, and other local and regional governing bodies,” it said.
Afranji said NWPP’s RA efforts will bolster WECC’s efforts.
“As to the WECC, this program will be complimentary to the RA activities they are engaged in,” he said. “The NWPP is part of WECC, and we have a great and symbiotic relation with them.”
The winter of 2019/20 saw PJM with the lowest peak loads of the last seven years, as temperatures 4 to 6 degrees Fahrenheit above the long-term average kept energy consumption down.
Executive Director of System Operations Paul McGlynn told the Operating Committee on Thursday that the highest peak load was on Dec. 19 at slightly over 120,000 MWh, 10,000 MWh below the next lowest peak during the winter of 2015/16.
LMPs were very low all winter, McGlynn said, coming in at an average of $21.31/MWh compared to the next lowest recent number of $26.16/MWh in 2015/16. LMPs exceeded $100/MWh for only three hours over the winter.
Top 10 winter peaks by year | PJM
For the fourth straight year, natural gas was the primary fuel for generation, with a 38% share, compared to 35% for nuclear, 19% for coal and 7% for renewables. Natural gas overtook nuclear in 2016/17 as the most utilized winter fuel. Gas also passed coal that year as the most utilized fuel during winter daily peak hours.
The relatively mild winter, with few major snowstorms, led to only 12 emergency procedure events during the season, McGlynn said, the lowest total in the last six years. By comparison, PJM saw 43 emergency procedures in 2014/15.
“From an operational perspective, it was a fairly unremarkable winter,” McGlynn said.
Review of Operating Metrics
PJM’s Stephanie Monzon reviewed March’s operating metrics, highlighting that the balancing authority area control error limit (BAAL) performance has exceeded the 99% goal each month in 2020 so far, at 99.9%.
The BAAL standard was created to maintain stable interconnection frequency under normal and abnormal conditions to prevent instability, unplanned tripping of load or generation, or uncontrolled separation or cascading outages.
PJM compares the BAAL excursions in minutes to the total minutes within a month.
Monthly BAAL performance score | PJM
Monzon also pointed out the perfect dispatch performance score through March 2020 was 94.81%. Perfect dispatch refers to the hypothetical least production cost commitment and dispatch, achievable only if all system conditions, including load forecast, unit availability and transmission outages, were known and controllable in advance.
The perfect dispatch performance goal was designed to measure how well PJM commits combustion turbines in real-time operations compared to the calculated optimal CT commitment profile. Monzon said the perfect dispatch score has resulted in more than $21 million in savings in 2020.
Monzon said March was a “rather quiet operational month,” with three post-contingency local load relief warnings, four high system voltages and one heavy load voltage schedule action. One spinning event was recorded on March 8, Monzon said, which took place in the Mid-Atlantic Dominion region, lasting a total of five minutes, with a Tier 1 estimate of 1,541.4 MW and an actual response of 660.1 MW.
System Operations Subcommittee Report
PJM’s Rebecca Carroll gave a summary of the most recent System Operations Subcommittee meeting held April 13. Carroll highlighted four high system voltage actions in March, which are typically seen during periods of low loads. PJM will likely continue to see similar events in the upcoming months because of the impacts from the COVID-19 pandemic and the stay-at-home orders, she said.
Carroll said all weeks of the 2020 Operator Seminar have been canceled because of the pandemic. She said if operators need training hours to renew their certification, they should reach out to PJM at TrainingSupport@pjm.com.
While most offices remain closed, Carroll said the PSI testing centers, which administer tests required for PJM training, will reopen about May 1. Masks and gloves will be allowed for anyone going into the training center, she said.
Load Forecast Model Performance
PJM’s Elizabeth Anastasio provided an educational presentation on the performance of the RTO’s neural network machine learning algorithms, which identify the relationship between historical loads and temperatures to create load forecasts. It also considers cloud cover, humidity and the “effective” temperature, a measure similar to wind chill that takes into account wind speed.
What makes a good forecast model, Anastasio said, is a relatively low average error and a bias near 0%. She said bias is calculated by taking the average of hourly errors of over- and under-forecasting to determine the proportion between the two.
Although no model can predict all conditions, accurate models also have relatively few outliers of significant forecasting errors, Anastasio said. She said the best models also don’t see clear trends with outliers occurring at the same time of year or day.
Anastasio said PJM forecasters are constantly trying to assess how to improve load forecasting by looking back at past data as well as current conditions, analyzing outliers and investigating other forecasting methodologies and machine learning.
More than 300 energy industry professionals logged into a single video chatroom through Zoom on Wednesday to hear about the latest issues in energy law.
And — besides a half-hour delay while keynote speaker Gina McCarthy attempted to join, and other minor hiccups — the Energy Bar Association’s effort to hold its annual meeting through the internet because of the COVID-19 pandemic was a remarkable success.
In addition to McCarthy, CEO of the Natural Resources Defense Council and former EPA administrator, the event featured six panels on topics including notable ongoing litigation, FERC’s proposed revisions to how it enforces the Public Utility Regulatory Policies Act and landowner challenges of pipeline certificates. Discussions played out as they normally would at EBA’s conferences, usually held at the Renaissance Hotel in downtown D.C., except that panelists spoke from their home offices, living rooms or kitchens. Sometimes, they forgot to unmute themselves before they began speaking.
Meanwhile, attendees commented on the discussions in the text chat sidebar, though this was often limited to remarking on speakers’ impressive libraries or their use of Zoom’s prerendered backgrounds.
NRECA CEO James Matheson addresses EBA annual meeting attendees, held through Zoom, in a panel on utility responses to the COVID-19 pandemic. Matheson is not seen because he joined the meeting by phone. EEI’s Emily Fisher moderated the panel. | EBA
The normally two-day event was compressed into one eight-hour marathon, made further compact by McCarthy’s delay and by shortening or even scrapping scheduled networking breaks, in which attendees were divided into separate, smaller chat rooms based on their sector or expertise.
The only breakdown in the meeting came during what is normally the luncheon awards presentation, in which members confirm incoming officers and board members by a ceremonial voice vote. In a physical setting, attendees need only pause between bites of their lunch to shout “aye” in response.
To replicate this experience, EBA attempted to unmute about 300 attendees simultaneously, wrongly assuming that everyone had returned from their lunch break and was paying attention. Robert Fleishman, presiding over the ceremony, was quickly drowned out as “a cacophony” — as one unknown attendee could be heard saying — flooded into the chat room: conversations, TVs, dogs barking.
Everyone was quickly muted again, and Fleishman asked if there were any “ayes.” Those that were paying attention to the proceeding unmuted themselves to respond.
“We don’t all speak with one voice clearly,” outgoing EBA President Jonathan Schneider said, laughing. “But on this election, I think we’ve got the message.”
At the end of the day, as EBA officials began breaking out the drinks to celebrate the meeting’s conclusion, many attendees voiced their appreciation, both through video and text, saying that it had brought some normalcy in a chaotic period.
Industry CEOs Laud Workers; Frustrated with Feds
After the awards ceremony, the CEOs of three major utility associations assured attendees that their members are working effectively despite the unique challenges posed by the pandemic.
Joy Ditto, APPA | EBA
Joy Ditto, Thomas Kuhn and James Matheson — the chief executives of the American Public Power Association, Edison Electric Institute and the National Rural Electric Cooperative Association, respectively — each said that reliability has not been impacted, despite extensive social distancing measures taken by line workers and a shortage of personal protective equipment (PPE). And each praised these workers as “real heroes,” asking attendees to keep them in their thoughts along with other essential workers.
Kuhn noted the severe weather over the Easter weekend on the East Coast, with tornadoes in the Southeastern U.S. and an ice storm in Maine.
“We had to figure out a new way to do business with respect to the pandemic,” Kuhn said. “We had to assemble crews” but keep one person per truck. Rather than house crews in trailers sitting in parking lots, “we had to find separate rooms in separate areas so we could operate.”
“But we did a fantastic job. This sector … is used to dealing with disasters and coming together and adapting,” he said. “I think we start way, way ahead of every other industry.”
Ditto also reported that mutual aid was occurring between APPA members as well as with EEI and NRECA members. She said an outbreak of tornadoes in Tennessee in early March, just before widespread economic shutdowns began in response to the pandemic, provided an early opportunity for utilities to learn how to work together while following social distancing and hygiene guidelines. The lessons learned during this event were implemented successfully when another tornado shredded Jonesboro, Ark., later that month, she said.
“Given the panoply of issues we face on a daily basis, we still had to learn some things as we’ve gone along in response to COVID-19,” Ditto said. But “the response is occurring. The mutual aid is happening.”
“To watch the participation across the different” utilities — investor-owned, municipal and cooperatives — was heartening, Matheson said. “Mutual assistance is one of the best calling cards we got in terms of how we’re committed to keeping the lights on.”
But, all three expressed frustration over shortages of PPE and testing.
Kuhn said EEI was having calls twice daily with the Department of Homeland Security, the Department of Energy and the White House, “but we weren’t able to break through” to them. “We were essentially behind the health care industry — which was obviously appropriate, because they were on the front lines — but what it meant to us was we were not getting the PPEs and not getting the testing.”
Finally, EEI was able to get in touch with the assistant secretary for health, Adm. Brian Giroir, whom Kuhn said understood the situation. “So that’s begun to break, and it’s been terrific,” he said, adding much more will be needed in time for summer.
“This is reflective of a broader national problem, and that’s not the topic of discussion today,” Matheson said. “But, you know, we’re behind on test kits — one could argue we should have been cranking up production test kits a long time ago — so we have a shortage of nationwide kits anyway.
“And for our sector, it becomes really important when you talk about certain critical employees. If you really want to keep the power plants running and keep the right people in the control rooms, you can’t just take someone from one power plant and stick them over in another one to replace someone who got sick,” he continued. “There are unique dynamics to every control room and every power plant. So it’s really important for these key employees that we have the capacity to … be able to test them on a regular basis.
“It seems pretty straightforward, but this has been a point of, quite candidly, frustration in terms of getting appropriate access to testing kits,” he said. “I think things are moving in a better direction, but I don’t want to say this issue’s resolved. This is still a big concern for my membership.”
Ditto echoed Kuhn’s and Matheson’s frustrations, but she added that utilities are getting creative with social distancing to ensure “that the most critical workers can continue to work even without testing.”
Several public utilities, including APPA member New York Power Authority, have sequestered their workers in control rooms in 30-day shifts, she said. In other cases, APPA has provided mobile homes for workers to live in. So far, workers have been receptive to the measures, as it protects their families and the public, she said.
“But it’s not ideal,” Ditto said. “It certainly puts more risk on our system than we’d like to bear and surely that the American public would like to bear.”
Matheson said that although he is not aware of any co-ops sequestering, some have gone as far as buying laundry machines just in case.
Financial Concerns Linger
The three CEOs also expressed their worries about the future viability of their members, who have pledged not to charge late fees or disconnect customers for nonpayment — or been barred from doing so by their states’ governors. All are lobbying Congress for long-term support in the inevitable future stimulus packages passed in response to the pandemic.
In the short term, the CEOs said, the focus has been on customers, many of whom are out of work and in desperate need of cash. Kuhn said that for the CARES Act, EEI pushed for increased funding in the Low Income Home Energy Assistance Program, which ended up getting $900 million.
Gina McCarthy, NRDC | EBA
As publicly owned utilities, APPA and NRECA members must return any surplus funds to ratepayers.
“A number of our members have adopted a policy to accelerate the return of revenue back to consumers … to get money into people’s pockets more quickly than would have otherwise happened,” Matheson said.
But the combination of nonpayments and lack of commercial and industrial demand “creates an economic hardship across the utility sector,” he said. “As the next stimulus package moves through Congress, it’s a sector that merits some attention. … In our case, this is about keeping the lights on, and I think it’s a pretty compelling argument.”
But Matheson also said that even before the pandemic, he had been flustered by a lack of funds from the Federal Emergency Management Agency. Despite having approved cost reimbursement for storms in 2018, “FEMA has never given them the money,” Matheson said. “Those are co-ops that are holding all that expense they did for storm repair on a line of credit and are paying interest on it now. And if they were able to receive their already-approved FEMA reimbursement, that would certainly be a benefit for them” getting through the pandemic.
Ditto said APPA is considering asking for short-term “bridge loans to enable some of our members to get past this squeeze.”
A Post-pandemic Future
The CEOs were asked how they thought the energy industry would change once the U.S. gets through the pandemic and things return to normal.
Matheson said that businesses may realize it is more cost effective for their employees to work from home, at least for part of the work week.
Jonathan Schneider, EBA | EBA
But he and Ditto noted that the pandemic has highlighted that many of their customers still lack access to broadband internet. They both hoped that the crisis would spur federal investment in broadband infrastructure in the rural U.S.
All three CEOs agreed that, at least in the short term, investment in clean energy resources would pause.
When society does start to go back to normal, Ditto concluded, “I’m very optimistic that we can … go back to work while still ensuring that we stay healthy. I think if we just do it systematically, we’re going to be OK.”
Kuhn said that many are noticing that the air has been cleaner since they began sheltering in place. He speculated that this may accelerate electrification of the transportation sector.
NRDC’s McCarthy also mentioned the reduced emissions in her keynote speech. She said that cable news show hosts always note the substantial reduction in emissions as a result of the pandemic when she’s a guest. “They turn it over to me and seem to think I’m going to go, ‘Wow, isn’t this great?’” she said incredulously. “That’s not how I want to succeed!”
But, she said, “maybe these times are giving us a sense of the importance of science.”
PJM backed off plans to seek a vote next month on short-term changes to its five-minute dispatch and pricing procedures after pushback from the Independent Market Monitor and stakeholders.
PJM’s Tim Horger told the Market Implementation Committee on Wednesday that the RTO was prepared to make manual changes detailing short-term changes but needs more time to evaluate the operational benefits and impacts of long-term changes it has been discussing with the Monitor.
PJM’s proposed short-term fixes would align the locational price calculator (LPC) to use the reference real-time security-constrained economic dispatch (RT SCED) case for the same target time. LPC would calculate prices for the interval from 11:55 a.m. to 12 using the RT SCED solution for a 12 p.m. target time.
Proposed short-term implementation | PJM
The RTO would execute LPC cases every five minutes after the start of a dispatch interval, using as inputs resource offers, parameters and ancillary service assignments for the interval ending at the target dispatch time. Offers for 11 to 12 would be effective up to and including the 12 p.m. target; offers for 12 to 1 p.m. would be applied to a dispatch target of 12:05.
Horger said PJM also has committed to conduct operator training and make software changes to limit automatic execution of RT SCED cases to once for every five-minute target time. Additional cases may be manually executed and approved as needed by dispatchers under what PJM calls this “intermediate” change.
The long-term changes would include auto-execution of RT SCED cases every five minutes with a target time of 10 minutes into the future.
If dispatchers do not manually approve an RT SCED case for a target time, a case would be automatically approved before the start of the dispatch interval. It would also add transparency when cases are not approved for a target time because of data errors or software failures.
Horger said PJM wants to prioritize and consider parallel or incremental implementation of the long-term changes. “It might look good on paper, but until we get a comfort level on an operational level, we can’t commit to it.”
IMM Joe Bowring said the Monitor thought it had reached an agreement with PJM following “months of productive discussions” on a compromise that would give dispatchers better information closer to the dispatch time and help ensure consistency between dispatch and pricing.
But he said the RTO posted a presentation and a proposal matrix the night before the meeting that indicated the RTO no longer supported the agreement. The RTO’s current long-term proposal “is vague at best and probably years away,” he said.
In addition to aligning pricing and dispatch, Bowring said in an email later, it also is essential to reduce “the RT SCED dispatch interval from 10 minutes to five minutes, running RT SCED on a regular five-minute interval to match the pricing interval to minimize running multiple RT SCED cases and changing dispatch instructions for the same target time, and using the prior RT SCED case as inputs to the current RT SCED case.”
“Our goal continues to be a single comprehensive package,” he said at the meeting. “We believe the entire package is needed to make SCED and LPC work consistent with the FERC order … and it’s really required for fast-start pricing to work correctly.”
“This is something were going to need to test. It requires operator training,” responded Horger. “It won’t be years away. It will be a lot closer than that.”
PJM says the long-term changes may require a revised approach to ancillary service products.
“If we slow down the dispatch, [our concern is] what other compensating measures we [might] need to take,” explained Adam Keech, PJM vice president of market services. “Do we need more regulation if we slow down the dispatch? Sitting here today, I don’t know that we know the answer to that.”
Bowring noted that PJM recently changed the automated case execution for SCED from three to four minutes without operator training. “I don’t know why training is needed to go from four to five minutes,” he said.
Keech said the RTO believes the intermediate and long-term changes aren’t required by the FERC order because they are not used “uniformly” in other RTOs/ISOs. He acknowledged that the recent change in the automated SCED case execution from three to four minutes has not caused any operational issues.
But he said that shift still allowed dispatchers to manually order additional cases in response to changing conditions. Preventing dispatchers from such manual intervention “is much different than where we are today,” he said. “TBD on an exact timeline, but I will say there is motivation to make the change quickly, but I will add, judiciously.”
Keech also said PJM’s long-term goal is to greatly reduce dispatchers’ interventions while retaining operators’ ability to approve SCED cases if, for example, they unexpectedly lose a large generating unit. “The desire is not to [intervene] unless it’s absolutely necessary.”
He said about one-third of approved RT SCED cases do not set prices currently because they are supplanted by new cases.
One stakeholder representing a trading firm who said he was not permitted by his company to be quoted by name said PJM’s current practices are preventing proper transient shortage pricing even when the system is in a “critical state.”
He cited a spinning reserve event in February that resulted from an under-forecast for load, an incident in October in which load rose faster than forecast and a July 2018 time error correction at noon and subsequent unit trips that resulted in a drop in system frequency on the Eastern Interconnection.
MIC Chair Lisa Morelli concluded the discussion by saying the committee will hold a second first read of the proposal in May. “I think it’s pretty apparent we’re not ready to move this to a vote at the next meeting,” she said.
In the interim, the MIC will hold a special meeting on the issue May 1.
Horger said that because the short-term changes only affect the manual and do not require FERC approval, the delay should not prevent the RTO from making the changes by July as planned.
PJM told the Planning Committee on April 14 that it is standing behind its intention to seek stakeholder approval of a new regional targeted market efficiency project (RTMEP) process without first developing cost allocation rules.
LS Power’s Sharon Segner acknowledged that cost allocation is the TOs’ responsibility, but she said FERC Order 1000 requires any regional planning process to be accompanied by a cost allocation methodology. Segner reviewed a legal memo filed by LS Power regarding cost allocation for the new project category.
Foley said she agreed with LS Power’s contention on the importance to know the cost allocation methodology before PJM designates a project or implements a planning process. But she disagreed with the memo’s contention that a methodology must be simultaneously filed with the planning process. “I don’t see anything in Order 1000 that says that,” she said.
PJM officials noted that stakeholders have been working on the issue for at least 18 months and said that if it’s pushed back any further, it could prevent implementation before 2022. PJM stated it is prepared to seek a vote on a new measure at the May PC meeting.
Alex Stern of Public Service Electric and Gas provided a response from the TOs regarding the LS Power memo. He said the plans that have been proposed follow existing transmission planning principles and comply with Order 1000.
“Once we have an effective [stakeholder-approved] package, the TOs will begin developing any needed cost allocation revisions that emerge,” Stern said. “This is consistent with the transmission planning approach that has been followed in the past.”
Segner said there remains a “long path ahead” on the RTMEP process for stakeholders. She said there has been no consensus on the proposals submitted thus far.
“The members deserve to know the cost allocation methodology for an entirely new type of regionally planned project category,” Segner said. “If FERC can’t accept these filings without understanding what the cost allocation methodology is going to be, why should the members? Why is it that the members are considering approving changes without knowing what the cost allocation framework is going to be?”
Competitive Planner Nears Debut
Ilyana Dropkin of PJM presented an update on the Competitive Planner, a new web-based application for TOs and developers to participate in the RTO’s competitive planning process under Order 1000.
By publishing a set of criteria violations and soliciting solutions from competing developers in the new application, Dropkin said, PJM and FERC are hoping to encourage innovative and cost-effective solutions for transmission needs.
Dropkin said that having a web-based application increases the speed and accuracy of the process and provides near-real-time tracking of submissions.
Anyone looking to participate in PJM’s competitive planning process can get access to Competitive Planner by prequalifying through the critical energy/electric infrastructure information (CEII) process, Dropkin said.
Training for the application is expected to be available on May 6, Dropkin said, and the full implementation of Competitive Planner is expected by June 24.
Transmission Expansion Advisory Committee
Deactivation Notifications
Phil Yum of PJM provided the Transmission Expansion Advisory Committee an update on two recent generation deactivation notifications.
The first highlighted was PPL’s Keystone NUG, a 4.9-MW coal-fired unit scheduled to retire on May 31. Yum said PJM determined during analysis that no violation was identified with the unit’s closure.
Generation deactivations for 2018-2020 | PJM
Second, Chesterfield Units 5 and 6, producing 1,015 MW in the Dominion zone, are scheduled to retire on May 31, 2023. Yum said a generation deliverability problem was discovered at the Chickahominy 500/230-kV transformer that was overloaded for loss of the Chickahominy-Surry 500-kV line.
Yum said PJM is recommending installing a second Chickahominy 500/230-kV transformer at an estimated cost of $22 million.
PJM: Error had no Impact on Project Selection
PJM’s Brian Chmielewski told the TEAC that FirstEnergy’s admission that it included an incorrect winter-normal rating in its proposed rebuild of the 115-kV Hunterstown-Lincoln line did not affect the RTO’s selection of the project (HL_622).
PJM selected the $7 million proposal by FirstEnergy’s Mid-Atlantic Interstate Transmission (MAIT) subsidiary as the solution for the Hunterstown-Lincoln congestion driver following the 2018/19 long-term window.
After MAIT told PJM of the error on March 6, the RTO’s market efficiency unit reran the proposal with the updated rating, Chmielewski said. “There was no change to the congestion or dispatch when that rating was updated,” he said, adding that PJM stands by its decision.
In February, Ameren asked PJM to reconsider its selection of the project over 22 other proposals, including the company’s proposal for installing a SmartWires SmartValve. (See PJM Rejects Ameren Challenge on Tx Project.)
RTEP Window Delayed
PJM’s Aaron Berner said delays in the development of Regional Transmission Expansion Plan cases have pushed its schedule back by three weeks. Posting of preliminary violations, originally targeted for April 15, is now expected on May 8. The opening of the 60-day proposal window, originally expected June 1, is now set for June 24.
Supplemental Project
Paul Mills of Commonwealth Edison presented needs and a solution for several supplemental projects, including the Lisle 345/138-kV Transformer No. 83 that acoustic testing showed higher-than-expected vibration levels and increased frequencies associated with looseness in the core/coil assembly. The solution calls for replacing the transformer and adding a high-side circuit breaker at a cost of $8.5 million.
While PJM’s controversial initiative to tighten fuel requirements for black start resources is on pause, the RTO said last week it wants to clarify and update its documentation on the substitution and termination of those resources.
PJM’s David Kimmel presented a first read of a proposed problem statement and issue charge at the Operating Committee meeting Thursday, saying PJM officials have identified four areas in the Tariff and manuals in need of updates.
Last month, PJM suspended its initiative looking at black start fuel requirements, which faced opposition from state regulators and consumer advocates. (See PJM Backs off Black Start Fuel Rule.)
Kimmel said while the fuel requirements initiative remains on “hiatus,” the RTO wanted to clean up black start resource language in the Tariff not related to fuel.
“We have received a lot of questions on substitution, and we wanted to make those rules more clear,” Kimmel said.
PJM is first rewriting language for testing requirements for black start resources not compensated through Schedule 6A of the Tariff. Kimmel said PJM has identified the need to provide clarity within testing requirements to ensure consistency, including test submittal timelines, for black start units compensated by either PJM or transmission owners.
Tasley, a single-unit 33 MW industrial gas turbine that began commercial operation in 1972 in Tasley, Va., is a black start capable unit. Calpine acquired Tasley in 2010 as part of its purchase of the Conectiv Energy assets. | Calpine
Kimmel said the black start units in PJM are typically compensated through Schedule 6A, while some units entered service through a contract with a TO that was integrated into the system. In order to receive compensation, the unit must submit a successful black start test to PJM every 13 months.
The second clarification PJM is seeking is on black start unit substitution rules. Currently the Tariff allows a black start unit owner to substitute another unit as long as it’s on the same voltage level and has a valid annual black start test.
Kimmel said PJM has received increased questions on adding, maintaining and managing units as black start substitutes. He said some of the questions that have been raised include the notification time required to allow a substitution and how to manage updates to system restoration plans documenting black start resources.
Black start termination rules are also being addressed, Kimmel said, to address potential delays in planning and replacement.
PJM and black start unit owners are currently required to provide a one-year advance notice of intent to terminate service. Kimmel said that could allow a unit to remain in the system without a successful test on file for an extended period of time before being terminated, delaying PJM from procuring a replacement.
The RTO also is looking to update the black start capital recovery factor (CRF) table in the Tariff to reflect current tax law and interest rates. It also is exploring a new process for automatically updating and documenting the table to remain current.
Kimmel said black start units electing to recover new or additional capital costs must commit to provide black start service for a term based on the age of the unit, and the CRF table lists the term periods of commitment and applicable capital cost recovery factors. He said recent tax law and interest rate changes don’t reflect the assumptions used in the current CRF and need to be updated.
Work on the proposed changes is expected to take two to three months, Kimmel said, and it could be another six months before the changes would take effect in the Tariff. Changes are also anticipated to Manuals 10, 12 and 14D.
Process Questions
Independent Market Monitor Joe Bowring said he agreed with PJM’s proposal that the CFR table needs to be modified for tax law changes. He recommended that a reference interest rate be used as part of the problem statement and issue charge for the new changes and that the Moody’s Utility Index for bonds already in use in the Tariff for black start-related matters be the benchmark.
Bowring also said he would also like to see the black start minimum tank suction level (MTSL) issue addressed in the new changes. He said the MTSL has been an issue for several years that has not been clearly addressed. PJM had agreed with the Monitor’s position and had included such an agreement in the black start fuel requirement initiative that is now on hiatus, he noted. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: May 1, 2018.)
PJM’s Tom Hauske said the MTSL is still part of an active stakeholder process with the fuel resource initiative and should remain there.
“We’re not sure that you can pull something from one stakeholder process and then bring it over into a whole other stakeholder process,” Hauske said.
Bowring said he didn’t see why the MTSL issue couldn’t be addressed in the new process, as the fuel cost committee is currently on hiatus. Bowring also pointed out that the CRF table was part of the fuel assurance matrix being discussed in the black start fuel requirement.
Hauske said the previous fuel assurance matrix discussion dealt only for new units that were going to provide fuel assurance and did not apply to current units that were switching to black start, which is what the new proposed changes are meant to answer.
