MISO’s Advisory Committee is beginning work on a possible new process for prospective members to join the RTO.
The AC is considering whether the newly formed Affiliate sector will serve as an “incubator” for designing new sectors that will allow a more diverse set of companies and organizations to join MISO. The committee plans to examine how the Competitive Transmission Developer sector was formed in 2014.
MISO’s Board of Directors last month cleared the AC to create an 11th sector while instructing the committee’s to come up with a longer-term solution that guarantees members full participation in the stakeholder process. The new sector serves as a home for any member that isn’t participating in another sector, but it lacks voting power in the AC and the Planning Advisory Committee. Prospective members must declare a sector affiliation before they can join the RTO. (See Board OKs 11th MISO Sector, Orders Redesign.)
The AC will consider whether sectors should develop charters and bylaws, and how it will divvy up voting rights among new — and possibly even existing — sectors. The committee votes by sector when it decides to send recommendations to the board.
“The voting in my view is the most sensitive and possibly even contentious issue,” AC Chair Audrey Penner said.
The AC has a year from late March to draft a solution.
AC Hears LMR Saturation Concerns
The AC also briefly touched on a conversation brewing in the Reliability Subcommittee about how to set limits for load-modifying resources participating in MISO’s markets.
Some stakeholders have expressed concern about an overreliance on LMRs and are seeking analysis exploring the potential for oversaturation in the footprint. (See MISO Group to Probe LMR Saturation.)
RSC Chair Bill SeDoris said the subcommittee is asking whether there should be a limit on how many LMRs can clear in the capacity auction — or even in the day-ahead market.
“Are we there with demand response, LMRs and distributed resources?” SeDoris asked rhetorically. “Do we have enough steel in the ground generating electricity?”
Eligible End-User Customers sector representative Kevin Murray said LMRs are essential because they’re designed to be the first load in line to be interrupted during emergencies.
“Are we making sure we have the right resource mix to maintain the system reliability? Load can be cut, but the system’s designed to keep the lights on,” SeDoris said.
Stakeholders in the Resource Adequacy Subcommittee have since voted to formally oppose the LMR filing.
Murray called the accreditation proposal “arbitrary.”
SeDoris said he can’t tell if the leaner accreditation will cause some LMRs to walk away from the MISO capacity market. “I’m working under the assumption that the LMRs will adapt to the changing rules.”
North Dakota Public Service Commissioner Julie Fedorchak pointed out that state regulators consider the effectiveness of LMRs when appraising their utilities’ integrated resource plans.
The RSC will continue to discuss the upper limits of LMR participation in its upcoming meetings.
The New York State Energy Research and Development Authority was authorized Thursday to solicit up to 2,500 MW of offshore wind energy this year — the largest such procurement in the country to date.
The New York Public Service Commission granted NYSERDA’s January petition to solicit “at least” 1,000 MW of offshore wind energy in 2020 and be granted the “flexibility” to evaluate a range of bids for up to 2,500 MW (18-E-0071).
“This is an important step forward to advance the opportunity for New York state’s next offshore wind solicitation,” PSC Chair John B. Rhodes said. “We received important inputs in the recently concluded comment period, and this order properly considers those, as well as the principal aspects of the public interest.”
Environmentalists and labor groups were quick to laud the state’s action.
“The PSC order will help ensure that New York is able to take maximum advantage of expiring federal tax credits, limited offshore lease areas and the developing offshore wind supply chain,” New York Offshore Wind Alliance Director Joe Martens said in a statement.
NYSERDA 2019 OSW contract awards, lease and project areas, and proposed points of interest | NYSERDA
Gary LaBarbera, president of the Building and Construction Trades Council of Greater New York, said the decision “paves the way for thousands of good jobs and billions in economic development for New York. We applaud this order and look forward to building New York’s offshore wind industry for years to come.”
Following the commission’s decision, NYSERDA said in a statement that it would not be rushing amid the coronavirus pandemic to put out a request for proposals.
“While NYSERDA fully supports and is poised to execute on this authorization, given the current circumstances, we feel issuing a near-term solicitation would not be responsible nor advisable. … Given the dynamic nature of the situation, NYSERDA is closely monitoring the crisis and stands ready to launch the solicitations when the associated activities can responsibly begin,” the agency said.
Gov. Andrew Cuomo in January announced that NYSERDA would solicit at least 1 GW of offshore wind energy this year. The state last July awarded offshore wind contracts to Equinor’s 816-MW Empire Wind project and to the 880-MW Sunrise Wind, a joint venture of Ørsted and Eversource Energy. (See Cuomo Sets New York’s Green Goals for 2020.)
Among other targets, New York’s Climate Leadership and Community Protection Act (A8429), signed into law last July, nearly quadrupled the state’s offshore wind goals to 9,000 MW by 2030.
Burman Dissents
All five PSC commissioners met via teleconference for its regular monthly session in Albany; only one voted against the offshore wind order.
Commissioner Diane Burman said “that while we are looking to give direction and regulatory certainty to NYSERDA and to those involved in offshore wind, and giving a nod that we are supportive of moving forward in 2020 on an offshore wind solicitation,” she was concerned that the funding of NYSERDA “fails to set conditions on the authorization.”
Burman said that as “stewards of the ratepayer dollars and stewards of the state’s environmental goals,” commissioners “need appropriate information in real time to make those decisions, not in a vacuum; not crossing our fingers and hoping it all works out.”
“We have at times looked at modifying a petition, or asking those petitioners to provide more information,” Burman said. She said it was reasonable to seek “more clarity and information” as “the comments on the petition only came in this week.”
Burman said there are “significant under-the-hood issues. … Commenters repeatedly discuss the transmission study … and yet many times we are left not necessarily having those studies completed in time to inform our decisions.”
“I’m struck by how we’re not demanding real information from NYSERDA,” she said. “I’m not opposed to giving authority, but I am opposed to being kept in the dark from the beginning.”
Burman also noted the concerns raised this week by the Long Island Commercial Fishing Association (LICFA), which as a member of NYSERDA’s Fisheries Technical Working Group (F-TWG) requested an extension of the April 20 deadline to submit comments.
“Though an email was sent on Jan. 30 notifying the F-TWG members of NYSERDA’s petition, no email chain, meeting or webinar was conducted by NYSERDA to discuss the proposal specifically, and as such, none of the fisheries stakeholders from multiple states who fish in the Atlantic from the Mid-Atlantic New York Bight area off of New Jersey to the Southern New England/South of Massachusetts waters have had the opportunity to address or comment as a group on this issue,” LICFA said.
Burman said the order doesn’t properly address the fishermen’s concerns “but says they should not have waited so long, which is not the appropriate approach for a regulator. … We should be seeking how to incorporate their concerns on the front end.”
MISO’s Steering Committee is debating whether to propose a new rule that would require consultants to identify the clients they represent when participating in stakeholder meetings.
A number of stakeholders have pressed for the rule, but the Planning Advisory Committee has reported that some consultants are reluctant to reveal their clients before offering comments or criticisms on MISO presentations. (See “SC Mulls Consultant Transparency,” MISO Steering Committee Briefs: Feb. 19, 2020.)
The Steering Committee again took up the issue during a Wednesday teleconference.
“This is not an issue that I’m personally raising; I’m raising it on behalf of several stakeholders,” said PAC Chair Cynthia Crane, of ITC Holdings.
“This is beyond simple courtesy. It’s so we can understand the perspective of the requests being made,” Crane said. “These consultants are making significant requests of MISO staff to change analyses and processes. … Other stakeholders can’t identify the driver of comments being made, and essentially those remarks are being made in a vacuum.”
The PAC currently requests that all meeting attendees first identify themselves and companies they represent before speaking — a request that is not always followed.
“There are a whole range of vested interests in the PAC. And some are asking to change the inputs to planning analyses. And when you change the inputs, you change the outcome,” Crane said. “This is a very specific example of why this matters.”
“We all hammer MISO for transparency. And I guess I’ll say turnabout’s fair play,” Reliability Subcommittee Vice Chair Ray McCausland, of Ameren, said at the subcommittee’s Feb. 27 meeting.
Some stakeholders have pointed out that MISO has a loose definition of “stakeholder”: anyone with an interest in the RTO’s workings. Customized Energy Solutions’ David Sapper asked how MISO could require individuals to state affiliations when stakeholder meetings are open to “all interested participants,” according to the RTO’s Stakeholder Governance Guide.
However, the Organization of MISO States (OMS) argued the guide should be revised with the expectation that all meeting participants be prepared to announce their affiliation.
“To foster openness and transparency, the MISO Stakeholder Governance Guide should be amended to add language that defines a set of expectations for stakeholder identification in the stakeholder process,” OMS said in comments to the RTO. “These revisions should include details addressing how consultants identify who they represent when participating in any MISO meeting or process. When consultants fail to disclose this information, it puts other stakeholders and the entire stakeholder process at an informational disadvantage and does not foster a fair and level playing field.”
OMS said its members frequently announce in meetings whether they’re offering their personal opinion or the view of their states.
“Some consultants currently do effectively communicate their affiliation(s) during a wide range of stakeholder proceedings, and the OMS believes that applying a consistent rule requiring all consultants to identify their clients would not be unnecessarily burdensome,” OMS said.
Finding the Balance
But Advisory Committee Chair Audrey Penner, of Manitoba Hydro, said she wasn’t sure how far stakeholders can go in insisting that consultants divulge the identities of clients given the “stakeholder” definition and the fact that consultants can maintain that they’re sharing their personal views, not those of the company they represent.
Some stakeholders have raised the issue of consultants executing nondisclosure agreements with clients. Crane said in those situations, consultants could still announce the sector affiliation of their clients. Others have said that any new identification rule shouldn’t have a chilling effect on open discussion in meetings.
“I don’t want this to become so restrictive that good ideas are stifled out,” said Resource Adequacy Subcommittee Chair Chris Plante, of Wisconsin Public Service. He reminded other committee chairs that they can always step in to prevent a stakeholder from dominating a conversation. He also said that most consultants already notify attendees of their affiliation before making comments.
“If we’re getting someone with lots and lots of pushback, it would be nice to know who they represent to determine whether they have standing as a stakeholder — whatever that means,” MISO Director of Planning Jeff Webb said.
As an independent entity, MISO applies its own discretion in taking stakeholder suggestions, no matter the source, he said. “I think we can live with it either way. We have for a long time already.”
“I feel it would be easier for us in the stakeholder process if we knew from what perspective comments are coming from,” Clean Grid Alliance’s Natalie McIntire said.
FERC’s controversial MOPR ruling, the troubles of the petroleum industry and ways to continue manufacturing electric buses were topics of a webinar hosted by the California Energy Commission on Tuesday called “Weathering the COVID Crisis.”
The CEC, which dispenses hundreds of millions of dollars in grants for clean-energy innovation, brought together leaders in electric vehicles, rooftop solar and utility-scale solar to talk about how they were coping with the effects of the pandemic.
CEC Vice Chair Janea Scott, who heads the commission’s research and development programs, said the CEC is taking care of critical business as usual even though most of its employees are working from home.
“We recognize the importance of continuing to invest in our clean energy entrepreneurs, and we are actively preparing to release new solicitations,” Scott said. “In fact, in the R&D team, we anticipate releasing seven solicitations that would make about $150 million available over the next few months.”
The CEC is also supporting its current grant recipients, she said.
“We recognize that people may not be able to get into a lab to do the testing,” Scott said. “We recognize that folks aren’t necessarily able to do wet signatures and things like that.”
The commission is extending due dates and working with the Legislature to make relief funds available, she said.
“Please know that the Energy Commission is a resource for you to reach out to anytime,” she told the 350 people on the webinar, which was co-hosted by New Energy Nexus, a nonprofit that supports green-energy entrepreneurs.
Building Buses
Ryan Popple, executive director of Proterra, the largest North American manufacturer of electric buses, described his company’s efforts to fill orders while protecting workers.
Ryan Popple | Proterra
Electric buses have been one of the fastest growth sectors for EVs and could be the first to fully electrify, Popple said. While airports and some cities have cancelled orders, most cities “still want their electric buses,” and the company has an 18-month order backlog to fill, he said.
“Cities are still thinking long-term about their zero emission and electrify-everything strategies,” Popple said.
The company has three factories in South Carolina and California. In each jurisdiction, he said, “we were informed that public transit vehicles are essential, and if we can keep building, we should.”
The company has been enforcing physical distancing on the factory floor, providing coveralls and masks, and checking workers’ temperatures before they enter the building, Popple said. He urged other businesses to strictly follow government policies.
“We don’t have any practices that don’t line up line-for-line with guidance from [states, the federal government and the United Nation’s World Health Organization],” he said. “We make sure we are 100% compliant and up to date with the science behind [the official policies].”
Popple said he doesn’t think the world will go back to normal, at least until a vaccine or therapy lessens the threat from the COVID-19 virus, “but we’ve got to get back to work in the safest way possible.”
Electric bus | Proterra
He said he thinks the U.S. will adapt to COVID-19 the way other countries have dealt with malaria as a persistent threat — for instance, using face masks the way some countries use mosquito netting as a preventative measure.
“If we’re going to get people paid and get the economy recovered, we’re going to have to do that,” he said.
End Game for Fossil Fuels?
Popple also talked about the current crisis in the oil industry, where futures prices fell below zero this week.
“We’ve got to take very seriously that the fossil-fuel industry is backed into a corner right now. And my grandfather, who was an Illinois state trooper, told me, ‘Don’t ever back anybody into a corner because the only way they can get out is through you.”
Despite mounting evidence that vehicle pollution contributes to COVID-19 deaths, he said, the fossil fuel industry will try to roll back electric-vehicle mandates in California and elsewhere.
“If you’re faced with losing a multi-trillion-dollar industry, you’re going to take any shot you can get.”
“I think we are seeing the end game for fossil fuels. We’re seeing a preview of it,” Popple said. “So, don’t be surprised if a policy that was already implemented, that positively affected your business [comes under attack]. You better be prepared to defend it.”
Solar Survival
Lynn Jurich, CEO of Sunrun, a major rooftop solar firm, gave a pep talk of sorts to the green-energy industry.
She said she and her co-founders started Sunrun when they were students at Stanford in 2007 and racked up expenses fast, counting on millions of dollars in financing to bail them out. Then the recession hit in 2008, and the banks that the entrepreneurs thought they had deals with backed out – all except one.
Lynn Jurich | Sunrun
That one bank loaned them the $40 million they needed, and they were able to get a jump on the competition during the downturn, Jurich said.
“Sometimes these crises can be a benefit for entrepreneurs and people who can get through to the other side,” she said. “In many ways, that gave us a head start because we were able to weather this really tough period. So, from a business standpoint it was harder for other new entrants to raise capital and copy [our] model. We got a little bit lucky.”
Jurich said the recession that began in 2008 taught Sunrun to make sure it had plenty of cash on hand and to maintain good relationships with lenders.
“We’re like Depression babies,” she said. “We’ve been conservative about planning for a rainy day.”
In the current situation, Jurich said, “I’m really optimistic we’re going to come out of this as a stronger industry.”
Rooftop solar is too expensive and permitting too difficult, she said. Firms should use the coronavirus crisis as a way to spur innovation and accelerate cost reductions.
“Consumers want this product more than ever,” Jurich said. “They feel let down by institutions in many ways and want to take matters into their own hands.”
The rooftop solar industry relies on face-to-face sales but needs to turn to e-commerce and become more efficient, she said.
“I think this crisis is going to accelerate this industry by one or two years,” she said.
Jurich said she wasn’t denying the difficulty of these times, but “I’m really optimistic that it’s going to force a lot of the discipline that we need to really put the solar and batteries on all infrastructure and decarbonize the energy business quickly. Time is essential, as we all know.”
‘Under Direct Attack’
Dan Shugar, founder and CEO of NEXTracker, is a veteran of the utility-scale solar industry, the biggest driver of California’s growth in renewable power.
The CEC has been a leader in promoting clean energy “in stark contrast to what’s happening on the federal side,” Shugar said. “Every one of the companies on this call is under direct attack from the Trump administration, and so we have to respond.”
The administration’s new tariffs on solar panels and its attack on net-metering, key to rooftop solar, are two examples, he said.
Dan Shugar | NEXTracker
“FERC also had an extremely alarming ruling in the PJM regional transmission operator territory, which serves 65 million customers,” Shugar said, referring to the commission’s order applying the minimum offer price rule (MOPR) to all new state-subsidized resources. “It impacts $10 billion of economic value that’s traded for capacity in the Northeast. Essentially what they’re doing is subsidizing coal and nuclear at the expense of renewables.” (See related story, Stakeholders Appeal Expansion of PJM MOPR.)
The motivation isn’t to save consumers’ money, he said. Wind, solar and electrical vehicles have created more than 2 million jobs. Power from wind and solar now costs significantly less than natural gas, coal or nuclear power, he said.
Shugar urged his colleagues to fight back.
“We have the opportunity to win at everything — create jobs, help the environment and create value for our economy,” he said. “You must engage [politically] this year more than ever. It’s really important because these policies … are really a first-order impact of massive overreach by the federal government to unravel these benefits that we’ve helped create.”
[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.”
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.
