SPP staff last week added some additional color to their joint proposal with MISO to replace their affected systems study process with interregional transmission analyses similar to their joint targeted interconnection queue (JTIQ) initiative.
The RTOs told stakeholders last month that they intend to create a “JTIQ-affected system zone” where they identify new transmission facilities near their seams that are likely to be affected by their neighbor’s interconnection requests. Staffs said the process will enable them to take advantage of cost-sharing opportunities between GI customers and load. (See SPP, MISO Propose Scrapping Affected System Studies.)
Neil Robertson, SPP’s coordinator of system planning, told the Seams Advisory Group June 15 that the process will incorporate narrower affected system analyses into the regional processes.
“What we’re basically proposing to do is along with this forward-looking study is to look for larger, more regional interregional solutions,” Robertson said. “There is going to be an additional affected systems study performed under a much narrower scope from what it is today. The key thing about this is that it’s an additional layer we’ve incorporated into the regional generation interconnection processes … so the regional studies will provide coverage for the adjacent system along the seam.”
MISO and SPP seams | MISO and SPP
The grid operators say the JTIQ framework will identify and mitigate existing and future affected system constraints. The biennial process will assign a predetermined dollar/MW charge to applicable interconnection customers based on their zonal impact. Staff said that will eliminate individual developers depending on higher-queued interconnection customers’ upgrades to get their own projects online.
“You won’t find many fans of the current process. I wouldn’t think efficiency and timeliness describe the current process,” Robertson said. “We’re providing both cost certainty and shorter timelines than GI customers take to get through the current process.”
Under the JTIQ process, GI customers would know the affected system cost earlier in the process and eliminate unknown affected system network upgrades, Robertson said. He said the process builds on FERC’s proposal for interconnection zones in its proposed transmission-planning rulemaking (RM21-17).
Robertson said the RTO staffs are “working behind the scenes” to gain stakeholder support for the proposal, but initial reaction on the SPP side has been positive.
“At a high level, we think it’s a very creative process,” ITC Holdings’ Raju Brahmandhabheri said before thanking SPP for “coming up with this idea.”
American Clean Power Association’s Daniel Hall said his organization is very supportive of the concept.
“As everyone knows, the study process has been a major impediment to moving through the queue in both RTOs. This effort to try and replace that process with something like the JTIQ is potentially a game changer,” he said. “We appreciate the effort and the creativity.”
$12.4M in M2M Settlements for SPP
SPP began its eighth year of market-to-market (M2M) transactions with MISO by accruing $12.4 million in settlements from its seams neighbor in March, pushing the total amount in its favor to $291.3 million. The process began in March 2015.
It was the 13th straight month M2M transactions have settled in SPP’s favor, and the 28th time in the last 30 months. The two grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm-flow entitlements.
Permanent and temporary flowgates were binding for 1,828 hours in March.
Staff Secretary Savoy Promoted
The meeting may have been the last for SAG’s staff secretary, Clint Savoy. He was promoted to manager of interregional strategy and engagement, a new position, effective June 16. In his new position, Savoy will be leading the interregional relations team in ensuring SPP completes its seams-related goals under the RTO’s strategic plan.
Savoy said SPP plans to backfill his position while it looks for a permanent replacement.
“So, you guys are still stuck with me for a little,” he told the group.
ERCOT has asked the Texas Supreme Court to find that it is entitled to immunity as a governmental agency and reject a five-year-old lawsuit by a power developer.
The grid operator filed a petition with the high court June 10, asking it to reverse a February ruling by a state appeals court that ERCOT is a private, independent membership-based nonprofit not created or chartered by the state. (See ERCOT’s Legal Issues Continue to Mount.)
ERCOT noted in its filing that the Supreme Court “has already held that this case merits review,” and that it had agreed to answer whether the grid operator is immune from suit and whether the Public Utility Commission has “exclusive jurisdiction” over Panda Power Funds’ claims against ERCOT.
“The court declared that it ‘will review the court of appeals’ decision on appeal from the trial court’s final judgment,’” ERCOT said. “This is that appeal.”
The issue has become critical for ERCOT. It has asked that the more than 100 lawsuits filed against it over the February 2021 winter storm be consolidated and reviewed by a multi-district litigation panel. Another petition before the court has raised the same issues.
ERCOT said the Fifth District Court of Appeals “bungled” the statutory text when it ruled 12-1 in February that the grid operator’s immunity claim has no basis in Texas law. As a result, ERCOT said it would be subject to a suit that “could wreak havoc” on the state’s ability to manage the electric grid and market.
The grid operator said it “performs public functions under the PUC’s ‘complete authority’” and asked the Supreme Court to hold that it can manage the market’s electric resources “subject to the direct accountability to the state, without fear that private litigants will divert its mission, and the state’s resources, to their own ends without regard for the public interest.”
The appeals court said that while the PUC maintains some authority over ERCOT, the grid operator is “a purely private entity that is not created or chartered by the government, maintains some autonomy, is operated and overseen by its CEO and board of directors, and does not receive any tax revenue.”
Panda Power filed suit in 2017, accusing ERCOT of publishing “flawed or rigged” projections regarding energy production demand. The company said it spent $2.2 billion to build three plants, relying, it said, on ERCOT’s “false representations of market data.” Those plants are now operating at a loss.
The Supreme Court last year declined to make a ruling on ERCOT’s status. It said it did not have jurisdiction over the matter because the appeals court in 2018 found the grid operator was entitled to sovereign immunity before the higher court was asked to review the case. (See Texas Supremes Sidestep Ruling on ERCOT Lawsuit Shield.)
In December, the fourth Court of Appeals dismissed a lawsuit filed by San Antonio municipal utility CPS Energy against ERCOT. The three-justice panel sided with ERCOT’s claims that the grid operator is a “governmental unit” and said the utility should have first taken its claims to the PUC.
FERC last week said it will take another look into whether Dynegy violated federal laws by manipulating pricing in MISO’s 2015/16 capacity auction.
Following a remand from the D.C. Circuit Court of Appeals, the commission directed its Office of Enforcement to compile a report using evidence from FERC’s earlier, nonpublic investigation that was abruptly closed in 2019. The commission said it will issue a decision following the office’s assessment (EL15-70-003).
FERC directed Enforcement staff not to collect any new evidence. It said the remand report should determine “whether Dynegy’s conduct constituted an exercise of market power and/or market manipulation, and, if so, what effect Dynegy’s conduct had on the 2015/16 auction results.”
The D.C. Circuit ruled last summer that FERC hadn’t sufficiently supported its decision to let stand the Southern Illinois transmission zone’s capacity price produced in the capacity auction. The court said the commission’s repeated decisions to uphold the zone’s $150/MW-day clearing price were arbitrary and capricious because they lacked explanation. (See DC Circuit Sides with Public Citizen over 2015 MISO Capacity Auction.)
Public Citizen, Illinois’ attorney general and Southwestern Electric Cooperative all questioned Dynegy’s market behavior after the auction because the company controlled a significant portion of the zone’s available capacity.
FERC wrapped a three-year investigation into the 2015 auction, finding no market manipulation on Dynegy’s part. The commission concluded the zone’s clearing price was just and reasonable and declined to set up an evidentiary hearing to possibly recalibrate the auction results. FERC said a clearing price isn’t unjust simply because it’s higher than expected. (See FERC Clears MISO 2015/16 Auction Results.)
When the D.C. Circuit remanded the issue to MISO, stakeholders asked if the grid operator was preparing to recalibrate the auction; staff said there wasn’t anything for MISO to do until FERC reassessed its decision.
FERC said it will prevent some commission staff from making decisions when it takes a second look at the matter. The commission will block staff with previous involvement in the investigation and those involved in creating the remand report and subsequent pleadings from “communicating with any member of the commission or its decisional staff concerning deliberations in this proceeding except through pleadings.”
“Out of an abundance of caution, certain commission staff will be treated as non-decisional employees for this proceeding,” FERC said. It did not name the commission staff that the rule would apply to.
Commissioner James Danly recused himself from last week’s order. He previously served on the legal team defending Dynegy against the market manipulation accusations.
Cybersecurity and “extreme natural events” top the list of grid issues WECC plans to focus on over the next two years, along with resource adequacy and the impact of “emerging technologies” on the Western Interconnection.
WECC’s Board of Directors on Wednesday voted unanimously to approve staff recommendations for the organization’s four near-term “reliability risk priorities” (RRPs), issues of special concern that warrant focused research and stakeholder efforts.
“The identification of RRPs does not preclude work on other risks,” WECC wrote in a brief submitted to the board ahead of the vote. “The prioritization process is meant to aid WECC staff and technical committees in focusing their work.”
The priorities identified for 2022-23 come after an intensive stakeholder process that began in February when WECC convened a workshop to begin narrowing the potential list of risks. (See WECC Workshop Assesses Western Risks.)
That proved to be a daunting task for a geographically diverse region confronting multiple threats: growing wildfire danger; deepening drought; and an accelerating reliance on variable renewable resources coupled with the large-scale retirement of conventional generators.
Addressing the board at its virtual quarterly meeting Wednesday, Maury Galbraith, executive director of the Western Interstate Energy Board (WIEB), said WIEB’s Western Interconnection Regional Advisory Body (WIRAB) of state energy officials was “very happy” with the “strategic focus” of the reliability risk priorities and the process used to select them. His one complaint, though, was that the list of potential priorities kept changing over the course of the process, making it difficult for WIRAB and other parties to focus on and “talk consistently” about some of the risks.
“I think that the constant changing of the risk priorities is probably a function of the WECC staff trying to anticipate where the board wants to be on these priorities,” Galbraith said. “And what I would say is, I think it’s OK to have daylight between the WECC staff and the WECC board on these issues. I think it supports the independence of both of those entities.”
Board member Gary Leidich differed with Galbraith’s take.
“I think what happened here was the sausage making, if you want to call it that, was done very publicly. And so I think we all started with, ‘What do we really want?’ And we wound up, I think, with a great set of reliability risk priorities,” Leidich said.
“I accept Maury’s critique of how this changed over the timeframe since February,” Kris Raper, WECC vice president of external affairs, said. “I would say that part of the reason that it changed was not just anticipating where the board wanted to go with this list, but also where the stakeholders were going with this list. And so each time we provided an opportunity for stakeholder involvement, that list modified and evolved as the process went forward.”
Speaking Wednesday at a virtual meeting of WECC’s Member Advisory Committee (MAC), Fred Heutte, senior policy associate with the Northwest Energy Coalition, said that while WECC could have accelerated the prioritization process with a “simple rank-choice exercise,” he found value in stakeholders having sufficient time to produce “a result we can all stand with.”
“And that time is well worth taking, because it helps us get out of our specific areas of concern in a given moment and think about the bigger picture in a pretty structured way, not just a blue-sky way,” Heutte said.
‘Uniqueness’
While the MAC on Tuesday endorsed the four priorities without dissent, longtime committee member Duncan Brown expressed surprise that cybersecurity made it to the final list.
“But then again, we’re not party to a lot of the information that’s flowing around at a board level and within the organization about cyber-attacks and things going on because of the sensitive nature,” Brown said. “I’m not saying we should be, I’m just saying we’re not, so it will be interesting to hear from the board at some stage as to, in generic terms, what we’re seeing in the way of cyber activity against the grid right now and how important that makes this as being one of the topics.”
When WECC kicked off the process in February, cybersecurity would have seemed unlikely to earn the top spot, given the stated preference for prioritizing risks unique to the West and NERC’s existing focus on cyber risks across the ERO.
“I don’t think ‘uniqueness’ to the West is the right word; maybe something relevant to the West, where it’s an issue for the West,” board member Ric Campbell said, noting that other regions of the U.S. are also dealing with RA and emerging technologies.
“I think about what can take the system down, and cybersecurity to me is at the top of the list,” Dick Ferreira, principal at ZGlobal, said during the MAC meeting.
WECC is hoping its cybersecurity work will support the “continent-wide” efforts of NERC and the Electricity Information Sharing and Analysis Center (E-ISAC) while also addressing issues specific to the West.
Delivering a quarterly update to the WECC board Wednesday, NERC CEO Jim Robb pointed to “a couple of events” in the past year in which one of the ERO’s regional entities picked up on a cyber threat that NERC itself had not identified, including a vulnerability in commonly used modeling software.
As it works to “recraft” its strategic plan this year, NERC “is going to be trying to be much more thoughtful about what is the model around cyber, outside of the compliance and monitoring and enforcement of the standards, where the regions can really help us advance the ball,” Robb said.
Playing Together
WECC’s second priority, extreme natural events, was a more obvious choice as the region persistently faces record-breaking temperatures, prolonged cold snaps, deepening drought and intensifying wildfires, in addition to the risk of earthquakes along the West Coast. In its brief to the board, WECC said it expects to examine the impacts of such events on system operations, including load impacts that can be integrated into future reliability assessments.
WECC said it could also investigate how resilient the Western Interconnection is in the face of extreme events, “elevate the dialogue” related to aging infrastructure in high-risk areas and “open dialogue” about adopting a wildfire mitigation data system.
On Thursday, FERC issued a proposed rulemaking requiring transmission providers to detail their plans for assessing their vulnerability to extreme weather and mitigating the risks. (See FERC Approves Extreme Weather Assessment NOPRs.)
Resource adequacy, which WECC deemed its top priority two years ago, was relegated to the third spot on the new list of priorities. The organization has since begun issuing annual assessments to help stakeholders understand the potential impact of declining resource capacity on the system. (See West Cannot Rely on Imports, WECC Says.)
“WECC will continue to improve its stakeholder engagement to gather input, shape analytical work, and share useful and timely information, particularly with its regulatory and policy partners,” WECC said in its brief.
“WECC’s resource adequacy work focuses largely on resource plans, but there is a noticeable absence of information on how or whether integrated resource plans are carried out. To complement its current studies, WECC will evaluate how past resource plans have been implemented and the potential implications to resource adequacy and reliability,” it said.
The fourth priority, examining the impact of changing resources and customer loads on the grid, will likely initially focus on the impact of inverter-based resources (IBRs) on system performance.
“In some cases, the West simply does not have adequate models and data to evaluate the impacts associated with the changing technology (e.g., models for IBRs need to be improved throughout the Western Interconnection). Accurate models and data need to keep pace with the changing resource mix and loads to ensure reliability,” WECC said.
“As we transition to 100% green resources, [there’s] a lot of discussion about challenges in integrating inverter-based resources,” Steve Ashbaker, WECC reliability initiatives director, told the MAC on Tuesday.
Ashbaker explained that most IBRs are “grid-following” resources, meaning they can only inject power into the grid when there is a system frequency and voltage, whereas “grid-forming” resources can create their own frequency and voltage.
“The other thing we need to look at is grid-following plus grid-forming inverters in parallel with traditional rotating inertia — how do they all play together?” he said. “We look at areas of system strength, voltage regulation, frequency regulation, fault current oscillation dampening as just being some of the challenges that we need to consider.”
FERC on Thursday approved an update to NERC’s reliability standard on physical security, removing a requirement that is no longer needed (RD22-3).
The order puts into place a new standard, CIP-014-3, to replace the existing standard CIP-014-2. NERC’s Board of Trustees approved the new standard at its meeting in February. (See “Additional Approvals,” NERC Board of Trustees/MRC Briefs: Feb. 10, 2022.)
At issue is language in the “Compliance” section of CIP-014-2 that requires transmission owners and operators to retain “all evidence demonstrating compliance” with the standard at the relevant facilities. NERC told FERC in its filing that while this provision “presents challenges to effective and efficient compliance monitoring” because auditors must visit the sites in question to see the data, it was considered necessary in light of the sensitivity of this information.
That assessment has changed following the introduction of the Secure Evidence Locker (SEL), which went live alongside the Align Software Platform in March 2021 for the Texas Reliability Entity, the Midwest Reliability Organization and NERC, and for the rest of the ERO Enterprise in May of that year. (See ERO Align Tool Goes Live for NERC, MRO, Texas RE.)
NERC conceived of the SEL as a way to provide secure digital storage where confidential information collected as evidence can be kept separate from work papers managed through the Align tool. Regional entities are not required to use NERC’s SEL if they construct their own lockers, provided they meet certain reliability and security specifications provided by the ERO.
With the SEL available, NERC told FERC that entities no longer need to worry about CIP-014 evidence being mishandled because it can be stored in the same secure location as all other evidence in the compliance monitoring and enforcement program (CMEP). As a result, the ERO asked the commission to remove the requirement for on-site storage.
EEI Raises Security Concerns
The proposal did not go without criticism from industry; after NERC submitted the new standard to FERC in February, the Edison Electric Institute filed an objection with the commission. EEI reminded FERC that because of the “critical and highly sensitive nature” of the information documenting CIP-014 compliance, it is not widely available even within utilities and that stakeholders “go to great lengths to protect the identity of the assets and other sensitive information.”
The institute also said that, far from providing additional levels of security, the SEL added risk by aggregating sensitive information from across the industry in a single place that could be attacked by a malicious actor. It argued that the commission should allow registered entities “more flexibility … to select the most secure methods for providing CIP-014 compliance data.”
FERC rejected EEI’s argument, responding that the SEL is not a “novel and untested” idea; the commission cited NERC’s 2020 petition for funding the SEL, in which the ERO stated that at least two REs already used similar lockers to collect CIP-related evidence. FERC’s order noted that NERC already uses the SEL to store evidence for other CIP standards, indicating “that it is a well established and secure method of evidence review.” It also observed that all data stored in the SEL are encrypted, are not backed up and are destroyed as soon as the CMEP engagement is done.
The standard became effective immediately upon FERC’s approval.
WASHINGTON — FERC Chairman Richard Glick (D) on Thursday categorically denied taking directives or feedback from Biden administration officials on commission actions.
The remarks to reporters after the commission’s monthly open meeting came in response to questions about records of Glick’s meetings released under the Freedom of Information Act. They showed that Glick had met 13 times with Deputy National Climate Adviser Ali Zaidi between September of last year and the end of March and nine times with Energy Secretary Jennifer Granholm between last July and the end of March.
The Wall Street Journal’s Editorial Board published an op-ed Sunday suggesting that the meetings indicate Glick had lied before the Senate Energy and Natural Resources Committee when he denied slow-walking natural gas pipeline approvals because of administration orders. (See Glick: No Regrets over Gas Policy Statements.)
“It’s impossible to know what Messrs. Glick and Zaidi were discussing,” the board wrote. “But it’s hard to believe the two never talked about pipelines.”
Glick called the Journal’s piece “complete bull,” joking that he wanted to quote former Attorney General Bill Barr, whom he said was “more colorful.” He was alluding to Barr’s statement in a deposition that former President Donald Trump’s claims of election fraud were “bullshit.”
“I take FERC’s independence very seriously,” he told reporters. “I would never allow [anyone in the administration] to tell me what to do, and the good news is that in this particular administration, they don’t do that.”
Glick was likely alluding to the Trump administration’s proposed Grid Resiliency Pricing Rule, which FERC unanimously rejected in 2018. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.) He also said that in his first meeting with Granholm, she pledged that the Department of Energy would “never tell [us] what to do. And she’s lived up to that, and I really respect that.”
He also said he “would never, ever talk about anything we can’t talk about, meaning ex parte.”
Under the commission’s ex parte rules, FERC commissioners and staff can only discuss issues pending before them among themselves; they cannot even consider opinions about those issues unless they are officially filed with the commission as comments.
Instead, Glick said, the meetings were for him to brief the administration about what was going on: “‘What’s the status of grid reliability? Where do we think the grid is headed? Is there enough fuel in New England for the winter? What’s happening in Texas during [last year’s] winter storm? Was there market manipulation?’ … It’s never, ‘you need to do this,’ or ‘you should do this,’ or ‘this is our policy.’ That just doesn’t happen.”
Glick was also asked whether he received feedback from Zaidi or Granholm about two controversial policy statements the commission issued earlier this year that were later converted to drafts, with the majority citing feedback from stakeholders who said the policies were confusing. (See FERC Backtracks on Gas Policy Updates.)
The policies were not even discussed, Glick said. “No one provided any feedback whatsoever.”
The FOIA request was submitted by the Institute for Energy Research, which describes itself as a nonprofit that “conducts intensive research and analysis on the functions, operations and government regulation of global energy markets.” It advocates for free-market energy policy and fossil fuel use.
INDIANAPOLIS, Ind. — MISO’s Board of Directors discussed concerns over dropping capacity reserves during its board sessions this week as heat blistered the footprint and forced emergency preparations.
As the board gathered this week, MISO operators managed the first serious heat wave of the 2022/23 planning year. The RTO issued a maximum generation alert Monday for MISO South and a footprint-wide alert on Wednesday; both were to expire Wednesday night.
The alerts followed earlier capacity advisories for MISO South on Sunday and the entire footprint Wednesday. MISO also called for conservative operations by all members through 10 p.m. ET Thursday.
The advisories come after MISO’s 2022-23 planning resource auction (PRA) in April unveiled a 1.2-GW capacity shortage across MISO Midwest and triggered a $236.66/MW-day cost-of-new generation entry clearing price for the entire subregion. Though members approached the auction with more capacity year-over-year, the RTO said the resource additions were mostly intermittent and generally less available than retiring thermal generators. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)
During Tuesday’s Markets Committee meeting, MISO Executive Director of Market Operations J.T. Smith said the capacity deficit doesn’t necessarily mean MISO must revert to controlled load shedding. The RTO can access imports and its load-modifying resources during tight conditions, he said.
“There is some risk sitting out there, but to date … there hasn’t been a summer situation where MISO had to go through all of its emergency operating procedures,” Smith told board members.
He said staff forecasted a 122-GW peak for Wednesday, 2 GW shy of its overall summer peak prediction. Smith said while MISO appeared to have enough firm generation on hand beforehand, units tripping offline in real time make the difference.
“The interesting factor will be generator performance,” he said.
The grid operator’s and the Organization of MISO States’ 2022 resource adequacy survey has painted an increasingly dark supply picture. According to the survey, capacity deficits could reach 2.6 GW next year and as much as 11 GW by the 2027/28 planning year. (See OMS-MISO RA Survey Says Supply Deficits Could Top 10 GW by 2027.)
MISO Director Nancy Lange asked whether the RTO needs a better “picture of generation retirements and their time frame.”
“Do we need additional insights or is there something I’m missing?” she asked. Lange said MISO could have withstood the uncertainty “in the good old days” but that now, it’s crucial it knows which units it stands to lose.
Smith acknowledged that the OMS-MISO survey results have recently been “rosier” than the capacity auction results. He said that this year’s survey could influence some generation owners’ decisions to keep or bring more capacity online.
MISO currently has about 124 GW of capacity at various stages of study in its interconnection queue. Historically, about 20% of the generation that enters the queue reaches commercial operation.
President Clair Moeller said MISO is currently holding conversations with OMS on how it can achieve a “deeper level of collaboration” with its states on resource adequacy.
“They have the majority of the authority,” Moeller reminded the board. “We don’t have the authority in the regulatory process to make anybody do anything. Our big weapon here is transparency.
“They’re suffering through this same problem of needing more information,” he said. Moeller pointed out that jurisdictional utilities usually complete integrated resource planning once every three years and regulators can be caught off guard on how utilities’ plans evolve.
Lange called the media’s emphasis on possible rolling blackouts unhelpful and potentially sensationalist. She asked whether MISO could pin a number on its chances of entering controlled load shed.
“Could there be a heat dome event that sits over PJM and MISO? It’s unlikely, but it could happen. I can’t quite put a probability on that, but if it does happen, we will have a difficult time,” said Renuka Chatterjee, executive vice president of system operations. “We try to keep the lights on. Sometimes we can’t keep all the lights on, and we have to make some choices.”
Independent Market Monitor David Patton estimated that about 5 GW of MISO’s generation has retired prematurely, some due to the footprint’s uneconomic capacity market conditions. He reiterated that the grid operator should have used a sloped rather than vertical demand curve in its capacity auction.
“If we ignore economics, we expect that we’ll get bad outcomes, and this is a bad outcome … If we value reliability, we have to fix this market,” he said.
Patton said he now thinks “there’s a lot of interest among states on reforming the demand side of the market.” He met privately with state regulators after the Markets Committee meeting to discuss potential capacity market adjustments.
“As evidenced by the recent PRA results, it is time to review … market signals and reliability requirements, and to enhance the collaboration between MISO, the states, and other entities responsible for resource adequacy,” most OMS members wrote. “Put simply, MISO must ensure it has the markets and planning processes in place that can deliver the reliability and economic efficiencies its members expect.”
State regulators said they need more transparency into how load is planned to be served within MISO so they can “fully understand the landscape of risks associated with decisions that are not subject to their oversight.”
The regulators said the capacity auction shortfall is “further impetus for our ongoing efforts to work together to provide transparency, reduce uncertainty, and ensure roles and responsibilities for resource adequacy are crystal clear so we are not reduced to pointing fingers or disclaiming these responsibilities.”
OMS said MISO must immediately act to reduce barriers on both the transmission and distribution system to gain access to new generation. It said the RTO should “ensure resource retirements are properly and holistically studied before states finalize their decisions.”
“The region should not wait for the large number of distributed resources — as MISO has recently proposed in its [FERC] Order 2222 implementation timeline — that can often be deployed much more rapidly than grid-scale resources,” the organization said. “Likewise, MISO must move with haste to re-examine its study process for retiring resources so states can fully consider the impact retirements have on the region’s and the respective states’ electric reliability.”
The grid operator has proposed more frequent steady-state analyses and more attention to transmission system reliability when analyzing retiring generation but does not plan to consider resource adequacy in the studies. (See MISO Bolstering Generation Retirement Studies Amid Capacity Shortage.)
OMS finished by saying it believes in the MISO system’s various planning activities and interconnectedness. However, it also said that the region is “best served when decisionmakers at all levels engage in transparent, cooperative and respectful communication.”
The letter was signed by 11 of OMS’ 17 members. Regulators from Louisiana, Mississippi, Texas, Montana, the New Orleans City Council and the Canadian province of Manitoba did not add their signatures. Because the letter was not taken up under normal OMS board meeting prcedures, OMS does not consider the letter an official position.
Spring Brings High Prices
Load has returned to normal in the spring as the pandemic winds down, averaging about 70 GW per day with a seasonal 104-GW peak demand. Real-time prices shot up to $57/MWh on inflated fuel costs from $26/MWh last spring and $18/MWh in two years ago, when the pandemic began in earnest.
“This was a very high-cost quarter,” Patton said. He said natural gas prices rose 140% over last spring, with prices routinely going above $8/MMBtu in the quarter.
Patton said coal unit operators are beginning to conserve their stockpiles again as they did during the winter, holding out for the high-priced and hottest summer days.
He also said transmission congestion was “unbelievably high,” with real-time congestion costs surpassing $1 billion during the spring.
MISO Sees Members’ Savings Increase
Against this backdrop, MISO debuted a forecasted value proposition that bets market participants will more than double their savings by 2040 through membership. The forward-looking estimate foresees members enjoying a benefit-to-cost ratio of about 26:1 by 2040, up dramatically from its current 11:1 ratio.
MISO last year said it saves its membership about $3.4 billion annually on average and approximately $36.3 billion in total since 2007. (See MISO: 2021 Member Savings Exceeded $3B.)
The value proposition study normally quantifies the annual savings it generates for its membership against utilities going it alone. MISO included the usual savings measures of more efficient generation dispatch, its diverse geographic footprint, a diminished need for new generation, and the sturdier reliability that comes with a resource sharing pool. Staff pointed out in its projections the benefits of being able to access carbon-free energy from other regions and to more flexibly incorporate renewable energy into the resource stack.
MISO CEO John Bear called the new value proposition a “significant increase in value delivery to MISO membership.”
“In the future, MISO will continue to play a significant role in ensuring reliability and optimizing flexibility in our large and diverse footprint as it transitions towards a more decarbonized system,” he said in a press release.
“[T]he accelerated transition to a low-carbon future will create challenges, which can be more reliably and efficiently solved using the region’s scope and diverse resources, creating even more value for customers in the future,” said Wayne Schug, MISO’s vice president of corporate strategy and business development.
The grid operator said it assumed a 4.9% increase in membership costs per year to gauge the savings, noting the increase is “well above recent levels of inflation and historical MISO costs.”
MISO said it will continue to conduct an annual value proposition study but said, “given the magnitude of change the industry is undergoing, it is important to provide indications for the future value range MISO may bring to the region.”
American Electric Power (NASDAQ:AEP) customers in Ohio accused the company of racism Wednesday for cutting power to poor areas of Columbus while continuing service to richer suburbs in the wake of a severe windstorm.
AEP said it lost more than 100 poles during the storm Monday night, which saw wind gusts as high as 95 mph, and had downed power lines across its service territory Tuesday morning. The National Weather Service said the storm was a derecho, a windstorm driven by large, explosive thunderstorms.
Dozens of customers vented on Facebook and Twitter, questioning why the utility cut power to poorer, urban areas of Columbus, while richer suburban areas, and AEP’s headquarters building, had power.
Of the 135,000 customers lacking power at one point Wednesday afternoon, about 85,000 were in the Greater Columbus area — even though the city’s power lines were not damaged — The Columbus Dispatch reported. By 5:30 p.m., the outages had dropped to less than 127,0000.
AEP Ohio was under attack on social media from those who questioned why the utility cut power to poor areas of Columbus while the richer suburbs and the AEP headquarters building had power. | summertime fun stevie via Twitter
A peak of 230,000 customers lost power Tuesday as PJM ordered load sheds on three 138-kV lines to prevent overloads and cascading outages. (See related story, PJM Orders Load Sheds in AEP Following Storms.)
PJM ordered another load shed at 11:40 a.m. Wednesday to mitigate an N-5 cascade analysis on the 138-kV Kenney-Roberts line. Earlier in the day, PJM extended its Hot Weather Alert for its Western region, including AEP, through the end of Thursday.
AEP restored power over Tuesday night to some customers in central Ohio but turned it off again Wednesday as demand rose, saying customers previously affected might see additional outages through Thursday. It asked customers to reduce their electric usage between the peak hours of noon and 7 p.m.
In an update at 7:30 p.m., AEP said its crews had made significant progress repairing damage to the transmission lines serving Columbus and that it expected to begin restoring power to substations and customers in the early morning hours.
“All customers who were impacted by the emergency outage will have their power restored by 5 a.m. on Thursday, June 16,” AEP said. “We expect that these repairs will allow the power grid in the Columbus area to operate as it normally would, even as temperatures rise.”
The forecast for Thursday calls for temperatures in the mid-90s.
“I’ve been with AEP 41 years, and I don’t remember anything like this,” Jon Williams, AEP Ohio’s managing director of customer experience, told the Dispatch. “This is a very, very unusual occurrence.”
Outrage
AEP said the outages in Columbus were necessary because the storm damaged transmission lines in eastern and southeastern Ohio that serve the city.
“This is criminal. You intentionally cut power in low-income areas. How obvious is your prejudice?” wrote one woman on AEP Ohio’s Facebook page. “Good ole fashion redlining practices determined whose power was cut. No way they will last two days in that kind of heat.”
At least 11 cooling centers were opened in central Ohio as temperatures hit the mid-90s and the heat index hit 105.
Columbus, Ohio, areas affected by outages Wednesday afternoon. | AEP Ohio
“Shout out to AEP Ohio for purposely cutting power to, almost exclusively, the poorest parts of Columbus during today’s extremely hot weather,” wrote one resident on Twitter.
“Apparently AEP is intentionally cutting power to Columbus area residents in 90-degree weather to protect the grid’s integrity,” tweeted a woman who said she had been without power for a few hours. “Funny enough, power hasn’t been cut to anyone in Dublin, Bexley or the like. Hmm … wonder why?”
Williams and other AEP officials insisted the outages were dictated by where lines were overloaded, not by any favoritism.
“There’s no tie whatsoever to customers, or what type of customers,” Williams told the Dispatch. ‘We’re not picking and choosing locations.”
The utility said it was working to maintain power for critical facilities like hospitals and emergency services.
It said it had to react “within seconds” to protect the system. “Unfortunately, there simply was not enough time to notify customers before taking the necessary actions to protect the grid,” AEP said in a statement on its website.
It said it was unable to use rolling blackouts to reduce stress on the system. “In this case, the affected transmission lines cannot be brought back online until other lines that feed into the area are repaired from storm damage and returned to service,” it said.
The Columbus branch of the NAACP released a statement demanding more information from AEP about its load-shed process.
Once power is restored, the Public Utilities Commission of Ohio will conduct an “after-action report to understand what it is that happened,” said PUCO spokesman Matt Schilling.
Schilling said all six of the state’s electric distribution utilities had significant outages from the storm. “Many [of the utilities] are getting close to being fully restored,” he said in an interview Wednesday. “By and large, the central Ohio area was hit hardest, which is AEP service territory.”
Merrilee Embs, spokesperson for the Ohio Consumers’ Counsel, said the office hopes “for the safety of the many central Ohio consumers losing electricity in the extreme heat and for the AEP workers restoring electricity.
“Job-one is to restore power safely and ASAP for thousands of Ohio families,” Embs said in a statement. “… The PUCO should investigate to learn what happened and why — and for lessons learned. Importantly, the PUCO should allow the public to be heard in the process, given that so many Ohioans have been at risk.”
At an abbreviated meeting on Wednesday, members of NERC’s Standards Committee approved four standard authorization requests (SARs) and the teams to work on them.
Two of the SARs that came before the committee at Wednesday’s meeting were coming off of industry comment periods after having been accepted at prior meetings. First up was Project 2022-01 (Reporting area control error (ACE) definition and associated terms), which first came before the committee at its January meeting; the committee approved the SAR drafting team in April. (See NERC Standards Committee Moves Projects Forward.)
Amy Casuscelli, Xcel Energy | NERC
The goal of the project is to revise the definition of reporting ACE, which in its current form conflicts with the Western Interconnection’s automatic time error correction (ATEC) process and does not allow other interconnections to develop ATEC at all, according to the Reliability and Security Technical Committee’s (RSTC) Resources Subcommittee. By redefining the term, NERC hopes to “improve long-term average frequency performance” and to help other interconnections “pursue automatic correction approaches.” The committee approved the SAR and agreed to appoint the SAR drafting team as the standard drafting team (SDT).
Also before the committee was Project 2021-02 (Modifications to VAR-002), which was proposed by NERC’s Inverter-based Resource Performance Task Force in 2020 and endorsed by the RSTC the same year. The Standards Committee accepted it in January 2021 and appointed the SAR drafting team that July. (See Standards Committee Approves Drafting Team Additions.) The Project 2021-02 SAR has gone through two industry comment periods since then; the most recent ended in April.
In addition to approving the SAR, members also agreed to a 30-day solicitation period for additional members of the SDT. Latrice Harkness, NERC’s manager of standards development, said the organization is seeking transmission operators with expertise in “receiving and applying information to [their] real-time assessment and real-time monitoring activities” because the project proposes to add a requirement to VAR-002-4.1 for generator operators to notify their TOPs of status changes in voltage-controlling devices.
ERATF SARs Approved After RSTC Endorsement
The committee also approved two SARs submitted by the Energy Reliability Assessment Task Force (ERATF) and endorsed by the RSTC at its meeting last week. (See “SARs Move to Standards Committee,” NERC RSTC Briefs: June 8-9, 2022.) The SARs are grouped under a single project, intended to update NERC’s reliability standards to require utilities to perform energy reliability assessments in order to evaluate energy assurance.
The item did not face any serious opposition, though Linn Oelker of LG&E and KU asked to clarify why two SARs were needed, pointing out that their scope seemed to be identical. Harkness acknowledged the similarity between the two proposals and explained the ERATF thought they ought to be separate because one applies to the operations time horizon and the other applies to the planning horizon. She added that this assessment is subject to change as the drafting team’s work continues.
“Moving forward, if the SAR drafting team did decide that they wanted to combine these [or] to reword them, that’s an option that the … team will have,” Harkness said.
July Meeting to be Held in Person
Chair Amy Casuscelli, of Xcel Energy, reminded committee members that their next meeting July 20 will be held in person, for the first time since the beginning of the COVID-19 pandemic, at Xcel’s offices in Denver from 10 a.m. to 1 p.m. MT. The gathering will be followed by a joint meeting with NERC’s Compliance and Certification Committee, from 1 to 4 p.m.
Howard Gugel, NERC’s vice president of engineering and standards, noted that the Institute of Electrical and Electronics Engineers’ Power and Energy Society is also holding its 2022 general meeting in Denver, July 17-21, and encouraged attendees to line up their hotel reservations early “because there’ll be a lot of folks in town that week.”
FERC is learning from technical conferences that it’s important to be clear about what the emerging system needs will be with the energy transition, Robert Fares, a wholesale electricity markets analyst at the commission, told NYISO’s Management Committee on Tuesday.
The MC received from Fares an update of the commission’s recent areas of interest, including changes to capacity, energy and ancillary services markets.
“And it’s important to be clear about whether and why the existing products are not meeting those needs and then finding the product that addresses those needs in a very targeted way just in order to balance the tradeoff between minimizing consumer costs and also meeting the needs of the system,” Fares said.
Fares referred to NYISO’s recently completed changes to both its buyer-side mitigation (BSM) and capacity accreditation. The commission earlier this month accepted NYISO’s proposal to implement its revised BSM rules for the current class year.
Capacity accreditation is going to be a hot topic going forward, and “I think you all know that that’s become a bit of a trend across the eastern RTOs, where PJM took the first bite of the apple, and NYISO has taken the second one, and now I am assuming everybody will shortly be taking a bite at the apple,” Fares said. “I personally expect that’s going to be continually refined over the coming decades as the transition continues, so that’s certainly a big area of interest.” (See PJM Responds to Market Monitor Recommendations.)
FERC has also been very interested in transmission because there’s a wide consensus that it is going to be an extremely challenging area over the coming years in terms of enabling the energy transition, he said.
Another area of interest across all the RTOs concerns the rapid pace of new development of generation. “The interconnection queues are totally flooded right now, and making those queues work quickly and efficiently is really an important part of FERC’s mission,” Fares said. “Part of the commission’s underlying mission is promoting competition, and promoting efficient entry and exit is a big part of promoting electric competition.”
RS1 Cost-of-service Study
NYISO staff recommended that a new Rate Schedule 1 cost-of-service study be conducted in 2022-2023 in order to consider the impact of the significant market design changes to be implemented, though several stakeholders seemed reluctant to commit the ISO’s limited resources to such a study.
The last study was done in 2011, and the MC will vote on conducting a new study at its July 27 meeting.
Market changes include the integration of distributed energy resources, large-scale solar and co-located storage resources, which “will result in an increase in the number of market participants and resource types that may not be prevalent in our markets today, so conducting a cost-of-service study in the coming year would be appropriate to provide rate certainty for those new entrants, as well as NYISO cost recovery and budget planning,” said Chris Russell, manager of customer settlements.
The MC discussed whether a Rate Schedule 1 Cost of Service Study is necessary due to current and future market changes. | NYISO
Some market participants said that the penetration of renewables in NYISO markets has yet to cause big changes and expressed concern the ISO could stretch its resources too thin dedicating up to $300,000 for a new RS1 study while trying to manage some major projects.
“We want to be ahead of these things rather than reacting to them, and that’s part of the reason why we look at doing a study now rather than later, even with limited market penetration for a lot of these kinds of resources,” Russell said.
Another stakeholder recommended that the ISO consider asking the MC to approve two RS1 studies — one in 2025 and another in 2030 — which would lock down some dates while also giving staff time to prepare for the study.
MISO and SPP seams | MISO and SPP
