SPP’s market-to-market (M2M) settlements with MISO exceeded $20 million in October for the second time in 12 months, staff told the Seams Advisory Group Wednesday.
The $20.59 million in settlements, which accrued in SPP’s favor, pushed the M2M payments due to SPP to $203.87 million since the grid operators began the process in March 2015.
Permanent and temporary flowgates were binding for more than 1,875 hours in October. Outages and power swings from nearby wind increased shadow prices. The grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm-flow entitlements.
M2M settlements hit a record $51.49 million, in MISO’s favor, in February, thanks to February’s winter storm. Settlements have accrued to SPP during the eight months since February and for 23 of the last 25 months.
New SAG Members
The group welcomed new members Luke Haner of Omaha Public Power District and Brenda Prokop of ITC Great Plains to their first meeting.
The SAG still has three open seats that it plans to fill next year. With a membership normally dominated by transmission owners, the group hopes to diversify by targeting larger retail customers and generation developers when it seeks applications after Jan. 1.
Only five of 20 respondents to the stakeholder survey said their companies have experienced a failed cross-seam transaction, transmission project or interconnection project because of rate pancaking issues. Twelve said rate pancaking is a factor when seeking long-term generation commitments and half said the same for siting or accessing generation in a particular location.
Stakeholders said reservations timing is not consistent between the RTOs. SPP charges for all use of its transmission system, including unreserved use, while MISO only bills for network services taken, not reserved, at the time of the monthly system peak. MISO bills for transmission service each month based on actual usage at the zonal coincident peak, but SPP uses a 12-month rolling average.
Point-to-point reservations across the seam | Organization of MISO States
The RTOs told the working group that 59 load-serving entities have transactions across the seam. MISO has three active point-to-point (PTP) service requests across the seam and SPP had 75 network service and PTP requests.
Marcus Hawkins, the Organization of MISO States’ executive director, said he has not yet sifted through all the data, leading to group to plan another meeting in January to take a deeper dive. The working group plans to present its findings to the SLC in February.
CAISO issued a straw proposal this week that seeks to address the state’s dependence on energy storage for meeting summer evening peaks by paying batteries to stay charged during the day in readiness for when they are needed most.
Avoiding energy emergencies like those in the past two summers requires batteries to be ready to discharge during heat waves in the hours after the sun sets and solar goes offline, CAISO said. But requiring storage resources to maintain a state of charge means they cannot take advantage of other financial opportunities during the day, it said.
“A principal concern raised by the storage community is a lack of compensation during critical periods when the ISO must retain state of charge on limited energy storage devices, which may preclude their active participation in the real-time markets,” the proposal says. “The existing bid cost recovery rules, which are designed based on traditional energy generation resources, do not consider energy storage charging and discharging cycles.”
A main objective of CAISO’s energy storage enhancements stakeholder initiative is to develop a “set of solutions to enhance the optimization of storage resources and to allow additional flexibility for storage operators to manage state of charge in the real-time markets,” the straw proposal says. “The ISO proposes a new model, called the energy storage resource (ESR) model, which is unique from existing models because bids are predicated on state of charge values, rather than a dispatch instruction for power.”
The ESR model would require scheduling coordinators to “submit bids in terms of incremental state of charge instead of traditional bids submitted in terms of incremental energy,” in recognition that a resource’s costs to charge and discharge are different based on its state of charge, it says.
“Specifically, the energy storage resource model will allow storage resources to offer lower prices to provide energy when a battery has a nearly full state of charge and higher prices when it is nearly depleted,” it says. “This new model would be employed in the ISO’s market software for both the day-ahead and real-time markets and could be used by participants in the energy imbalance market.”
Before last summer, FERC approved a temporary two-year measure by CAISO to require batteries to maintain a minimum state of charge on days with insufficient supply to meet demand. The proposed changes are intended as long-term market rules.
Another part of the proposal involves paying storage resources for exceptional dispatch by compensating them “at the difference between the prevailing price during the exceptional dispatch and the reference interval discharge price. The reference interval discharge price will be the period when the storage resource actually discharges and sells energy.”
Batteries Proliferate
The proposed new rules reflect the state’s growing reliance on batteries to maintain reliability.
CAISO will have 2,500 MW of four-hour lithium-ion battery storage connected to its grid by the end of this year, CEO Elliot Mainzer told the Western Energy Imbalance Market’s Governing Body on Wednesday. He called 2021 the “advent of the bulk storage fleet on the California grid.”
“I believe that is the highest concentration of lithium-ion battery storage in the world and testament to years of policy support and procurement efforts by state officials,” he said.
Most of the battery resources were connected in response to the rolling blackouts of August 2020, when the state’s vulnerabilities to outages during severe Western heat waves became clear. The state’s increasing reliance on solar and wind power, without sufficient storage, was partly to blame for the energy emergencies. (See CAISO Sees ‘Explosive’ Growth in Storage in July.)
The energy storage enhancements stakeholder initiative, which began in May, focuses on market reforms to bring massive amounts of utility-scale storage into CAISO’s system to back up the solar and wind power needed for California’s transition to 100% clean energy by 2045, as well as to meet local capacity requirements. (See CAISO Readies for Storage Scale-up.)
The separate energy storage and distributed energy resources (ESDER) stakeholder initiative began five years ago and proposed numerous changes in four phases. FERC approved the fourth phase in October; it included market power mitigation measures for storage resources and biddable state-of-charge parameters. (See FERC Accepts Latest CAISO Storage, DER Rules.)
CAISO expects to add at least another 1,000 to 2,000 MW of storage in 2022-2024, most of it in lithium-ion batteries with four-hour discharging capacity.
Summer reliability issues will likely continue through 2024, as natural gas plants close and the state’s last nuclear generator, Pacific Gas and Electric’s Diablo Canyon power plant, begins shutting down, CAISO has said. State energy planners hope a large-scale buildout of solar, wind and batteries will compensate.
NERC Trustee Roy Thilly urged members to adopt the agency’s new cold weather standards before they become enforceable in early 2023 during SERC Reliability’s year-end board meeting.
“The tolerance for outages is non-existent,” Thilly said Wednesday, referring to the general public’s attitude.
He also warned that regions can’t depend on neighboring supplies should a widespread weather event strike, saying it takes four years on average to implement a new standard after a major event.
“That simply is too long a period in some cases,” Thilly said. “We need to decide when we need to be more agile and nimble.”
SERC’s 2021 regional risk report listed supply chain issues, extreme weather, generation fleet transitions, cyber security threats, a dependence on rising natural gas prices and the challenge of integrating variable resources as major concerns this winter. (See Grid Faces Multiple Risks in Winter Months, NERC Warns.)
SERC CEO Jason Blake said the organization plans to tailor its operations more closely to its regional risk reports in 2022. He said it’s important for SERC to be able to point to the report’s sections as the reasons behind workshops and agenda items.
Blake also said SERC will focus more on severe weather preparations.
“We have a very hot footprint; we have parts of the footprint that get pretty cold,” he said. “We also have parts of the East Coast. … If you’re going to get hit by a hurricane, you’re probably in SERC.”
SERC board member Venona Greaff said the new freeze-protection rules should surprise no one.
“For many, it seemed like a freight train bearing down on us, but it’s been a long time coming,” she said, noting that parts of the country have been experiencing notable cold-weather strain on the grid since 2011.
Greaff said NERC left cold weather undefined, giving generation operators the responsibility of deciding which temperatures pose a risk. She said it’s not realistic for the Deep South to enclose entire plants in buildings like those in the North. Greaff said that during the summer, southern generation operators need heat to dissipate, but said operators could consider enclosing smaller segments of their facilities.
Melinda Montgomery, SERC’s senior director of engineering and advanced analytics, said about 86% of SERC entities in a recent survey intended to complete plant winterization before the end of November.
Montgomery said the organization plans to survey its members again on their performance following this winter.
Montgomery said while gas well-head freeze offs and frozen coal piles were an issue in SERC territory during February’s winter storm, frozen plant equipment, water supply issues and local transmission emergencies also contributed to the loss of load.
David Huff, an engineer with FERC’s Office of Electric Reliability, said the winter storm wrought the largest monthly decline of U.S. natural gas production on record. He said production in the continental U.S. dropped 28%; Texas’s production alone dipped more than 70% when compared to its January production.
Huff said 1,045 generating units experienced 4,124 “outages, derates or failures to start.” Of those failures, 58% came from natural gas-fired generation. He said frozen equipment accounted for more generation outages than fuel-supply issues. However, if there was an outage caused by fuel supply, it was overwhelmingly a natural gas generator.
Protecting transmitters, sensing lines and instrument against freezing, as well as protecting wind turbine blades against icing could have reduced offline megawatts caused by outages, Huff said.
Texas regulators on Thursday pushed ahead with commission staff’s proposal to re-design the ERCOT market, directing the grid operator to work with it in implementing the two-phase approach.
In a 35-minute discussion, the Public Utility Commission did not address the 54 stakeholder comments it received on staff’s Dec. 6 strawman proposal, sticking to language in staff’s original memo. (See PUC Narrows Options for ERCOT Market Redesign.)
In two orders, the commissioners agreed to adopt the strawman as its market redesign blueprint and ordered ERCOT to take the strawman’s Phase 1 blueprint and file a comprehensive implementation report on the plan by Jan. 10. The commissioners also directed the ISO to prepare nodal protocol revision requests for their approval, potentially sidelining ERCOT’s stakeholder process.
Phase 1’s order involves modifying the operating reserve demand curve (ORDC); allowing for “more targeted response” to increase the use of load resources; reforming emergency response service; and adding new ancillary service products.
The PUC ordered ERCOT to make the ORDC changes effective Jan. 1. The modifications include setting the curve’s minimum contingency level to 3,000 MW and eventually decoupling the systemwide offer cap and the value of lost load, now set at $5,000/MWh.
PUC Chair Peter Lake (2nd from right) explains his thoughts on the ERCOT market redesign. | Texas Admin Monitor
PUC Chair Peter Lake also asked commission staff to work with ERCOT in “crystalizing” the major “abstract” concepts of Phase 2, which is described in the second order. He said staff should focus on Phase 2’s backstop reliability service proposal first and then the load-side reliability mechanism he has been promoting since October.
Neither order had been filed as of Thursday evening.
The PUC did not discuss the cost impact of its proposals.
ERCOT’s Kenan Ögelman, vice president of commercial operations, told the PUC that ERCOT staff would target a Feb. 15 deadline to provide the inputs, specifications, quantification and relevant metrics it would need to design and build each of the Phase 2 proposals.
Alison Silverstein, a former PUC and FERC staffer, said in a fiery response to RTO Insider that she was “deeply disappointed” by the commission’s actions. She said the commissioners should have called for “much more” analysis of both phases’ reliability, market and cost impacts and should include better stakeholder and public input going forward.
“Today the commission voted to implement many Phase 1 measures that will have interacting effects on resource and system operating capabilities and costs, without any clear analysis of whether and how it will all work together or what it could cost Texas electric customers,” Silverstein said. “We don’t know whether all these measures will collectively help or hurt day-to-day resource availability and reliability, and there has been zero calculation of how much additional money they will suck out of Texas electric customers’ wallets.
“I’m willing to pay more for better reliability, as are many Texans, but it’s the commission’s responsibility to make sure that we get what we pay for. Today, the PUC abdicated that responsibility,” Silverstein said.
Consultant Doug Lewin of Stoic Energy, who live-tweeted the open meeting, said although there will be a cost analysis on the load side reliability mechanism and the backstop reliability service, “it still seems to me like they’re missing an integrative look at system needs.”
“How big should the backstop reliability service be? What are we basing that on: a detailed, transparent analysis?” he said in an email to RTO Insider.
Both Lewin and Silverstein said the FERC-NERC investigation of Winter Storm Uri’s devasting power outages in Texas and elsewhere was largely ignored by the PUC. The report laid the blame for the nation’s largest controlled load shed at the foot of the natural gas industry and listed 28 recommendations to prevent a reoccurrence. (See FERC, NERC Release Final Texas Storm Report.)
“There was a lot of discussion at the legislature and in the press about how the 2011 recommendations were largely ignored,” Lewin said. “How seriously are we taking this more recent set of recommendations?”
ERCOT said in a statement that the PUC’s proposals “will require a lot of coordination among all the market participants and market experts,” calling them “the most significant and important changes … since [the market’s] migration to a competitive market almost a quarter-century ago.”
“ERCOT is glad to be able to assist the PUC in this effort and will continue to work closely with the agency to meet the aggressive timeline,” a spokesperson said.
“It is unprecedented to make so many substantive, market and cost changes with such minimal regulatory process and public and stakeholder input,” Silverstein said. “The pace and scope of the PUC’s decisions today may pass legal standards for Texas administrative law practice, but it violates sensible practices for sound public policy and public-interest decision-making.”
The open meeting was punctuated by almost 50 minutes of public comments, organized by the Sierra Club, Public Citizen and Texas Campaign for the Environment. The groups asked the PUC to prioritize public input in their decision-making and consider “people-first solutions.”
To make their point, the group’s members held up a symbolic power line, decorated with 350 icicles, each representing the names of 10 people asking the commission to weatherize the Texas grid to “protect and benefit the people of Texas, rather than the profits of Texas energy companies.”
The wide range of comments called for energy efficiency and demand response measures that decrease energy consumption. One speaker tearfully recounted her granddaughter being forced to go without power for 60 hours and then another 30 without water.
“You need to start being accountable to the people of Texas,” another person said.
Emma Pabst, a representative for the Sierra Club’s Beyond Coal Campaign, called for an energy grid “that works first and foremost for our communities.”
“The fossil fuel industry left us to die during the [February] freeze,” Pabst said. “Natural gas made $11 billion, while we were left to die in our homes.”
FERC on Thursday accepted PJM tariff changes covering non-rate provisions for black start service, including commitment and termination periods, as well as outage and substitution restrictions (ER21-1635-002).
The letter order directed a further compliance filing within 30 days to make agreed-upon revisions to an initial compliance filing that set forth details concerning the formulaic capital recovery factor (CRF) that the commission found essential to the rates, terms and conditions of black start service.
PJM Market Monitor Joe Bowring in April said the CRF table was originally created in 2007 and included incorrect assumptions. Black start unit owners and other stakeholders asserted that any changes to the CRF table should only be applied prospectively, and any rates currently in place should remain changed. (See PJM to File Black Start Proposal Without Members’ Endorsement.)
In October, PJM filed reply comments agreeing with the Market Monitor, explaining that the CRF formula used prior to June 6, assumed a 100-MW combustion turbine plant with a $1,000,000 capital investment. The RTO agreed that the formula no longer uses those assumptions and asked to remove the references to the assumed type of unit.
FERC opened a Notice of Inquiry on Thursday over the recovery of trade association dues in utility rates, with commissioners questioning whether customers should pay for groups that seek policies that may be contrary to consumers’ interests.
The NOI asks what portions of utilities’ dues paid to industry, civic and political associations are suitable for rate recovery (RM22-5).
The inquiry is a response to a petition filed by the Center for Biological Diversity, a conservation nonprofit that argued that association dues should be presumed to be non-recoverable through rates. Utilities should shoulder the burden of proving that such expenses should be recoverable, the group said. The group also sued the Tennessee Valley Authority over the issue in September. (See TVA Sued Over Contributions to Trade Groups.)
Under current FERC accounting rules, regulated utilities are allowed to recoup association dues, subtracting disclosed spending on IRS-defined lobbying activities.
FERC Chairman Richard Glick said the NOI will help FERC decide whether to modify its accounting and recording requirements.
“It appears that trade associations might not provide the utility company members with a sufficient level of detail as to which portion of a trade association’s dues should be recoverable and which should not, making it difficult for the commission to assess whether utilities are being excessively compensated by ratepayers or not,” Glick said at FERC’s open meeting.
Commissioner Allison Clements said the inquiry “in no way impinges on regulated utilities’ ability to advocate for any issue of interest.
“Regulated entities have every right to engage in outreach to influence public opinion on political issues; however, they do not have the right to pass through the cost of their outreach to the customer,” she said.
“At the minimum, it is a good housekeeping exercise to ensure that customers are not inappropriately left footing the bill for their electricity provider’s political aims, simply because they were taken on a by trade association instead of a regulated entity itself.”
Commissioner Mark Christie agreed that the NOI “is not a constitutional threat.”
“I don’t see it as threatening any corporations or trade associations’ speech rights,” he said. “The question here is not about the First Amendment; it’s about who pays for the expenses associated with speech.”
Christie pointed out that while state-regulated monopolies “may invest voluntarily,” their captive customers cannot buy voluntarily.
Christie said that FERC uses formula rates, a “very different system than in states where a utility comes in and has … the burden of proving that any expenditure is prudent.”
He added that he hadn’t prejudged any answer to whether FERC’s formula rate format is transparent enough. “It may be that the rules are fine. And maybe no changes are needed. But I don’t see a problem at all with putting this out for comment.”
Christie added that FERC should probably also consider whether its precedents on charitable and civic contributions should be codified. “I do not think that charitable and civic contributions by a state-granted monopoly should be recoverable from customers, period. That should not be allowed at all,” he said.
FERC Commissioner James Danly said he was dissenting on the NOI and would issue a later statement. He did not explain his opposition during the open meeting.
The California Public Utilities Commission on Thursday took steps to address two of the state’s major grid problems, resource adequacy and wildfires, by approving Southern California Edison’s request for a $1.2 billion storage project and slapping the utility with a half-billion dollars in penalties for blazes sparked by its equipment.
The decisions, reached in quick succession, came during the CPUC’s final meeting of 2021 and the last meeting for retiring President Marybel Batjer and Commissioner Martha Guzman Aceves, who is leaving for a top post at EPA.
The storage project, meant to improve summer reliability, would connect 535.7 MW of batteries at three SCE substations at an estimated cost of $1.226 billon. SCE said it will operate the storage resources as local distribution assets, not connected to CAISO, for five years. It will then transition the projects to “resources that participate in the wholesale market … [and] proceed through the interconnection process like any other customer.”
More than a dozen entities — including the CPUC’s Public Advocates Office, the Solar Energy Industries Association and the California Energy Storage Alliance — protested, challenging the cost of the project, its intended use and SCE’s interconnection plans.
The CPUC said it was not swayed by the objections and believed the project qualified under its prior procurement orders and Gov. Gavin Newsom’s emergency proclamation in July requiring the connection of additional resources to meet projected shortfalls by next summer. The five commissioners voted unanimously to approve it.
“We are facing a large gap in the amount of resources we have to ensure the reliability of our current grid in the face of the more extreme, climate-driven weather events that we saw earlier this summer and [that] we witnessed last summer,” Batjer said, referring to the derating in July of transmission lines linking the Pacific Northwest to California caused by a massive wildfire and the rolling blackouts of August 2020 in a severe Western heat wave.
“In this case, Edison has been able to leverage its unique position as an IOU and distribution operator to move forward with a shovel-ready project that can respond to our emergency procurement needs,” she said.
The project is expected to come online by Aug. 1, 2022, in time to meet summer reliability needs.
Wildfire Penalties
The CPUC next voted 4-1 to approve a settlement with SCE over the major fires of 2017/18 ignited by its equipment. The Thomas, Woolsey, Liberty, Meyers and Rye fires collectively killed at least five people, destroyed more than 2,700 structures and burned more than 385,000 acres.
Of the five blazes, the Thomas and Woolsey fires were by far the largest and most destructive.
The Thomas fire, which began in December 2017, was the biggest wildfire in state history at the time at 282,000 acres. It was surpassed by much larger fires, including two of approximately 1 million acres, in recent years.
The fire in Santa Barbara and Ventura counties killed two people and destroyed more than 1,000 homes. Subsequent flooding and debris flows in the burn-scar area later killed 21 residents and destroyed more than 100 homes. Without admitting liability, SCE settled with insurers for nearly $1.2 billion last year.
The Woolsey fire started in November 2018, killed three people, destroyed more than 1,600 homes and led to the evacuation of almost 300,000 residents in Los Angeles and Ventura counties.
The CPUC used its new, controversial procedure called an administrative consent order (ACO) to settle with SCE. The expedited process reduces the time it takes the commission to hold utilities accountable for safety violations in an era of regular, catastrophic wildfires. Other enforcement proceedings, such as the commission’s order instituting investigation, can take years to complete.
It was the second time the CPUC has used an ACO to settle with a utility blamed for starting wildfires. Earlier this month it approved a $125 million settlement with Pacific Gas and Electric over the 2019 Kincade Fire in Northern California’s wine country.
Commissioners voted 3-2 to approve the agreement between PG&E and the CPUC’s Safety and Enforcement Division that levied $40 million in fines and denied the utility $85 million in cost recovery for removing abandoned transmission lines. (See CPUC Assesses PG&E $125M for Kincade Fire.)
They voted 4-1 to approve Thursday’s settlement with SCE. Commissioner Genevieve Shiroma, who voted “no” previously, said she was satisfied the process had led to a better result with SCE than with PG&E. Commissioner Darcie Houck, who also voted against the PG&E settlement said she believed the ACO process lacked transparency and the opportunity for public participation, especially involving fires of such magnitude.
“I agree that this can be a flexible and useful tool that allows us to resolve things in a streamlined and efficient way where we are dealing with only penalties and not the extreme catastrophic events at issue here,” Houck said.
FERC on Thursday ordered transmission providers to end the use of static line ratings in evaluating near-term transmission service, a move the commission said will improve accuracy and transparency and increase utilization of the grid (RM20-16, Order 881).
The order requires transmission providers to employ ambient-adjusted ratings (AARs) for short-term transmission requests — 10 days or less — for all lines that are impacted by air temperature. Seasonal ratings will be required for long-term service.
The commission said the current practice — in which line ratings are typically based on conservative assumptions about worst-case, long-term air temperature and other weather conditions — has caused underutilization of available transmission capacity.
“This is a pretty big deal,” Chairman Richard Glick said at the commission’s open meeting. “We’ve spent a lot of time over the last several months talking about the need for substantial investments in new transmission capacity, and there is a significant need for these investments. But at the same time, we need to squeeze more out of the existing grid.”
The final rule did not mandate the use of dynamic line ratings (DLRs), which the commission said should be more accurate than AARs by incorporating not only forecasted temperatures, but also other weather conditions such as wind, cloud cover, solar irradiance intensity, precipitation, and line conditions such as tension or sag. DLRs also can provide situational awareness, alerting operators if a line is over its capacity.
But the order does require that organized market operators allow transmission owners that would like to use DLRs the ability to do so. FERC also ordered RTOs and ISOs to create systems and procedures to allow transmission owners to electronically update transmission line readings at least hourly.
The order also rejected the NOPR’s proposal to “stagger” implementation of AARs on historically congested lines first, followed by all lines. The order requires transmission providers to submit compliance filings within 120 days of the rule’s publication in the Federal Register and to implement the rules within three years after that.
Worst-case Assumption
In a presentation to the commission, Dillon Kolkmann of the Office of Energy Policy and Innovation, said that transmission line ratings are often based on worst-case assumptions, for example, a hot summer day. “Atmosphere and weather conditions vary day to day and hour to hour. But seasonal or static ratings are typically updated only when equipment is changed or weather assumptions are revised,” he said.
As a result, such ratings often result in less transfer capability than the system can actually provide, resulting in unnecessary congestion costs, curtailments and redispatch orders.
Kolkmann said seasonal and static ratings may also overstate near-term transfer capability, creating reliability risks.
Glick said the evidence gathered to date was insufficient to determine “the incremental benefits, costs and risks associated with dynamic line ratings.” The commission opened a new proceeding (AD22-5) to build the evidentiary record further.
Commissioner Allison Clements said she hoped that new rules also would result in more accurate signals about where investments in new transmission facilities are needed.
“I want to stress that this rule is not [the end of] efforts to improve existing system efficiency, but instead represents an important first step,” she said. “The record in this proceeding does demonstrate that dynamic line ratings may provide even more accurate line ratings than ambient adjusted ratings, and therefore even greater reliability and economic benefits to consumers. In my mind, these are benefits we can’t afford to leave on the table.”
How Much More?
LineVision Inc., which provides transmission technology for AARs and DLR, claims its solutions can “unlock up to 40% additional capacity.”
The Electric Power Research Institute said that DLR is more costly than AARs because it requires “placing sensors in remote locations, ensuring the cyber security of sensors, and various additional costs.”
AARs are widely used in PJM. The RTO told the commission that AARs provide “significant operational value [and] allows for the realization of additional incremental capability on the system.”
PJM is conducting DLR pilot programs with PPL and AEP. In a study of a hypothetical installation on one of its most congested lines, PJM said DLRs could provide a payback of the estimated $500,000 equipment installation cost in two months through reduced congestion payments.
In its comments, the Electric Power Supply Association was generally supportive of moving to DLR but warned it “could have some unintended impacts with respect to day-ahead and real-time price convergence.
“While such an impact ultimately may not be negative or significant, it is nonetheless important to ensure that the RTOs consider the issue,” EPSA said.
ITC Holdings told the commission in April that “AARs should not be seen as a panacea to the needs of the transmission system.”
The company said it agreed with the Organization of MISO States (OMS) that AARs “should not be implemented on facilities where it is not economic or reliable to do so.
“A collaborative approach among stakeholders will allow the identification of the facilities that will provide the most benefit to electric customers from the use of AARs,” ITC said. “This is of particular importance in MISO where the Transmission Owners have worked over more than the past 18 months to develop an AAR conceptual framework to evaluate candidate facilities and begin the process of program development.”
FERC said Thursday that MISO and SPP can use a predictive flow factor process to offset overlapping congestion charges between the RTOs on pseudo-tied loads and resources (EL17-89, et al.).
However, the commission said the grid operators are not off the hook in refunding past excessive congestion charges.
FERC said the organizations can use the new process, which entails using forecasted rather than historical data, to determine the relief necessary on a market-to-market (M2M) flowgate. MISO and SPP said a predictive process will allow them to provide more precise redispatch relief on constraints.
The RTOs pledged to use the process in the first couple of intervals after an M2M event begins. The update to their joint operating agreement will become effective at the end of March 2022, when the RTOs will complete software design and testing.
FERC agreed that the solution would dramatically cut or reduce the duplicative charges.
The commission said in late 2019 that it would investigate overlapping congestion charges between the grid operators after complaints from American Electric Power (AEP) subsidiary Southwestern Electric Power Co. and the city of Prescott, Ark. FERC has since held a technical conference on the matter, ruling that MISO and SPP must correct the problem and rejecting challenges from the RTOs. (See FERC Upholds Decision on MISO-SPP Overlapping Charges.)
AEP and Prescott argued that it won’t be clear for months whether the new process is a sufficient solution and asked FERC that its acceptance be conditional. The commission responded that the predictive flow factor remedy should represent an improvement over the RTOs’ “uniquely excessive” congestion charges, reminding AEP and Prescott that “the RTOs cannot provide perfectly calibrated redispatch to match the exact congestion relief required.”
However, FERC ordered the grid operators to submit three annual joint informational reports through early 2025 to describe whether the solution works in practice and to list any post-implementation challenges.
FERC: Refunds in Order
FERC set hearing and settlement judge procedures to establish appropriate refunds due to AEP and Prescott.
The RTOs had said the refunds would be too onerous to calculate. They said the calculations would be tantamount to re-running the market and asked FERC to exercise its discretion in not ordering the refunds.
MISO and SPP said that “by only correcting the relief amount during any given interval, without taking into account the many variables that occur during real-time operations, the results of the calculations would be, at best, an unverifiable estimation.”
FERC countered, “We believe that providing recovery to AEP and Prescott for the unjust and unreasonable overlapping congestion charges they incurred during the refund period outweighs the RTOs’ concern that calculating refunds for AEP and Prescott would be burdensome and lead to unverifiable estimates.”
Before proposing their solution, MISO and SPP had argued that though duplicative congestion charges are possible for their pseudo-tie transactions, mechanisms such as virtual transactions, financial transmission rights and firm flow entitlements counteract double charging.
MISO maintained that congestion charges on the RTOs’ pseudo-tied generation don’t require special tariff remedies similar to the measures it took to correct double charging with PJM. MISO said it did not experience near the pricing impacts that it used to with PJM transactions.
NERC’s Standards Committee approved a revised charter and standard authorization requests (SARs) for its MOD and PRC rules in its year-end meeting Wednesday.
Reactive Power Measurements
The committee accepted SARs for Project 2021-01, which is considering changes to MOD-025 (Modeling, Data, and Analysis) and PRC-019 (Protection and Control).
The Power Plant Modelling and Verification Task Force (PPMVTF) developed a SAR to revise MOD-025-2 to address problems with the verification and data reporting of generator active and reactive power capability. The task force said the existing standard has rarely produced data suitable for planning models although that is its purpose.
Most testing cases are undermined by limits within the plant or system operating conditions that prohibit the generating resource from reaching its “composite capability curve.” The standard drafting team hopes to correct these issues so that equipment owners can produce suitable and accurate data during verification activities.
PRC-019-2 seeks to addresses miscoordination among generator capability, control systems, and protection functions, but does not sufficiently outline the requirements for non-synchronous generation, a problem identified by the System Protection and Control Subcommittee (SPCS). The SAR seeks to revise the standard to apply to all generation types.
The Planning Committee endorsed a third SAR in December 2019 concerning the potential risk of increasing amounts of reactive power being supplied by nonsynchronous sources. But the SAR drafting team revised and consolidated the three SARs into two.
Marty Hostler of Northern California Power Agency questioned why the SAR wasn’t reposted after the drafting team made changes in response to industry comments. “I saw a lot of negative comments,” he said. “And I’m just curious why it hasn’t gone out again for additional commenting after all the adjustments were made?”
NERC Senior Standards Developer Latrice Harkness said NERC rules don’t require reposting the SAR after it has been reviewed by the SAR drafting team. “The comments for consideration … were posted back in November for review,” she said. “The team has worked to consider those comments.”
Transmission Relay Loadability
The committee also approved a SAR for Project 2021-05 that was submitted by the System Protection and Control Working Group to modify PRC-023 to address potential reliability issues resulting from confusion regarding the standard.
The standard is intended to ensure protective relays are set so they do not trip unnecessarily during heavy loading conditions while still being capable of detecting all fault conditions.
The SAR said some entities have disabled their power swing blocking (PSB) relays because of internal conflicts within the standard, which could lead to tripping during stable power swings. The SAR calls for removing or modifying Requirement R2 “because it has been interpreted to restrict the setting of PSB elements making determination of appropriate settings more difficult and making compliance with PRC-026 more difficult.”
Engineer Philip Winston questioned why the SAR continues to list the System Protection and Control Working Group as the sponsor even though it was changed after the working group submitted it.
“I’m a little concerned over the fact that this revision to the … SAR has never gone back to the [working group]. So to show it that they are sponsoring it, in my opinion, is incorrect,” he said. “And I have confirmed that with the chair of the [working group] that he has not been informed of the changes that have been made.”
“Once a SAR is submitted to the Standards Committee, it actually becomes part of the Standards Committee and the process there,” said Howard Gugel, NERC’s vice president of engineering and standards. “We do not typically go back to the original submitter and ask that submitter to review any changes that were done based on public comments.… That has been a common practice for us.
“In other words,” Gugel said, “the submitter doesn’t own the SAR anymore. It’s actually owned by the Standards Committee.”
The committee approved the SAR with the notation that it was “as revised by the SAR drafting team based on comments.”
Committee Charter Approved
The committee also approved a revised committee charter in response to a charge from the NERC board in November that it further amend the document — last updated in 2019 — to ensure clarity about its role and that it has the “agility” to respond to urgent reliability concerns.
Committee Chair Amy Casuscelli of Xcel Energy said the changes include additional language to clarify the committee’s role as a “process committee,” additional references and linkages to the Standard Processes Manual section of the Rules of Procedure, and a section on waivers to highlight the committee’s “ability to act with agility in the face of urgent need.”
The revised charter states that the committee “shall provide oversight of the reliability standards development process to ensure stakeholder interests are fairly represented” but that it “shall not under any circumstance change the substance of a draft or approved reliability standard.”
It also includes a new section allowing the committee to waive some steps in the Standard Processes Manual if needed to act quickly to meet “a time constrained regulatory directive” or meet “an urgent reliability issue.”
Call for Volunteers
NERC Board Member Jim Piro ended the meeting by thanking the committee for its work in 2021.
“It’s been a very busy year, and I’ve been really impressed with the attention to detail that the committee takes in doing their work,” he said. “And I will tell you that the work is not going to end … There’s a lot of important issues ahead of us in terms of looking at the changing grid as it decarbonizes.”
Piro acknowledged concerns about “industry fatigue” and the need to get resources from the industry to work on future SARs.
Charles Yeung, executive director of interregional affairs for SPP, and chair of the Project Management and Oversight Subcommittee, echoed Piro’s concern, saying the (PMOS) will be seeking new members in 2022.
“We had 11 members on PMOS. … Three of those 11 members did not re-up their membership for the next year, and we did not get any new nominations this year,” said Yeung. “… So, I invite anyone on the committee or folks that you know from your organizations to nominate.”
Casuscelli reappointed Michael Brytowski, of Great River Energy, as vice chair of the PMOS.
Point-to-point reservations across the seam | Organization of MISO States