New York Department of Public Service staff on Wednesday recommended a 58% funding increase for the state’s EV Make-Ready Program for electric vehicle infrastructure.
When it created the program in July 2020, the Public Service Commission stipulated a midpoint review. The DPS’ white paper published Wednesday updates the PSC on the progress made to date and recommends a series of changes for the commission to make.
The recommendations reflect data and feedback gathered in the nearly three years since the order was issued, including through a series of technical conferences with the investor-owned utilities that are carrying out the program — Central Hudson Gas & Electric, Consolidated Edison, National Grid, New York State Electric and Gas, Orange and Rockland Utilities, and Rochester Gas and Electric — and other stakeholders. (See Inflation Hampering Efforts to Expand EV Charging Network in NY.)
Installing charger plugs has proved to be more expensive than was projected in 2020, and analysis has indicated a different mix of direct current fast chargers (DCFC) and Level 2 chargers should be incentivized.
The 2020 order authorized the utilities to spend $701 million in ratepayer money to help reach a buildout target of 53,733 L2 plugs and 1,500 DCFC plugs. Staff are recommending that be changed to $1.11 billion to incentivize buildout of 43,122 L2 plugs and 6,302 DCFC plugs.
Buildout through the Make-Ready Program has also been slower than anticipated.
Only 4% of the original L2 goal and 14% of the original DCFC goal had been completed as the midpoint review was prepared. With the addition of projects committed but not completed, the totals rise to 23% and 42%, respectively.
The pace was such that all six utilities failed to qualify for incentives through the earnings adjustment mechanism specified for L2 chargers, and only National Grid reached the midpoint goal that would qualify it for a DCFC incentive.
The Make-Ready Program supports New York’s landmark Climate Leadership and Community Protection Act of 2019, which mandates a 40% reduction from 1990-level greenhouse gas emissions by 2030 and an 85% reduction by 2050.
The transportation sector is a major source of those emissions. A 2022 New York law mandates that a gradually increasing percentage of passenger vehicles sold in the state be EVs, reaching 100% by 2035. For that to happen, many more publicly available chargers will be needed.
“At the time the Make-Ready order was issued, the commission was confident that the electrification of the transportation sector would help attain the goals of the CLCPA,” DPS staff wrote. “In the three years since the Make-Ready order was issued, it has only become clearer to DPS staff that the electrification of the transportation sector is paramount to the achievement of the goals of the CLPCA.”
The following recommendations by the DPS staff are among those included in the white paper:
Continue to limit administrative costs to 15% of the original program incentive budget in the 2020 order.
Budget $25 million for micromobility charging, for devices such as electric bicycles, skateboards and scooters, and earmark $20 million of that for the New York City area.
Boost the budget for the medium- and heavy-duty vehicle make-ready pilot program from $24 million to $54 million.
Shrink the eligibility radius for the enhanced funding offered for siting L2 chargers in disadvantaged communities, so that wealthier surrounding communities do not benefit.
Seek continued input to shape a workforce development program focusing on disadvantaged communities.
Direct the Technical Standards Working Group to identify barriers to vehicle-to-grid integration and propose solutions.
Convene a technical conference to streamline the collection of charger site data, which is critical to achieving the goals of the Make-Ready Program but has proved challenging to carry out.
Seek additional shareholder input and analyze it before modifying or expanding the transit electrification efforts authorized in the 2020 order.
Do not move forward with consideration of a make-ready program for installation in private residences, because brisk EV sales suggest such incentivization is not necessary.
PJM stakeholders are requesting that the Board of Managers provide more information about its initiation of a fast-track process to address reliability concerns, which it announced in a letter published last month.
“This is not giving us any clear direction … and I think that we’re going to waste a lot of time if we don’t get some clear direction,” Paul Sotkiewicz, president of E-Cubed Policy Associates, said during the Feb. 28 meeting of the Resource Adequacy Senior Task Force.
The board released the letter Feb. 24 in response to “numerous data points suggesting that grid operators may face challenges in maintaining reliability during the transition,” as shown in a white paper released by PJM the same day detailing an imbalance between future resource development and retirements through the rest of the decade. (See PJM Board Initiates Fast-track Process to Address Reliability.)
Invoking the Critical Issue Fast Path (CIFP) stakeholder process, the board identified a set of key work areas it would like to see addressed by proposals for it to consider and potentially send to FERC by Oct. 1.
The four primary areas the board identified include revising the Capacity Performance (CP) model and ensuring any penalty risks can be accounted for in capacity offers; improving resource accreditation to ensure that reliability contributions are accounted for and compensated; enhancing risk modeling to improve understanding of winter risk and correlated outages; synchronization between the Reliability Pricing Model and the fixed resource requirement rules to ensure that supply and demand are held to comparable standards.
Steve Lieberman of American Municipal Power said the letter is eliciting a lot of questions from stakeholders and it would be beneficial for representatives of the board to attend one of the upcoming Markets and Reliability Committee meetings to set the grounds of what they’re looking for in a solution package.
“If we’re going to be jumping through hoops for the next six [or] seven months, let’s make sure we’re jumping through the right hoops,” he said during the RASTF meeting.
Vice President of Market Design Adam Keech said PJM’s understanding of the board’s intent with the letter was to avoid steering stakeholders in the direction of a specific solution, but to identify areas of importance that a solution must address.
“I think this is the scope we have to work with, and it was written for this reason,” he said.
Going through the work areas, Keech noted that many of them have long been under discussion by stakeholders before giving PJM’s interpretation of each of them. Regarding any changes to the CP construct, he said the board believes any risk generators face from penalties should be reflected in their market seller offer cap.
“I see the board saying ‘review CP’ in terms of Winter Storm Elliott and the market seller offer cap,” he said. In the wake of the December 2022 storm, PJM announced that generators could face $1 billion to $2 billion in CP penalties, which has prompted many generators to say they are not adequately able to incorporate the risk of future penalties in their capacity offers. (See PJM Weighs Options for Winter Storm Elliott Follow-up.)
Keech said PJM believes the board wants to incorporate growing risk during winter months into the calculation of reliability requirements.
He also said PJM is likely to pursue a marginal accreditation framework for its effective load-carrying capability method, whereas it currently uses an average, though he acknowledged stakeholders can opt to move in a different direction.
Part of the board’s letter noted that it is interested in exploring if any changes made can be implemented before the 2027/28 Base Residual Auction. But state consumer advocates said any delays to future capacity auctions could interfere with states that procure their own capacity.
“I know that is a concern for at least some of the auctions: further delays and how that affects state auctions,” said Greg Poulos, executive director of the Consumer Advocates of the PJM States.
David “Scarp” Scarpignato said he would like to see additional information about the impact auction delays could have on states at future meetings. He also encouraged PJM to create a framework for presenting the particulars of any proposals that may come forth in an easier-to-read format than the matrix that is typically used, predicting that the process of drafting packages is likely to be “unwieldy.”
“I don’t think someone is going to be able to read a 100-line matrix and understand what it’s saying,” he said.
PJM’s Dave Anders gave an overview of a target roadmap for drafting and voting on packages, with first reads anticipated in June and votes at the MRC and Members Committee in August and September, respectively. Anders and Keech told the task force that the RTO plans to present a draft problem statement, issue charge and proposal, with a target posting date of March 13.
The Market Implementation Committee will continue the discussion of potential auction delays during its March 8 meeting, as well as at the March 15 RASTF.
AUSTIN, Texas — ERCOT staff reported to the grid operator’s Board of Directors last week that despite “not insignificant” forced outages during the December winter storm, it set a new winter demand record and supported “reliable execution throughout event.”
Fossil fuel outages from fuel restrictions and cold weather spiked in the early-morning hours of Dec. 23, knocking more than 14 GW of generation offline at one point. Fortunately for ERCOT, wind resources, the early fall guys during the deadly February 2021 storm, helped fill the gap with about 30 GW of energy at times during the night Dec. 22-23.
“This is a great example of the dependency we have on renewables, because for part of the 22nd and the 23rd, we were in renewable territory,” Director John Swainson said during the board’s Feb. 28 meeting. “If the wind had stopped blowing, we would have been in deep [expletive].”
“As load shot through our forecast, we needed another [6,000] or 7,000 MW,” Texas Public Utility Commission Chair Peter Lake said.
Stoic Energy principal Doug Lewin — who follows ERCOT and, among other data, its forced outages — told RTO Insider that about 25 GW of capacity was offline at some time between Dec 22 and 24. ERCOT went into the event with 6 GW already offline, despite the lack of snow and ice, he said.
The grid operator’s data included 655 individual outages at 348 units, peaking at close to 20 GW during the storm. Initially, 127 outages were considered weather– or fuel supply–related, with a high of almost 4.5 GW. Outages or derates at 97 units were considered weather related (35 were wind), and another 30 were caused by fuel issues; 23 of the latter were at gas units.
Almost 1.5 GW of large flexible loads, such as data centers and bitcoin miners, responded to market prices and curtailed their usage. ERCOT also deployed a total of about 2.5 GW of firm fuel supply service to make up for gas restrictions in North Texas.
Like other grid operators during the storm, ERCOT underestimated the drop in temperatures and its effect on load. In the days before the storm, staff had projected demand would almost reach 70 GW. Instead, it peaked at 73.9 GW on Dec. 23, more than 4 GW than the official record peak set during the 2021 storm and its load shed.
“It was a fairly successful event from a risk perspective. It was also one of the coldest events that we’ve seen in the last 15 years,” said Dan Woodfin, vice president of system operations, referencing the more recent storm. “The key message here is that this under-forecast didn’t have any impact on reliability because pretty much all the generation was all buying, and so we were prepared for much higher load than what actually occurred.”
Woodfin said national weather models underestimated “how quickly and how deep” the storm arrived in Texas. Dec. 22-23’s load-weighted daily minimum temperatures of 13.4 and 16.3 degrees Fahrenheit during the December event were lower than all but two of the 2021 storm’s days.
He said the load-forecast models “overplayed” the demand reduction from businesses shutting down for the holiday weekend and were unable to rely on historic data without load shed for the temperatures. Staff have since identified lessons learned and begun improving the forecast models with a focus on extreme cold events, Woodfin said.
ERCOT is still investigating the forced outages’ root causes.
Carrie Bivens, ERCOT’s Independent Market Monitor, attributed prices that peaked at $4,500/MWh on Dec. 22 to the normal economic dispatch of energy storage resources.
“It was fairly significant pricing event,” she said. “The reason the prices were high is price-setting resources were energy storage resources during that time. They typically have high opportunity costs and high offers, and they were mostly setting the price during that time.”
She said the issue was an example of a case in which real-time co-optimization would have had an effect. The IMM has for several years pushed the market tool’s implementation, which is currently sidelined by the state’s market redesign efforts.
Vegas Applauds Sunset Review
ERCOT CEO Pablo Vegas told the board that the grid operator supports recommendations made following a review by the state’s Sunset Advisory Commission.
“Fundamentally, I think some of the changes can be summarized as improvements to communication, making sure that when we communicate information and reports; … that we’re clear [and] transparent, and we take out the engineering jargon,” he said, “and that what we’re recommending needs to happen in order to always keep reliability at the forefront.”
The commission, which also simultaneously reviewed the PUC and the Office of Public Utility Counsel because of their interrelated responsibilities, recommended:
process changes so ERCOT can restrict the commissioners’ presence during executive sessions and to better define the sessions;
adding a second commissioner to the ERCOT board as a non-voting member;
requiring ERCOT to send a biannual industry report to the legislature;
directing ERCOT and the PUC to re-evaluate the grid operator’s performance metrics and create a public communication guidance document; and
ordering ERCOT to include appropriate budgetary funding for “qualified” economic planning staff.
Under state law, ERCOT, the PUC and OPUC, as do all state agencies, undergo regular sunset reviews to assess their continued need and their programs’ efficiency. The Legislature will consider the sunset commission’s recommendations when the report is filed and make final decisions before its session ends May 29.
Directors Approve Rule Changes
The board approved seven nodal protocol revision requests (NPRRs) and single changes to the Planning Guide (PGRR) and Retail Market Guide (RMGRR) previously endorsed by the Technical Advisory Committee:
NPRR1144: provides a limited exception to the requirement that loads included in an ERCOT-polled settlement metering facility’s netting arrangement only be connected to the grid through the facility’s metering point(s). The exception would allow no more than 500 kW of auxiliary load connected to a station service transformer be connected to a transmission or distribution service provider’s (TSP/DSP) facilities through a separately metered point using an open transition load transfer switch listed for emergency use.
NPRR1147: sets fast frequency response’s ancillary service offer floor 1 cent/MW lower than other responsive reserve services categories to allow fast frequency response’s procurement up to the current limit, without proration with other categories.
NPRR1149: charges qualified scheduling entities (QSEs) an ancillary service failed quantity if their supply responsibility is not met in real time by their portfolio’s resources, based on a comparison of their real-time telemetry.
NPRR1151: eliminates the protocol requirement that the Protocol Revision Subcommittee hold at least one meeting per month.
NPRR1153: adds two existing fees (public information request labor and ERCOT training) to the grid operator’s fee schedule; creates a $500 registration fee for resource entities, TSPs and DSPs, and subordinate QSEs; deletes the system administration fee’s current value and the map sales fee; and restructures existing fees for generator interconnection or modification, full interconnection study applications and wide-area networks.
NPRR1158: eliminates the weatherization-inspection fee’s sunset date and changes its invoicing period from a quarterly to a semiannual basis.
NPRR1159: provides needed references to the Retail Market Guide accounting for Texas standard electronic transaction processing options for municipally owned utility or electric cooperative service areas. The change is aligned with RMGRR171, which adds language establishing the mechanism that opt-in munis or co-ops without an affiliated provider of last resort (POLR) that have not delegated authority to designate POLRs to the PUC would follow to provide their initial POLR allocation methodology; and updates and confirms such allocation methodology.
PGRR102: requires resource entities and interconnecting entities to provide operations dynamic model quality test results that demonstrate appropriate performance for submitted operations dynamic models, and makes non-substantive clarifying changes.
The board also approved:
Vegas’ selection as CEO and the corporate officers’ ratification;
CARMEL, Ind. — MISO’s attempt last week to justify a sweeping new resource accreditation process gave way to heated debate over how to best alleviate the footprint’s reliability challenges.
The RTO has proposed accrediting all resources based on their performance during predefined resource adequacy hours, or tight operating conditions. It will then adjust unit accreditation by a capacity value determined by loss-of-load expectation. The equation’s direct LOLE piece would replace the grid operator’s use of unforced-capacity values that rely on historic forced-outage rates.
The proposed probabilistic, direct loss-of-load hours calculation would have MISO filing edits at FERC to its availability-based accreditation design for thermal resources that was approved last year. It would also eventually assign solar generation near-zero capacity credits by 2031, based on their marginal value.
During a Feb. 28-March 1 Resource Adequacy Subcommittee (RASC) meeting, MISO adviser Davey Lopez said staff still believes a direct loss-of-load approach is an improvement over the status quo’s accreditation. He said MISO’s responsibility is to accredit resources based on their availability at times of greatest risk, even as that risk profile fluctuates.
“We know that there’s a rapid rise in solar coming, and we know that solar is going to shift periods of risk to late-afternoon and early-morning hours,” he said.
Lopez said a direct loss-of-load methodology balances known operational risk with probabilistic future risks.
“It’s a wide range of reliability risk that we’re capturing, and that’s why we’re proposing the direct LOLE approach. Change is coming; risk is shifting,” he said, adding that the design “better informs the future” while providing stability now.
MISO currently has 23 GW of solar resources with executed generator interconnection agreements that have yet to come online.
Lopez said MISO will propose a three-year transition to the accreditation method, which aligns with an influx of in-service dates for solar generation. It intends to seek the design’s approval from FERC by the end of the year.
Some stakeholders said it’s inappropriate for staff to send forward signals with accreditation instead of simply reflecting a resource’s capacity contribution. They said effectively reducing solar generation’s capacity credit to zero isn’t the solution during the clean energy transition.
Entergy’s Wyatt Ellertson asked whether the RTO intends to incent the market to cease investment in the solar fleet by assigning it little to no capacity value. He said if all MISO’s solar is retired, the daytime risk that solar had mitigated will resurface.
“Accreditation needs to capture availability during reliability risk hours. Period. It’s as simple as that,” Zakaria Joundi, director of resource adequacy coordination, said. “We’re not looking into why the risk is shifting. We’re looking into the risk hours and the reliability contribution of all resources.”
January’s tense accreditation discussion gave rise to two stakeholder motions introduced at the RASC: one denouncing the direct loss of load approach and another calling on MISO to share analysis behind its accreditation philosophy.
MISO’s environmental sector said the grid operator has displayed a “relative lack of transparent data supporting the proposal,” with stakeholders not privy to “any of the probabilistic analysis supporting” a change in resource accreditation.
The sector added that stakeholders don’t yet know which risky hours would be singled out under the direct loss-of-load approach.
“The best way to resolve these concerns is through the evaluation and discussion of transparent analytical data supporting MISO’s proposal, rather than discussion guided mostly by narrative,” sector representatives said.
“I think we’re a long way from understanding how this actually works,” Minnesota Power’s Tom Butz said in agreement. “It can’t be just platitudes of how the system risk is changing.”
Sustainable FERC Project senior advocate Natalie McIntire said staff appears “too wedded” to the direct loss-of-load approach.
WEC Energy Group’s Chris Plante also lodged opposition to the design with a stakeholder motion. He said, “any marginal approach to resource accreditation is inconsistent with MISO’s existing resources adequacy construct.”
Plante said MISO’s current prompt-year capacity auction design doesn’t pair well with an accreditation that attempts to send investment signals. He argued that the capacity auction design is residual in nature and was never intended for members to fully procure their capacity needs.
Senior VP Makes Rare RASC Appearance
MISO Senior Vice President Todd Ramey made an unusual visit to the RASC meeting. He reminded stakeholders that MISO Midwest last year came up short against its planning reserve margin requirement in the capacity auction. He said while installed capacity additions are on the rise over the past five years, accredited capacity is on a downward slide.
As a result, Ramey said, the methods for counting available capacity are more important than ever.
“That is the primary reason we’re having discussions about how we approach accreditation,” he said.
A capacity shortage may play out again this year in the seasonal auctions held at the end of March. The RTO reported that Illinois’ Zone 4, Missouri’s Zone 5, Indiana’s and Kentucky’s Zone 6 and Michigan’s Zone 7 appear to have smaller amounts of accredited capacity available this summer versus their planning reserve margin requirements. MISO Midwest has almost 98 GW in accredited capacity to meet more than a 99-GW requirement, staff projected. They said the region will likely require assistance from either load-modifying resources, MISO South’s predicted capacity excess, or external capacity contributions to avoid a deficiency.
While other seasons show zonal deficits in midwestern zones and Texas’ and Louisiana’s Zone 9, no other season exhibits risk for a region-wide capacity shortage.
MISO’s Durgesh Manjure said he couldn’t conclusively say whether the grid operator will avoid a shortfall in the capacity auctions.
“System risk is shifting from being driven by peak load today, to being driven by the unavailability of weather-dependent resources — primarily solar — in the future,” he said.
McIntire cautioned MISO against categorizing resources as either strictly “weather-dependent or controllable,” saying “that doesn’t serve anyone well.”
“Wind and solar are controllable,” she said.
Ramey said MISO agrees that other kinds of resources beyond wind and solar can be weather-dependent.
Customized Energy Solutions’ David Sapper said MISO could adopt the phrase, “dependably capable of ramping up,” to describe the resources it’s looking for.
Butz asked Ramey how MISO intends to address the “common conclusion” that there’s a gap between the intermittent resources in the IC queue and the level of on-demand resources it needs.
“I’m taking advantage of your title in this organization to ask how this plays out,” Butz said.
Ramey said MISO and members must enter a “paradigm change” in reliability planning. He said staff stands ready to work with stakeholders on an appropriate accreditation process and implementing a sloped demand curve to better value capacity in the seasonal capacity auctions.
“MISO doesn’t make retirement or investment decisions. You all do,” Ramey told stakeholders. He said, “all MISO can do” is provide its most accurate insights to inform decision making.
Clean Grid Alliance’s Beth Soholt said MISO hasn’t adequately explored the reliability value of the energy storage and hybrid resources in the IC queue. She said the spike in storage queue applications is a response to the RTO’s call for dependable resources.
“It might only be four-hour batteries, but we haven’t fully the run the ground in what batteries can do for the reliability problem,” Soholt said. “Saying we don’t have the right resources in the queue, that’s not the case.”
Bill Booth, a consultant to the Mississippi Public Service Commission, disagreed that MISO isn’t trying to guide generation investment decisions, noting the RTO is considering marginal, declining capacity credits for solar generation as more come online. Booth said the design effectively means the grid operator is “marching down the path” to making solar facilities energy-only and incapable of serving as capacity resources. In that case, they would be rendered useless in the footprint, Booth argued.
“I think you need to listen to the states here: no effect on cost and no effect on our [planning reserve margin requirement],” Booth said of changes to its resource adequacy construct.
Sapper said he took issue with MISO’s approach to resource adequacy, questioning why staff took liberties with its most recent regional resource assessment by envisioning “an optimistic, or ‘best case’ view” of capacity additions. He questioned why projections differed from MISO’s annual resource adequacy survey that is conducted in partnership with the Organization of MISO States. (See OMS-MISO RA Survey Says Supply Deficits Could Top 10 GW by 2027.)
Sapper asked whether MISO is angling for a regional resource-planning process.
“There’s no hidden agenda here,” Ramey said. “We realize we don’t have authority to make these decisions. The only possible path forward here is to partner with those who are in the driver’s seat on investment and retirement decisions.”
“I’m not buying it,” Sapper responded.
“I think we’re at an inflection point in the history of MISO,” Plante argued.
Plante said the capacity market has evolved from its “humble beginnings” of a voluntary reserve-sharing group among load-serving entities. He said MISO and stakeholders should reestablish what they want from their capacity market.
“Do we want a full-blown capacity market? If we do, I think we need to stop putting lipstick and eyelashes on our current RA construct,” he said. “We need to start over from the ground up.”
Plante said a full compulsory capacity market might mean that MISO conducts forward auctions.
FERC last week rejected SPP’s capacity accreditation methodology for wind and solar resources on procedural grounds and granted clean energy interests’ rehearing request of its prior acceptance.
The commission on Thursday agreed with arguments that it had erred in its August 2022 order accepting SPP’s proposed tariff revisions to accredit wind and solar resources based on historical performance using an effective load-carrying capacity (ELCC) methodology. FERC accepted the proposal subject to the condition that the RTO revise its tariff to include additional details about the methodology (ER22-379).
Clean energy advocates — comprising the American Clean Power Association, Advanced Energy United, the Solar Energy Industries Association, Sustainable FERC Project, Natural Resources Defense Council, Advanced Power Alliance and Sierra Club — appealed the order.
They claimed FERC erred by accepting a Federal Power Act Section 205 filing that omitted tariff details that would significantly affect rates, terms and conditions of service. They contended the order failed to satisfy the rule of reason while also determining that these “manifest flaws” could be remedied by a later compliance filing.
The advocates said SPP’s new capacity accreditation methodology is not “some minor technical modification; rather, it is a new ‘complex’ rate scheme that represents a ‘substantial market design change.’” They charged the commission with relying on generalities rather than specific tariff language, noting that “specific critical elements of SPP’s methodology, including the determination of the base and change cases and the definition of seasonal net peak load, were missing.”
Upon consideration of the arguments, FERC said Section 205 and its regulations require that rates be “clearly and specifically” stated to ensure adequate notice of the proposed rate. It said it accepted SPP’s accreditation methodology without a definition of seasonal net peak load, thus resulting in a lack of adequate notice.
The commission encouraged SPP to expeditiously submit any future filing in the proceeding and found its compliance filing moot.
An SPP spokesperson said the grid operator is reviewing the order and will work with stakeholders to address the next steps.
“As FERC noted, the order has an impact on reliability, so SPP will proceed with reliability as the top consideration,” Meghan Sever said in an email.
The advocates celebrated the decision, arguing that fossil fuel resources, not renewables, have their own issues with intermittency.
“FERC did not address the underlying flaws in SPP’s approach, which clean energy advocates say ignores the risks of SPP’s large fleet of coal and gas plants going offline when needed most,” they said in a joint press release. “Clean energy advocates urge SPP to overhaul its approach to ensure that fair accreditation rules are applied to all resource types.”
“We’ve seen repeatedly over the last few years that fossil fuels fail when electricity is most needed. SPP has been given another bite at the apple to take this into account and evaluate renewables in a considered and fair manner,” Caroline Reiser, an NRDC senior staff attorney, said in a statement. “Fossil fuels are not infallible, and customers will lose out on reliability and affordability so long as grid operators continue to over-reward underperformance.”
Commissioner Allison Clements concurred in a separate statement and posted a Twitter thread explaining her decision, calling the order “an important course correction.”
“As I argue in my concurrence, SPP proposal unduly discriminated against wind and solar resources, over-crediting other types of generation by comparison,” she said. “SPP’s proposal was unjust and unreasonable because it penalizes wind and solar resources for outages while simultaneously declining to adjust the credit of other resources when they experience outages. As SPP goes back to the drawing board, I strongly urge it to develop a fair capacity accreditation methodology that is consistent across all resource types.”
Commissioner James Danly dissented on procedural grounds, arguing that the decision’s reasoning “fails to address the merits at all.”
“Were there procedural defects, we should have cured them in the course of this proceeding’s interminable back-and-forth,” he wrote. “Instead, having repeatedly returned to the filer for more information, we now declare that which we asked for insufficient and grant rehearing, implicitly terminating decades of (admittedly questionable) FERC practice without even acknowledging it.”
Order on GridLiance ATRR
FERC last week also affirmed an administrative law judge’s initial decision approving SPP’s proposed tariff revisions to add an annual transmission revenue requirement (ATRR), a formula rate template and implementation protocols for GridLiance High Plains-owned facilities in Nixa, Mo.
In a Feb. 28 order, the commission said incorporating the Nixa assets into one of the RTO’s transmission pricing zones is consistent with cost-causation principles and otherwise just and reasonable. The GridLiance assets, acquired from the city in 2018, include 10 miles of transmission lines and related facilities interconnected to Southwestern Power Administration in the same zone and to City Utilities of Springfield in a neighboring zone (ER18-99).
At issue was SPP’s decision in 2017 to place the Nixa facilities into Zone 10 because they serve load there. Several cities in the zone protested, as did other parties, leading the commission to set the tariff revisions for hearing and settlement judge procedures. FERC rejected SPP’s initial settlement offer in 2021 and remanded the proceeding to resume hearing procedures. (See FERC Remands GridLiance ATRR Settlement.)
The ALJ in December 2021 found that the Nixa facilities will result in a $1.8 million cost shift to its Zone 10 customers; that they will accrue “substantial, specific but unquantifiable” benefits; and that those benefits justify the cost shift. Intervening parties filed countering briefs on exceptions in January 2022.
The commission agreed that the ALJ “properly balanced competing testimony” in reaching his cost-shift finding and said the record supports the finding that the Nixa assets provide integration, reliability and power-transfer benefits to Zone 10’s customers and that those benefits justify their costs.
FERC also affirmed the judge’s dismissal of alternative rate proposals made by the intervenors, finding that SPP had met its burden under Section 205 to show that its proposal was just and reasonable.
A three-judge panel of the D.C. Circuit Court of Appeals on Friday rejected a challenge from the Midwest Ozone Group to EPA’s Cross-State Air Pollution Rule for the National Ambient Air Quality Standards (NAAQS).
The Midwest Ozone Group (MOG) is made up of numerous large industrial firms from the region, including utilities such as Ameren, American Electric Power, Associated Electric Cooperative Inc., Buckeye Power, Duke Energy and FirstEnergy.
The rule that the group challenged was updated by EPA after the court remanded it to the agency in a 2019 decision. In the revised rule, the agency addressed its failure to balance emissions obligations in accordance with the 2008 NAAQS and its date of attainment.
MOG argued that the revised rule is arbitrary and capricious and that the agency failed to conduct a legally and technically appropriate assessment of it.
The Clean Air Act authorizes EPA to adopt NAAQS to regulate air pollutants including ozone, which can be blown from facilities in one state into another. The law includes the “good neighbor provision” that requires every upwind state to prevent its pollutant emissions from contributing significantly to nonattainment in downwind states.
For 2021, EPA set specified, enforceable measures in federal implementation plans for Illinois, Indiana, Kentucky, Louisiana, Maryland, Michigan, New Jersey, New York, Ohio, Pennsylvania, Virginia and West Virginia.
MOG argued that EPA took mathematical and analytical shortcuts in its analysis of upwind states’ ozone contributions under the good-neighbor rule. Eleven of the 12 states identified were considered significant pollution contributors based on that flawed data, it said. EPA also failed to consider programs in downwind states to control pollution and exceptional events that could impact air quality monitors, MOG said.
EPA said it used the method to figure out how much improvement should have been expected by 2021, but even if it used MOG’s preferred method, the same states would have obligations to clean up their ozone pollution.
The court said its review of the case was simple: As long as the action was not against the law, all EPA had to do was act reasonably and reasonably explain its actions. The court had to give deference to the agency’s interpretation of “highly complex and technical matters.”
The kind of statistical analysis EPA used has been described as “perhaps the prime example of an area of technical wilderness into which judicial expeditions are best limited to ascertaining the lay of the land,” the court said.
The D.C. Circuit has never required EPA to use a particular method to generate its data, or to adhere to past practice; it just has to show a reasonable connection between the facts on the record and its decision, the judges said.
“MOG fails to demonstrate that EPA’s promulgation of the revised rule was arbitrary, capricious or promulgated in violation of its statutory authority under the good-neighbor provision,” the court said. “Accordingly, we deny MOG’s petition.”
CARMEL, Ind. — MISO says it is leaning towards a simple and existing method to handle the market participation of a growing number of combined battery storage and renewable energy resources.
The grid operator last week released a draft market participation model under which hybrid resources’ components will be required to register and participate separately by resource type.
MISO currently maintains two definitions for resources that share a point of interconnection: “co-located” or “hybrid.” While co-located resources participate in the market separately, hybrid resources would participate in the market as a single resource. (See MISO Prepares Hybrid Participation Model for Unknown Numbers.)
Bill Peters, a market design adviser for the RTO, told a Market Subcommittee meeting Thursday that there are advantages to requiring components of a hybrid resource to operate individually. He said renewables can still confidently use MISO’s forecasts for intermittent resources, and storage components of hybrid resources are free to clear as operating reserves. He said a single-offer hybrid participation limits MISO’s visibility into the capabilities of the multiple resource types that comprise the hybrid resource.
“As we learned from Ghostbusters, this will help prevent us from crossing the streams, which we know is bad,” Peters joked.
He said MISO’s proposal will prevent storage assets from being “shackled” to renewable resources and storage will be free to operate independently and “capture otherwise curtailed or clipped renewable generation.” Peters said resources sharing physical infrastructure already can be dispatched and settled separately.
The RTO has about 1 GW of hybrid resources projects that have executed generator interconnection agreements, though none are coming online over the next year.
MISO’s hybrid IC queue numbers may underrepresent the number of hybrids that eventually will materialize in the footprint. Staff has said interconnection customers sometimes request separate applications for the storage and generation components; others request surplus IC capability for storage that is added later. Clean energy advocates have been pressing MISO for several years to make its markets friendlier to hybrid resources.
Staff said that it is challenging to build a singular hybrid-participation model because any number of resource combinations are possible.
MISO is unable to provide forecasts for partial intermittent resources, Peters said, and wouldn’t know when hybrid resources are operating under a generation designation or a dispatchable intermittent resource designation.
Peters said MISO staff went over a “legal reading of the tariff” and found few clear answers as to how hybrid resources should participate in the markets. “It becomes clear that when a lot of answers are ‘maybe,’ that’s maybe not the best,” he said.
Peters said if MISO’s idea works well, it may “obviate” the need to work out a comprehensive participation model for hybrid resources.
“This may be the best way to operate these resources,” he said.
Peters said MISO might want to update software so it can create a “family relationship” to make sure resources are maintaining the megawatt limit of a shared interconnection point. Market systems currently lack the capability to manage shared interconnection limits.
Peters asked for stakeholders’ input on the “good, the bad and the ugly” of the proposal. They have until March 16 to weigh in.
CARMEL, Ind. — MISO last week continued to defend its decision to export power to its neighbors that played a role in tipping the RTO into emergency procedures during the December winter storm.
Staff told stakeholders their emergency operating procedures allow MISO to deploy load-modifying resources to “assist neighbors who are in a comparable or worse operating state.” The RTO exported up to 5 GW at times Dec. 23 to SPP, the Tennessee Valley Authority, Associated Electric Cooperative Inc. and the Southeast planning region.
“So, we did meet that condition during [Winter Storm] Elliott,” John Harmon, senior director of operations support, said during a Reliability Subcommittee meeting on Feb. 28.
Market design adviser Dustin Grethen said MISO was able to partly repay its neighbors after years of relying on neighboring regions’ exports during various maximum generation events.
“It’s good to know that we can sometimes step in and help others when it’s necessary,” he said during a Market Subcommittee meeting on Thursday.
The RTO experienced operating reserve deficits on Dec. 23 and hit its $3,500/MWh price cap during several intervals.
MISO energy and operating reserve pricing on Dec. 23 | MISO
“There was plenty of pain all around tied to the pricing,” Grethen said.
MISO Executive Director Market Operations J.T. Smith said MISO, PJM and TVA all missed on load forecasts “in pretty outstanding fashion.”
Smith said MISO’s Independent Market Monitor will likely propose that the grid operator create joint operating agreements with the TVA and other nearby non-RTO members so that it can hold its own load harmless from exports’ pricing impacts.
“I strongly support what MISO did, but I think there needs to be some way to make whole the load that was exposed,” Minnesota Public Utilities Commission staffer Hwikwon Ham said.
Grethen said high prices during the event drove higher settlements and thus “higher credit exposures,” but MISO was able to work with its market participants to avoid any defaults.
MISO said its credit team ultimately issued 101 exposure warnings. It issues such warnings when a market participant’s exposure is greater than 90% of its combined posted collateral and credit line.
The storm resulted in $23 million of price volatility make-whole payments charged to load-serving entities. That was offset by $54 million of revenue neutrality uplift credits because of revenue surpluses from load, unit and export deviations in the real-time market. A net uplift of $32.4 million was credited to load-serving entities in the footprint, distributed through a load ratio share. MISO uses its revenue neutrality uplift mechanism to balance charges and credits, ensuring it remains revenue neutral across operating hours.
The grid operator said it plans to improve how it communicates emergency alerts to its market participants. Some stakeholders complained they didn’t receive notifications until after the event unfolded.
Other than the December emergency, “winter continues to be mild,” Harmon said.
MISO averaged 75 GW of load in January, with load peaking at 93 GW Jan. 31. It had projected peak demands of 102 GW under typical winter conditions and 109 GW should an arctic blast descend on the footprint. (See MISO: Diminished Emergency Possibilities this Winter.)
The New York Public Service Commission’s work implementing the Accelerated Renewable Energy Growth and Community Benefit Act won praise in comments filed last week, but parties said much more work is required to increase the transmission capacity needed to meet the state’s clean energy goals.
The act was meant to improve and streamline the process for building renewable projects around the state. It included setting up a new Office of Renewable Energy Siting and to help speed up the development of needed transmission.
The Alliance for Clean Energy New York, New York Offshore Wind Alliance, Advanced Energy United and the Natural Resources Defense Council submitted joint comments saying that expanding transmission is critical to the cost-effective integration of renewables and praising the PSC for its actions so far. But they said the rate of transmission development needs to speed up to affordably meet the requirements of the Climate Leadership and Community Protection Act, which calls for a carbon-free grid by 2040.
“If not, renewable energy projects will be delayed, leading to the state not complying with the CLCPA mandates,” the groups said.
The PSC recently approved utilities spending $3.5 billion on 62 transmission upgrades meant to open up transmission capacity for renewables, but many of the projects will not be built until the end of the decade, or even beyond. (See NY PSC Approves 62 Tx Upgrades Totaling 3.5 GW.)
The longer it takes to build transmission, generator developers are more likely to price higher risk premiums into their offers for renewable energy credits (RECs).
“These risk premiums are necessitated by the uncertainty surrounding the developers’ ultimate cost obligation and local transmission owners’ construction time frames for system upgrades revealed through interconnection cost studies undertaken by the TOs and the NYISO,” the groups said.
Developers only get solid estimates of the transmission costs they face after they submit bids, which means they have to price such risks into their RECs. The groups argued that the PSC should ensure transmission is built before new power plants to limit those risks, which can work for both offshore and onshore resources.
EDF Renewables, which has built five projects in the state so far and has more in the pipeline, agreed, saying in its own filing that renewable projects will continue to experience congestion and curtailments until the new transmission infrastructure come online in 2029.
“Given the ambitious CLCPA targets throughout 2040, and the long lead time for transmission upgrades, it is critical that the state continues to explore effective transmission solutions and ensure they are approved in a timely manner,” EDF said.
Consolidated Edison (NYSE:ED) urged the PSC to continue leveraging local utilities’ expertise in expanding the grid to advance the state’s clean energy transition. Regulators should prioritize “multi-value projects” that connect clean energy to the grid while also improving reliability and cutting costs.
The utility wants the PSC to approve the “Coordinated Grid Planning Process” it recently filed along with the state’s other utilities. (See NY Utilities Propose Plan to Coordinate Decarbonization Efforts.) The proposal represents an end-to-end holistic process to identify and approve local transmission investments needed to achieve the state’s climate goals.
The four trade groups and EDF also want to see the CGPP approved, though they suggested changes including making it run every two years instead of three.
While the CGPP would help, the PSC should continue using NYISO’s Public Policy Transmission Planning Process to complement it and procure all the needed transmission to eliminate emissions from the power sector. EDF argued that the ISO’s process should be used to supplement the PSC’s 62-project package with infrastructure around the city of Watertown east of Lake Ontario and in the Southern Tier to ensure the grid can accommodate all of the new renewable projects being built.
LS Power urged the commission to avoid relying too heavily on the utilities, arguing that many of its actions implementing the law have lacked competition and transparency.
“As a result of [this] process, New York ratepayers will be responsible for billions of dollars of investment in transmission projects,” LS Power said. “Continued approval for the majority of this construction outside of a competitive process does not provide the best result for ratepayers.”
The commission should rely on competitive processes to build out the needed transmission because that has already benefited consumers in the state by lowering costs and accommodating more renewable generation, the company said. The PSC should look to maximize the use of existing NYISO processes and avoid approval of bulk transmission that does not come out of competitive planning processes.
ISO-NE has work to do to make itself compliant with Order 2222, FERC said in an order late Wednesday (ER22-983).
Similarly to how it has responded to other RTOs’ compliance filings on the landmark rule requiring RTOs to open their markets to distributed energy resource aggregations (DERAs), the commission accepted some of ISO-NE’s effort and rejected other parts.
The ordermakes ISO-NE responsible for several follow-up compliance documents containing revisions, with various deadlines between 30 and 180 days.
Renewable energy groups and others in New England had criticized ISO-NE for not going far enough to remove barriers for DERs to participate in wholesale markets, and some of those complaints were addressed by FERC.
“We find that ISO-NE has failed to demonstrate that its proposed energy and ancillary services market participation models for DERAs accommodate the physical and operational characteristics of behind-the-meter DERs, because behind-the-meter DERs participating under those participation models may be unable to provide all services that they are technically capable of providing through aggregation.”
The federal agency flagged ISO-NE’s choice to require measurement of behind-the-meter DERs at the retail delivery point for most DERs, rather than allowing sub-metering.
The commission sent back several other items for ISO-NE to revise or, in some cases, further explain.
FERC challenged the RTO’s requirement limiting the storage participation model — comprised of a binary storage facility or continuous storage facility — to load-serving entities (LSEs).
“ISO-NE fails to cite to any tariff provisions that establish this LSE requirement and therefore has not demonstrated that this LSE requirement is an existing requirement applicable to all resources in order to provide wholesale energy withdrawal service in ISO-NE’s energy market,” FERC wrote, requiring the RTO to explain it further as part of a 60-day compliance filing.
“The commission has given a pretty good overview of why ISO’s proposal isn’t reasonable and doesn’t meet the requirements of Order 2222,” said Caitlin Marquis, managing director of Advanced Energy United, the clean energy trade group that has been one of ISO-NE’s most vocal critics on the issue.
“One of our biggest issues with ISO’s filing is that it failed to accommodate behind-the-meter DERs, so I was pleased to see that the commission also felt that ISO had failed to accommodate the physical and operational characteristics of behind-the-meter DERs,” she said.
“We are pleased that the commission accepted most of our compliance filing, with a few things left to work on, which is common in these types of orders,” said ISO-NE spokesperson Matt Kakley. “We’ll be reviewing the decision and then responding as directed.”
Commissioners’ Commentaries
In a sharply-worded concurrence, Commissioner Allison Clements noted that the ISO-NE proposal was “almost universally panned by prospective market participants seeking to integrate behind-the-meter resources into its markets.”
She described the grid operator’s response as being especially deficient when compared to other RTOs, for example in its approach to submetering. She said that the other grid operators have figured out how to manage that question without blocking DERs from participating at all.
“ISO New England is like an architect declaring that it is impossible to construct higher than a 50-story building, even as competitors have already built the Empire State Building and Sears Tower, and are making plans for One World Trade Center,” she wrote.
She called on the grid operator to use its follow-up compliance filings to “roll up its sleeves and pursue a problem-solving approach to integrating behind-the-meter resources,” rather than “rigidly defend a status quo metering framework that stymies this critical opportunity to improve reliability.”
The commission’s two Republican commissioners both took the opportunity to bash Order 2222 itself: James Danly wrote that he dissented against it, and Mark Christie said he would have if he was on the commission at the time it was approved. But they took different approaches to the compliance filing, with Danly concurring with the majority and Christie dissenting.
“I do not envy ISO-NE and NEPOOL the compliance task we imposed upon them. One hundred percent compliance probably is impossible in a first, or perhaps even second, attempt. We shall see,” Danly wrote, calling 2222 “intrusive interference into the administration of RTO markets and distribution-level systems.”
Christie offered a similar take.
“The problems and complexities of complying with Order No. 2222 are extreme,” he wrote. “This is no surprise to anyone who has studied Order Nos. 2222 and its progeny.”
He chastised the majority for taking issue with ISO-NE’s metering proposal.
“After all of the effort and expense invested by ISO-NE and all of the various state entities and market participants, to require even more detail on the compliance proposal when the record makes clear to me that the proposal has met the requirements imposed by Order No. 2222, is not something I can support,” Christie wrote.
