The New England Power Pool Markets Committee devoted the bulk of its two-day summer meeting to debating changes to inputs and assumptions that will govern Forward Capacity Auction 16 in February 2022 for the 2025/26 capacity commitment period.
ISO-NE is proposing to update the cost of new entry and net CONE calculations, and to recalculate the offer review trigger prices (ORTPs).
Principal market development analyst Deborah Cooke gave a presentation outlining two proposed adjustments to the energy and ancillary services (E&AS) revenue offsets used to calculate net CONE and ORTPs.
One adjustment would account for estimated revenues under the Energy Security Improvements (ESI) market design. The second — a “level of excess” adjustment — seeks to account for surplus generation above the net installed capacity requirement (ICR) based on the one-day-in-10-years loss-of-load expectation.
In this example, the final adjustment for ESI revenues for combustion turbine technology participating in FCA 16 is $0.292/kW-month, representing the sum of incremental payments to generation and incremental payments to capacity. | ISO-NE
Cooke noted that the system has been long on capacity since the 2016/17 capacity commitment period, with a 2,006-MW excess for 2019/20.
E&AS revenue offsets will be calculated reflecting both current and future market conditions, including revenue impacts from ESI, both as proposed by ISO-NE and as proposed by NEPOOL, and the elimination of the Forward Reserve Market. (See “FRM Sunset by 2025,” NEPOOL Markets Committee Briefs: June 10, 2020.)
Detailed E&AS Revenue Offsets
Engaged by the RTO to support the updates, Concentric Energy Advisors’ Danielle Powers and her colleagues also presented a review of detailed capital and operating costs for CONE (simple cycle and combined cycle) and ORTP (solar, battery storage and onshore and offshore wind) units.
Their methodology used a simplified hourly dispatch model of the units’ E&AS awards in the day-ahead and real-time markets to estimate E&AS revenues. Unit dispatch was based on adjusted historical day-ahead and real-time LMPs.
Additional revenue adjustments made outside of the dispatch model included energy/reserve scarcity hour revenues and expected Pay-for-Performance (PfP) payments.
The expected impact of energy and reserve shortage hours in the future are incorporated in a standalone energy/reserve scarcity hour adjustment outside of the E&AS dispatch model.
The issue is complicated by having a great number of moving parts, but the analysis will be a little easier to understand at the August MC meeting after they pull more of it together, Powers said.
Concentric will continue to refine its analysis and, at the August meeting, will have incorporated ESI assumptions and analysis into the CONE and ORTP models. It will also review financial assumptions and its preliminary findings on demand response and energy efficiency.
The RTO proposes to file any calculation changes with FERC by Dec. 1.
FCM Parameter Updates for 2025/26 Period
ISO-NE Lead Analyst Kevin Coopey presented estimates of expected capacity scarcity condition (CSC) hours and related factors for updating the parameters for the 2025/26 capacity commitment period.
The summer peak-load CSCs account for 14.1 hours of the 15.3 hours expected annually for 2025/26.
Transient CSCs (estimated at 0.8 hours annually) arise from operational risks such as system under-commitment, load forecast error and the loss of critical transmission elements, Coopey said. Unlike peak-load scarcity, transient CSCs tend to be shorter in duration and usually occur at lower load levels. Winter CSCs (estimated at 0.4 hours per year) can arise from several causes, notably natural gas supply constraints during cold weather.
Coopey said the peak load analysis is based on the two peak-load CSCs that have occurred since December 2014: Aug. 11, 2016, and Sept. 3, 2018.
Each of the 2,160 hours in a 90-day winter season has its own random draw of a capacity factor from the historical sample. This capacity factor is multiplied by the expected quantity of installed capacity. The total miscellaneous intermittent capacity used in the PWSA is the current total nameplate capacity, 704 MW. | ISO-NE
Several stakeholders questioned the rationale for classifying a CSC event as peak-load or transient, and whether using two events provides sufficient data to draw statistical conclusions about average balancing ratios, which reflect the lower loads expected during transient and winter operating conditions.
“We’ve heard the feedback about trying to get GE MARS [General Electric’s Multi-Area Reliability Simulation Software] to generate a balancing ratio estimate,” Coopey said. “We’ll take that back to the ISO.”
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
OSW Capital Costs Assumptions
RENEW Northeast and Daymark Energy Advisors made a presentation on offshore wind capital costs and renewable energy credit price assumptions for ORTP calculations.
Alex Worsley of Boreas Renewables noted that ISO-NE proposed an overnight capital cost of $5,876/kW (2019$) for the FCA 16 offshore wind ORTP calculation.
“Looking at recent power purchase agreements pricing, as well as the latest publicly available data, and considering that current New England offshore wind developers with upcoming projects have significant experience building the largest wind farms globally, we believe that this cost assumption is unreasonable for projects to be built in 2024-2025,” Worsley said.
The RENEW analysis used a financial model of the offshore wind projects based on their executed PPAs. “We’ve also assumed that the developers are predicting some capacity revenues in addition to energy and REC revenues to determine their PPA price … but they wouldn’t have certainty over that [capacity] revenue, so this resulted in a conservative estimate for capital costs,” said Carrie Gilbert of Daymark.
Global cost data show the implied CapEx range from local PPAs is in line with recently installed European projects. | RENEW/IRENA
Worsley said their PPA analysis shows implied capital expenditures ranging from $2,200 to $3,600/kW for projects currently under development, while the International Renewable Energy Agency’s shows a $2,800 to $3,900/kW range of costs for the larger European projects with commercial operation dates in 2019. Lazard’s 2019 levelized cost of entry analysis shows a $2,350 to $3,550/kW CapEx range.
“We suggest the overnight capital costs of this hypothetical 800-MW project to be built in 2024-2025 should be approximately $2,681/kW, and assert that the $3,195/kW difference between our capital cost assumption and the ISO’s cost assumption would significantly impact the ORTP value.”
As for ISO-NE’s REC assumptions, “previous treatment of RECs in ORTP calculation has been forward-looking, but the currently proposed REC assumption is purely historical and uses three lowest-price years in the recent past. So, this is a big departure from previous approaches and underestimates REC revenues,” Gilbert said.
Proposed average REC value from 2017-2019 underestimates longer REC pricing trends, according to RENEW. | RENEW
Resource Balance for Net CONE
Robert Stoddard, managing director of Berkeley Research Group, introduced on behalf of the New England Power Generators Association (NEPGA) a presentation on resource balance for net CONE calculation.
The presentation questioned Concentric’s key assumption that the E&AS offset (and all other inputs to net CONE) should be calculated “at criterion.”
Stoddard said Concentric supports that contention by citing a non-decisional paragraph in a 2017 FERC order in which the commission said “net CONE is intended to approximate the compensation a new entrant would need from the capacity market in the first year of operation to recover its capital and fixed costs under long-term equilibrium conditions” (ER17-795).
Using the “at criterion” capacity balance has many negative consequences, NEPGA argues, such as requiring arbitrary and improbable adjustments to forecasts; ignoring impacts of energy-only resources; and overstating the expected number of scarcity hours.
In addition, competitive offers could be subject to undue mitigation, the ORTP may be set too low, and the FCM will be unlikely to produce sufficient revenue on average, Stoddard said.
CONE measures the cost of adding an incremental resource, and customers pay the difference between CONE and net CONE in E&AS markets, so CONE is the best measure of the expected total cost to consumers, the presentation said. Short of a full demand curve reset, the same expected price level can be achieved by using an “as expected” E&AS offset.
Exempting EE from PfP
Mark Spencer of LS Power presented a proposal to exempt energy efficiency resources from PfP, asserting that potential performance payments represent a miniscule revenue opportunity for EE resources.
The PfP program was implemented in June 2018 in order to ensure fuel security under severe winter conditions. Under the program, all resources with capacity supply obligations (CSOs) are assessed a charge — based on their gross FCA payments — when a “measurable” real-time operating reserve (RTOR) deficiency triggers a CSC.
The RTO redistributes the money collected from that charge as payments to CSO resources based on their performance during the RTOR event.
The bulk of EE funding is derived from surcharges to retail customers and a modest amount from Regional Greenhouse Gas Initiative revenues, Spencer said.
Capacity revenue represents only 7 to 29% of the total funding streams, and long‐run expectations of PfP payment contributions to total funding are likely less than 1%, he said.
“What our recommendations are is to retain EE’s base capacity payments and to remove them from the PfP settlement, including the insurance pool, so they wouldn’t be subject to any of the deficiency or capacity payment performance charges that that obligation would entail, and to eliminate the requirement for them to provide credit support for the [Forward Capacity Market] delivery financial assurance,” Spencer said.
Backers of the proposal will continue to develop it before seeking a vote on the Market Rule 1 and Financial Assurance Policy changes at the September PC meeting.
Texas regulators last week signed off on a settlement agreement between Wind Energy Transmission Texas (WETT) and other parties that will result in a change in ownership structure (50584).
The order, finalized during the Public Utility Commission’s open meeting Thursday, transfers WETT’s ownership and control to AxInfra, an investment fund managed by Axium Infrastructure US, from various subsidiaries of global asset manager Brookfield Asset Management and Canadian pension-investment manager Public Sector Pension Investment Board. The settlement also results in the Teachers Insurance and Annuity Association of America gaining an indirect, minority noncontrolling interest in WETT through its wholly owned indirect subsidiary 730 Hotspur.
Commissioner Shelly Botkin | Texas PUC
“We are grateful that the parties were able to reach a settlement that makes sense,” Commissioner Arthur D’Andrea said.
WETT built high-voltage transmission lines that it now operates in West Texas as part of the state’s Competitive Renewable Energy Zones initiative.
The commissioners secured a commitment from WETT that it would not build transmission infrastructure outside ERCOT without the PUC’s approval or take any action that impairs their continued jurisdiction.
COVID Relief Plan Extended to Aug. 31
The PUC extended the state’s Electricity Relief Program to Aug. 31, citing Gov. Greg Abbott’s July 10 decision to extend a COVID-19 disaster declaration for all Texas counties. The orders extend protection to participants from disconnections for nonpayment and continues the requirement for retail electric providers to offer deferred payment plans when requested.
PUC Chair DeAnn Walker and staff wait to hear public comments from the phone. | Texas PUC
“This pandemic is far from over, so we will continue to monitor its impact on Texas utility customers,” Chairman DeAnn Walker said in a statement. “Our goal is to ensure our state emerges from these troubled times with our competitive electricity marketplace intact and its benefits positively affecting customers across the state.”
The program is funded by a 33-cent/MWh rider charge to transmission and distribution utilities. It currently protects more than 590,000 households from disconnection.
Commissioners Revise Rate Package Docs
The PUC approved staff’s proposal that revises investor-owned utilities’ cost-of-service rate filing package (49199).
The revisions require applicants filing a rate case to provide information about plant additions for transmission lines, high-voltage switching stations and substations. The revisions also require applicants to provide information on the costs and loads associated with DC interconnections to areas outside ERCOT and the costs to serve wholesale customers who receive service at distribution voltage.
SPP stakeholders last week once again took a crack — three, actually — to resolve a weighty issue in determining how futures will be considered in the RTO’s 2021 transmission plan study. Now they’re back to square one.
The Markets and Operations Policy Committee took three votes during its July 15-16 web meeting, which began with 156 attendees, on how to consider the two futures that will go into the 2021 assessment’s scope. All three failed, leaving staff to promise they will raise the issue again at next week’s Board of Directors and Members Committee teleconference.
Since January, the Economic Studies Working Group (ESWG) has recommended a 60/40 split between Future 1 and Future 2, respectively. The “business-as-usual” Future 1 reflects current trends, while the “emerging technologies” Future 2 case assumes that distributed generation, demand response, energy efficiency and energy storage will have a major effect on load and energy growth rates.
The ESWG brought its recommendation to the January MOPC meeting, but members were unable to reach consensus between those who wanted a more aggressive forecast and those who favored a more conservative approach. A vote was never held. (See SPP Members Delay Decision on 2021 Tx Assessment.)
The Market Working Group has worn many hats while gathering virtually in recent months. | SPP
The working group returned in April with additional information and the same recommended 60/40 split. The MOPC this time held a vote, but the motion fell just short of the necessary two-thirds threshold at 65.2% approval. (See “Members Reject 60-40 Split in ITP 2021 Futures,” SPP MOPC Briefs: April 14, 2020.)
Through it all, the ESWG has remained “firmly” in the 60/40 camp, said its chair, ITC Holdings’ Alan Myers.
“Most people who advocate 60/40 suggest the assumptions in Future 1 are more reasonable,” he said. “They feel like some of the assumptions in Future 2 are further out, that the retirement assumptions are much more aggressive than they ought to be. Those who support 50/50 say we tend to under-report renewables in the model. They say Future 2 represents that more reasonably than Future 1.”
Future 1 projects about 32 GW of wind installations by 2031. Future 2 foresees about 37 GW.
“It would be nice to have MOPC consensus … to not have the air or notion that the 2021 ITP study is waiting on the results of the [futures],” said Casey Cathey, SPP’s system planning director. As he has said before, Cathey also pointed out that over the last three planning cycles, a 60/40 weighting “would not have made a difference on the final portfolio.”
The MOPC last week first voted on a 50/50 weighting, acknowledging the concerns of those wary of increasing transmission costs and favoring the more conservative approach. The motion failed, with a 51.98% average of the transmission owners’ and transmission users’ votes.
A second vote on the 60/40 weighting followed. It too failed, with a vote average of 59.9%.
Lincoln Electric System’s Dennis Florom then suggested a 55/45 weighting as a compromise. “Let’s try to get something passed, so we can get the ESWG to move and we’re not caught in this endless loop,” he said.
That motion met a similar fate as the first two, with a vote average of 55.4%.
Myers said the ESWG has not discussed any new information since April and continues to look for direction moving forward.
“Why are we doing this?” he asked. “We’ve already had this discussion. It’s a bit of a head-scratcher.”
Members Leave B/C Ratio at 1.0
The MOPC did approve the ESWG’s recommendation to maintain a 1.0 benefit-to-cost ratio for economic projects, with 80.8% of the member votes in favor. TOs approved the motion 17-3, and transmission users voted 40-7.
The Holistic Integrated Tariff Team (HITT) had directed the group to evaluate B/C ratios of 1.05 and 1.25 and determine whether the current ratio needs to be raised. The Strategic Planning Committee also approved the ESWG’s recommendation earlier in the week. (See related story, SPC Endorses SPP’s Strategic Market Roadmap.)
Myers said the ESWG determined the Integrated Transmission Planning (ITP) process uses conservative assumptions for net plant carrying charge (NPCC) at 17.4%, compared to an incumbent TO’s average 14.6% NPCC. Adjusted production cost is the only benefit metric used in the 1.0 threshold and has represented 79% of the total benefit package in the last three ITP assessments, he said, leaving 21% of the benefit not included.
The group also found the simplified market run in the models to be conservative, Myers said. He said there is no forecasting error for load or renewables, no transmission outages and perfect congestion hedging between owned generation and load, resulting in the process reporting less benefit from projects than what is expected in the real market.
Golden Spread Electric Cooperative’s Mike Wise, who pushed the initiative at the HITT, said transmission projects will become harder to fund going forward and suggested a higher B/C ratio.
“The $10 billion of transmission projects we’ve actually approved and constructed over the last 10 to 15 years is really low-hanging fruit. Transmission projects will be more difficult and incremental in nature,” he said. “We don’t have the load growth in SPP, outside of a small pocket here and there. There’s got to be a built-in hedge factor so that consumers can be protected from paying 40 years of transmission costs of a project that we don’t know will be beneficial.”
“The unease about 1.0 is how we calculate the benefits. Those benefits are impacted by what’s in the model, as far as injection points. Some of that generation has firm service; some doesn’t,” said Al Tamimi, vice president of transmission planning and policy for Sunflower Electric Power. “I think we need a little bit more buffer until we determine the accuracy of the injection points.”
Other members said transmission is still needed along the seam with MISO, where congestion is still an issue. City of Springfield (Mo.) Utilities’ Jeff Knottek noted his customers pay some of the highest rates in the footprint and said, “To talk about raising the bar now is really an insult to those customers on the eastern edge.”
SPP: Two ITP Studies in Yellow Status
Cathey briefed the committee on the three ITP studies under way, saying two are currently in yellow status (monitor/at risk).
Cathey said the 2020 ITP, considered a “rinse-and-repeat” study, is recovering from a February modeling issue that delayed the entire study by six weeks. However, he said, the study is still on track to be brought forward for approval in October.
“Even though there was an error in the model build, we’ve been able to maintain the project going forward,” Cathey said. “We’ve been playing catch-up the last few months. As weird as the entire world has been in going through this pandemic, we’ve been very successful in keeping the project going.”
The 2021 ITP is also in yellow status, given the uncertainty over its futures’ weighting. Its schedule was also re-baselined because of mitigation work on the 2020 study.
“Scope development is greenish. … It’s in good enough shape to proceed with the model build,” he said. “It would be nice to have MOPC consensus [on the futures’ weighting] … It’s important to note the weighting would not have made a difference in the last three [ITP] cycles.”
The 2022 ITP is in green status, but it has only begun work on scope development, model development and load and generation review.
Staff availability has been an issue because of the overlapping studies, Cathey said, noting that the ITP process was revamped in 2017 and SPP has only operated and executed one-and-a-half studies so far. “So, it’s a learning process,” he said.
Point-to-point Revenue Allocation Sent Back
After much debate over how to move forward with policy development, the MOPC agreed to have the Regional Tariff Working Group (RTWG), working with the Transmission Working Group (TWG), simplify the point-to-point (PTP) transmission service revenue allocation, a process long prone to inaccuracies.
SPP currently splits its distribution of PTP service revenues to TOs 50/50, with half determined by the ratio of the annual transmission revenue requirement (ATRR) and half allocated by a megawatt-mile process. Engineering staff in 2018 reviewed the process when some megawatt-mile modeling effects forced SPP to resettle revenues. They found the process was developed more than 10 years ago using a source-sink methodology that current staff were unfamiliar with and resulted in more than 1 million combinations in the calculations.
In December 2018, staff shared the study’s results during an executive session with the board and MC, where a suggestion was made to eliminate the megawatt-mile method. Staff took an action item to develop a revision request, which was given to the RTWG.
“I do support the effort to come up with a different methodology, but the last time I checked, [the RTWG] is not supposed to be a policy group,” said Bill Grant of Southwestern Public Service. “I’m not ready to vote on this because it hasn’t been through the stakeholder process and alternatives not considered. It hasn’t been vetted by the proper groups.”
Omaha Public Power District’s Luke Haner agreed, saying, “I think it needs to go through some sort of working group. When you say the TO gets to recover the ATRR, it affects retail customers when those dollars go to a different [transmission pricing] zone.”
Staff said that, according to the last 12 months of data, 11 of SPP’s 17 zones would receive an average of about 1% less in aggregate. RTWG Chair Robert Pick, with the Nebraska Public Power District, said the group learned during a discussion the week before that three of the zones would receive 90% of the revenue.
“Back-of-the-envelope … we’re looking at about $4.6 million in revenue cost shifts,” Pick said.
“The RTWG is a regulatory group. It responds to rates and tariffs,” said Vice Chair Mo Awad, with Evergy. “We’re not a policy group, but we’re fully capable of developing policy language that will meet FERC requirements.”
Work Continues on Resource Retirement Process
Reacting to MOPC feedback, two stakeholder groups agreed to continue working together to modify proposed Tariff language designed to evaluate the short-term (operational) and long-term (planning) effects of retiring generation to the system.
As developed by the TWG and Operating Reliability Working Group, RR373 would identify reliability concerns resulting from when resources are removed from SPP’s footprint. The process includes screening criteria to filter out resources that do not require analysis before retirement. Resources that meet the criteria would be assessed by both planning and operations staff to identify potential system impacts.
TWG Chair Nathan McNeil, with Midwest Energy, said the process would improve collaboration between staff and stakeholders and address gaps in the ITP, where notifications to construct can be issued quickly in the face of retiring generation.
Some members pushed back over the addition of a new process approving plant retirements and questioned whether it would not affect the administrative system fee, as the TWG said. Grant pointed out that regulated utilities must also go through their state commissions to retire a generator.
“There’s nothing in here about state authority over generation that most of your members have as to whether to run units or not,” Grant told staff. “If you go through [SPP’s process], it can take up to a year to get an answer. Then you have to start a state process, which can take another year. For people with a state process, we’re talking two years to get a retirement done.”
“We really wanted to get something in place as quickly as we could, to give us more information rather than less. That gives us a better opportunity to mitigate any system issues that may exist,” said Antoine Lucas, SPP’s engineering vice president. “We recognize we don’t have the authority to make decisions about whether or not generators retire, but what we’ve seen in the past, retirements that happen before a study is completed can result in reliability issues on the system.”
Lucas said staff are also working with the Market Working Group to research compensation mechanisms for resources staying online to maintain reliability.
MISO-SPP Settlement Parties Eye Changes
SPP Director of Seams and Market Design David Kelley said SPP, MISO and six joint parties to a 2016 settlement agreement are discussing potential changes to the agreement, which facilitates MISO’s power transfers between its Midwest and South zones.
The settlement agreement limits transfers over the other parties’ systems to 3,000 MW southbound and 2,500 MW northbound. The deal is set to expire next February, but Kelley said the parties have agreed to a statement of understanding that they will not terminate the agreement before Feb. 1, 2022. The deal automatically renews for subsequent one-year terms unless a party gives at least 12 months’ notice.
Kelley said the parties have entered into a nondisclosure agreement but that their discussions are expected include the characteristics and terms of provided service, potential system impacts, compensation terms, and preserving improved communication and reliability processes.
“Our focus will be, as its always has been, to seek out mutually beneficial agreements while at the same time protecting the rights of our members and customers,” he said. “It’s going to be of the utmost importance to us that we continue to maintain improvements that provide dividends for us in managing flow across the seams.”
MISO has said it wants to increase its firm rights between the zones, as the current arrangement only provides for “non-firm, as-available” transmission on the other parties’ systems. That would alleviate the need for MISO to build as many as three projects to alleviate the constraint. (See MISO Floats New Option for Midwest-South Constraint.)
LOLE Study: Reserve Margin Adequate
Supply Adequacy Working Group (SAWG) Chair Natasha Henderson, with Golden Spread, told the committee the group is not recommending a change to SPP’s planning reserve margin (PRM), based on its 2019 loss-of-load expectation study.
Henderson said the biennial study’s results confirm the current 12% PRM requirement is adequate for maintaining system reliability for this year and next. The study, which did not consider replacing retired resources, indicated an 11.75% PRM in 2021 but a 12.65% PRM in 2024.
The MOPC endorsed the SAWG’s recommendation to approve a revision request (RR404) that further defines the resource adequacy requirements for demand response programs and behind-the-meter generation. The change also addresses whether they are treated strictly as an offset of a load-responsible entity’s load or as a resource with capacity, specifying which resources can or cannot reduce load.
“If a program can reduce load, it doesn’t have to carry the reserve requirement of 12%,” Henderson said.
Members OK MOPC Reorg, Strategic Roadmap
The reorganization of the MOPC’s stakeholder group structure continued to pick up steam with the committee’s 47-1 approval of staff’s recommendation to shrink the number of working groups and convert some into advisory groups and user forums.
Staff will now take their proposal to the Corporate Governance Committee in October for approval of structure and scope documents. Assuming board approval in December, the MOPC’s new structure would be put in place early next year.
Staff’s current vision of the MOPC structure in 2021 | SPP
SPP has placed seven working groups under markets, operations, planning, oversight and resource adequacy functional responsibilities. Five stakeholder groups, including the Seams Steering Committee, would become advisory groups, and the Change and Operations Training working groups and Settlements User Group would become user forums. User forums dedicated to transmission service and generator interconnection will also be added.
Staff are also calling for a reduction in the number of in-person meetings and for cost-effective meeting locations as a “first choice” for groups when they do meet face to face.
“Don’t undervalue the value of face-to-face meetings, especially for some groups that only meet a few times a year,” Lincoln Electric’s Florom said.
“That’s the foundation of our culture,” said Erin Cathey, SPP senior market design analyst.
SPP COO Lanny Nickell said user forums are an “informal way to gain [stakeholder] feedback without parliamentary procedures” and chairs, vice chairs and meeting minutes.
“It’s a way to get dialogue and share ideas, but it’s incumbent on the staff to do that,” Nickell said.
The committee lent its unanimous approval to the 2020 Strategic Market Roadmap, following the Strategic Planning Committee’s endorsement earlier in the week. The initiative is designed to improve market efficiency, reliability and price formation by having staff and stakeholders annually identify, rank and approve proposed market improvements.
“This is us taking a step back to make sure this is where the membership wants to go,” said Gary Cate, SPP’s market design manager.
The roadmap will eventually include the planning, operations and resource adequacy functional areas.
Members also agreed to continue the monthly briefings they have been receiving from staff since the coronavirus pandemic blew up in March. The member-only briefings have centered on the pandemic’s effect on SPP’s load and staffing updates, but they expressed a need for more education on upcoming agenda items “that require extensive stakeholder input.”
SPP has scheduled an Aug. 12 briefing for the MOPC on the NRIS, ERIS and Deliverability (NED) Task Force, which is developing policies needed to create an appropriate balance among costs associated with and the value attained from the RTO’s energy resource interconnection service (ERIS), network resource interconnection service (NRIS) and long-term firm transmission service products.
MOPC Chair Holly Carias recognized Les Evans, a familiar face to committee members, for his 13 years with the group. Evans retired as Kansas Electric Power Cooperative’s COO in 2018 and has since consulted with KEPCo executives, but he is now stepping away for good from the industry.
“It has been a long, long journey. I’ve seen SPP grow from less than 10 people to what we’ve become today,” said Evans, who has been involved with SPP more than 30 years.
“I’ve made a lot of long-lasting, good relationships over time,” he said, his voice appearing to crack. “Best of luck to everybody.”
Revision Change Ups Capitalization Requirements
The MOPC approved a Tariff revision request (CPWG RR409) that increases the minimum capitalization requirements for participants in the transmission congestions rights market in a design to help prevent a similar GreenHat Energy default within SPP. (See PJM to Pay $12.5M to Settle GreenHat Dispute.) The revisions up the total asset requirement from $10 million to $20 million, tangible net worth from $1 million to $10 million and the alternative minimum deposit from $200,000 to $2 million. It also excludes trading collateral balances held at any ISO/RTO from both total assets and tangible net worth calculations.
Las Vegas-based wholesale trader Active Power Investments was able to convince members to pull RR409 off the consent agenda, saying negative comments about the measure during the stakeholder process needed to be “reviewed in depth.”
Active Power’s Michael Rosenberg said the revision request introduces an “arbitrary threshold” without addressing the core problem.
“The comments showed that an increase of the minimum capitalization requirements will not prevent or improve the chances of [preventing a default],” he said. “This measure is counterproductive and will decrease competition without any benefits.”
“We see this as discriminatory for smaller investors in the market,” said NextEra Energy Resources’ Jack Clark, who voted against the measure during the stakeholder process. “Going from the existing $200,000 [for an alternative minimum deposit] to $2 million is just excessive.”
Scott Smith, SPP’s director of treasury and risk management, said the RTO used recommendations from three market and credit experts hired to do an end-to-end review of the GreenHat default in helping put together the Credit Practices Working Group’s proposal.
“Our credit policy is structured so that everyone plays by the same rules,” Smith said. “Following the GreenHat loss, we [believe] that if the loss exceeds the amount of collateral held and there’s no demonstration of assets to cover those losses, that does not make for a credible counterparty.”
The committee passed RR409 with 85.5% approval. All 18 TOs voted for the measure, but only 11 out of 38 transmission users voted against the measure.
The consent agenda included seven other revision requests and the Project Cost Working Group’s recommendation for a $20.7 million cost reduction to Basin Electric Power Cooperative’s Multi-Kummer Ridge-Roundup project in North Dakota. The project consists of tapping a pair of 345-kV lines to build new substations and install new 345/115-kV transformers.
CPWG RR408: changes the credit application in Appendix A of the Tariff’s Attachment X by focusing on entity control/ownership and applicants’ prior history of loss contingencies and judgments.
CPWG RR410: revises Attachment X to establish a 10-cent/MWh minimum TCR collateral requirement for collateral posting.
MWG RR402: introduces a design that allows greater flexibility by using near real-time economic dispatch to evaluate intraday reliability unit commitment for committing fast-start resources near real time.
MWG RR406: adds four missing electric quarterly report bill determinants and associated logic inadvertently left out in MRR266; makes two corrections to bill-meter value in the grandfathered agreement monthly/yearly distributions; and adjusts how jointly owned units’ shares are based.
MWG RR407: clarifies member-facing and notification time frame language in the current market processes and system-change processes, and modifies the emergency change language to reflect the current practice of notifying members of a change as soon as practicable.
MWG RR411: corrects the TCR administration service charge type by modifying the equation to reflect the charge type is calculated at an asset-owner level, not at a settlement location.
RTWG RR390: removes requirements in Attachment F Appendix 1 that network customers list their designated resources’ maximum net dependable capacity amount for summer and winter.
Officials from New England’s six states on Friday described their efforts to advance renewable energy goals despite the coronavirus pandemic.
“We’re really lucky to live in this region where so many states are pushing for clean energy,” said Catherine Finneran, vice president for sustainability and environmental affairs at Eversource Energy, who introduced speakers at the webinar hosted by the Environmental Business Council of New England.
The Environmental Business Council of New England hosted a gathering of state energy officials on July 17. | EBCNE
Following is some of what we heard at the meeting.
Room to Grow on the Grid
Eric Johnson, director of external affairs at ISO-NE, focused on the changing resource mix in the region.
Eric Johnson, ISO-NE | EBCNE
“The region has room for about 6,000 MW of additional wind resources without the need for significant transmission upgrades,” Johnson said, referring to the RTO’s 2019 Economic Study Offshore Wind Transmission Interconnection Analysis, presented at last month’s Planning Advisory Committee meeting. (See ISO-NE Planning Advisory Committee Briefs: June 17, 2020.)
The analysis summarized findings from three studies requested last year by the New England States Committee on Electricity (NESCOE), Anbaric Development Partners and RENEW Northeast. (See related story, Panel: Much More Tx Needed for New England OSW.)
“While renewables are only about 9% of our resource mix in 2019, with what the states are looking to do with the renewable portfolio standard, those numbers will grow dramatically,” Johnson said.
Small States, Big Goals
Riley Allen, deputy commissioner of the Vermont Department of Public Service, said his state has about 720 MW of renewable energy resources meeting a peak load approaching 900 MW.
Riley Allen, Vermont DPS | EBCNE
“In the past, the peak load used to be well above 1,000 MW, but Vermont is following the path of the region, and our loads have been declining, including peak loads,” Allen said.
Vermont’s RPS started at 55% in 2017 and will increase to 75% by 2032, Allen said. “There’s legislation that was moving forward to update that to 100% by 2030, but the COVID-19 pandemic intervened and that’s been pushed to a later session.”
The DPS is involved in a rate design initiative, an eight-month process sponsored by the Department of Energy to look at dynamic rates, flexible load management, subscription services and gaining adoption of more advanced rate designs.
“We focused on several areas of emerging technologies: the heat pump, electric vehicle load, customer-sited generation and energy storage,” Allen said. “These are broadly recognized as loads that are pretty impactful if they’re left unmanaged, but with management, there’s a great deal of potential to essentially mitigate their potential adverse effects on the system.”
He characterized Vermont as having a roughly $800 million electric system today, “and in the next 20 years, we can expect an additional bill of $500 million on top of that with the addition of these new technologies.”
Carrie Gill, Rhode Island OER | EBCNE
Carrie Gill, chief of program development in the Rhode Island Office of Energy Resources, highlighted her state’s push to meet 100% of electricity needs with renewables by 2030 and decarbonize the heating sector, and its continued leadership in energy efficiency.
Rhode Island Gov. Gina Raimondo signed an executive order in January committing the state to be powered by 100% renewable electricity by the end of the decade and directing the OER to conduct economic and energy market analyses in order to develop workable policies and programs. (See RI Seeks to Lead with 100% Renewable Goal.)
“We recognize that we must keep energy supply and energy delivery rates affordable,” Gill said. “Fortunately, we’re seeing that many renewable energy resources are not only cost competitive, but sometimes represent the lowest-cost resources available.”
The heating sector is an important target because looking at decarbonization just in terms of electricity would be shortsighted, she said.
“We do not recommend that Rhode Island depend on one technology; [it should] look to multiple pathways. But either way, our fuel becomes decarbonized,” Gill said.
Rhode Island has been ranked among the top three states for energy efficiency for the past few years and is proud of it, she said.
Catherine Finneran, Eversource Energy | EBCNE
“We lost 3,900 of 17,000 clean energy jobs in the state since March … but even though we have challenges related to COVID, we’re not going to take our foot off the gas pedal,” Gill said. “We see this as an opportunity to move forward and to advance the clean energy industry.”
Dale Raczynski of Epsilon Associates asked how the state will meet peak demand with a 100% renewable mix during periods of low wind or solar.
“We will see storage as a critical technology … so we’re working on understanding where the market barriers are and removing them,” Gill responded.
Hank Webster of Acadia Center asked if the state would offer incentives allowing gas heating customers to transition to heat pumps. “There are many benefits to getting off gas because methane is a very harmful climate pollutant and presents a public health and safety risk,” Webster said. “Recent reports about indoor cooking show terrible health impacts.”
“We are trying to look holistically across sectors. … We don’t want to foreclose any options to us,” Gill said. She also added that improving the energy efficiency of HVAC systems reduces the risk of spreading pathogens.
Gulf of Maine
Dan Burgess, director of the Maine Governor’s Energy Office, said that growing the clean energy economy is even more important now in the pandemic.
Dan Burgess, Maine Governor Office | EBCNE
“Fortunately, the pandemic started during a shoulder season for heating … and Gov. Janet Mills has convened an Economic Recovery Council,” Burgess said. “There’s certainly some energy overlap, and we see an opportunity for clean energy and energy efficiency to play a role in the economic recovery.”
Mills signed an executive order last year setting a 2045 goal for achieving carbon neutrality and creating the state’s Climate Council to put it on a path for 45% emissions reduction by 2030 and 80% by 2050, he said.
“We’re on target to reaching those emissions goals,” Burgess said. “The electric power sector represents only 7% of emissions in the state, but we’ll have to keep working on that sector as we electrify transportation and heating in the state, where 60% of homes use heating oil.”
Burgess said heat pumps, which Efficiency Maine Trust has been promoting for 10 years, offer both environmental benefits and jobs, adding that “also there’s a huge opportunity in electric water heaters.”
He touted the first floating offshore wind turbine in the country, now under development by the University of Maine in the Gulf of Maine.
Matthew Mailloux, New Hampshire OSI | EBCNE
Matthew Mailloux, energy adviser in the New Hampshire Office of Strategic Initiatives (OSI), also serves as the state’s adviser to the Bureau of Ocean Energy Management for the tri-state offshore wind task force.
“We’re in the middle of a pandemic, and obviously some work has slowed down as a result, but OSI, especially in the early days of COVID, was working to understand what the landscape was for the energy sector broadly to make sure that critical infrastructure was still able to perform,” Mailloux said.
Gov. Chris Sununu declared a moratorium on evictions and utility shutoffs, which was done through the OSI, he said.
“The Gulf of Maine has some of the best offshore wind resources of anywhere in the world, not only some of the best wind speeds in the country,” Mailloux said. “New Hampshire is a relatively small piece of the pie when it comes to actual federal waters off our coast, but we also have some great transmission interconnection assets.”
One challenge is that northern New England is an export-constrained region for ISO-NE, he said.
“As we continue to inject more power into the grid at those locations, there [are challenges to] exporting that power to load centers in southern New England, such as Boston or Hartford,” Mailloux said.
New Hampshire also has seen “a contentious debate about net metering over the past year or so,” and “we won’t see much progress on net metering this year but will if Gov. Sununu is re-elected in November,” he said. (See related story, FERC Rejects Net Metering Challenge.)
Environmental Justice
Massachusetts Department of Energy Resources Commissioner Patrick Woodcock said 2020 is “an inflection year for” his state, which is attempting set an interim 2030 goal on the way to meeting Gov. Charlie Baker’s 2050 date for reaching net-zero greenhouse gas emissions. He referred to a decarbonization study being led by Undersecretary for Climate Change David Ismay to guide the state’s effort to meet the 2050 target. (See “Bay State Net-zero Overview,” NEPOOL Markets/Reliability Committee Briefs: July 1, 2020.)
Patrick Woodcock, Massachusetts DOER | EBCNE
Woodcock said the pandemic highlights the importance of a resilient electric system and the disparity of air quality across the state. “We are refocusing on how electrification may provide benefits for air quality and have started to contemplate either targeting incentives to environmental justice municipalities [or] targeting commercial medium- and heavy-duty vehicles, to ensure that our EV policies also have the co-benefits of improving air quality.”
The busy regulatory agenda included new regulations, which double the Solar Massachusetts Renewable Target program to 3,200 MW, and mandate that any solar installation over 500 kW needs to be paired with storage, he said.
“The policy does include some limitations on eligibility for land that has been identified as priority habitat … so that our solar policy has co-benefits of managing our open space,” Woodcock said.
Massachusetts also is finalizing its Clean Peak Standard. “We’re trying to harness storage and other resources to ensure that clean energy growth starts addressing the shifting peak that has been contributing to high electricity prices,” he said.
Implemented last year, the standard mandates that a minimum percentage of retail electricity sales be met with clean generation resources or load reductions during seasonal peak periods. (See Mass. Inaugurates Clean Peak Standard.)
Susannah Hatch of the Environmental League of Massachusetts asked about regional collaboration on offshore wind and transmission.
Victoria Hackett, Connecticut DEEP | EBCNE
Woodcock said officials are working on it and referred to a technical conference his agency held in March to explore whether the state should solicit proposals for a coordinated independent transmission network for offshore wind generation. (See Mass. DOER Explores Transmission for OSW.)
Victoria Hackett, deputy commissioner for energy in the Connecticut Department of Energy and Environmental Protection, agreed with Woodcock that environmental justice is important to protect those people most affected by polluting energy resources.
DEEP Commissioner Katie Dykes instituted a policy that all the agency’s work has to be viewed through the lens of environmental justice, Hackett said.
Last August, about 40 environmental activists marched in front of DEEP headquarters in Hartford to protest state regulators’ approval of a new 650-MW gas-fired power plant in the town of Killingly. (See Connecticut Activists Protest Gas-fired Plant.)
FERC last week approved NYISO’s revised buyer-side market (BSM) power mitigation rules, prompting a warning from Commissioner Richard Glick that the commission had threatened the future of organized capacity markets by explicitly excluding state-supported resources from mitigation exemptions.
Thursday’s 3-1 ruling followed on a February order that partly approved NYISO’s proposal for implementing renewable resource and self-supply exemptions to the BSM rules in its capacity market and directed the ISO to submit a compliance filing revising some provisions (ER16-1404). (See FERC Narrows NYISO Mitigation Exemptions.) It also denied a request for rehearing of the February order by a handful of New York state agencies and the American Public Power Association.
Glick’s dissent aimed not so much at the exemption rules but at their selective application, arguing that FERC’s approach to BSM mitigation “has degenerated into a scheme for propping up prices, protecting incumbent generators and impeding state clean energy policies.” He warned that the commission’s efforts “to ‘save’ capacity markets are more likely to hasten their eventual demise.”
The commission on Thursday accepted nearly all the revisions in NYISO’s compliance filing, effective for new resources entering the Installed Capacity Market (ICAP) starting with interconnection Class Year 2019. Approvals covered:
NYISO’s proposal to use a “renewable exemption limit” formula to calculate a megawatt cap of renewable resources exempt from BSM mitigation specific to each mitigated zone.
Inclusion of an “incremental regulatory retirement” component in the renewable exemption limit, which will adjust the megawatt cap to reflect the retirement of resources that can be attributed to “direct” regulatory actions taking place since the prior ICAP study period. The feature is intended to address NYISO’s concern that state policies can create a supply of “out-of-market” resources that depress capacity prices.
Use of an unforced capacity reserve margin (URM) impact component in the renewable exemption limit formula, which is intended “to capture the change in the URM in a mitigated capacity zone that reflects how URM market requirements are expected to increase in response to renewable resource entry.”
Implementation of a “renewable exemption bank” through which unforced capacity megawatts not used in prior interconnection studies are “carried over” into subsequent studies, ensuring “that any UCAP megawatts derived from the other three factors — change in forecasted peak load, incremental regulatory retirements and the URM impact — remain available to qualified renewable exemption applicants in future buyer-side market power mitigation determinations, thereby keeping supply and demand in the capacity market in balance even where entry and exit are lumpy over time.”
The commission conditionally accepted NYISO’s proposed role for its Market Monitoring Unit in determining what resources qualify as incremental regulatory retirements. It directed NYISO to revise the proposal by removing the commission as the arbiter in the event of a disagreement between the ISO and the MMU and instead designate that the ISO’s decision would prevail.
“Thus, absent a Section 206 complaint, the commission will not have a prescribed role in such determinations,” FERC wrote. “We find that NYISO’s proposal invites delay to a time-sensitive process. In particular, we find that if the commission fails to act on a disagreement within 60 days, suspending the Class Year process could result in unacceptable delays to an already complex process that NYISO is working to streamline and for which developers need greater certainty.”
Rehearing Rejected
Thursday’s ruling also denied a rehearing request by the New York Public Service Commission, New York State Energy Research and Development Authority, New York Power Authority, Long Island Power Authority (referred to as the NY Parties) and APPA, which asked the commission to review its February finding that public power entities should not be eligible for NYISO’s self-supply exemption in the capacity market. The NY Parties also sought rehearing of FERC’s decision to reject a statewide 1,000-MW cap for the renewable resources exemption.
The commission disagreed with the contention by APPA and the NY Parties that the decision to exclude state resources from the self-supply is arbitrary and capricious and inconsistent with the 2015 complaint order that originally forced NYISO to alter its exemptions policy. It noted that the complaint order “expressed ‘concerns regarding the state’s ability to artificially suppress prices by channeling uneconomic entry through an exempted load-serving entity’ and directed NYISO to ‘consider the impacts of state decisions to subsidize resources that are owned or contracted for by a self-supplied load-serving entity.’”
The commission at the time had also required NYISO “to propose net-short and net-long thresholds ‘tight enough to prevent a load-serving entity from being able to deliberately overpay for a resource in an attempt to manipulate ICAP market prices in a way that benefits the load-serving entity’s other purchases from the ICAP market.’”
St. Lawrence-Franklin D. Roosevelt Power Project on the St. Lawrence River | NYPA
The February 2020 order found that NYISO “had failed to comply with these directives because NYISO’s proposal to allow certain instrumentalities of the state to be eligible for the self-supply exemption did not account for the state’s ability to suppress ICAP market prices through self-supplied load serving entities.”
The commission noted that its February ruling found “the net-short threshold is premised on the assumption that a load-serving entity’s incentive is to minimize the costs of serving its customers, and that this assumption does not hold true for certain state entities, such as NYPA,” whose own mission statement “supports the conclusion that NYPA’s main focus is the welfare of New York state as a whole,” including supporting businesses and nonprofits that provide jobs and services to the state.
FERC found that the incentive of “certain instrumentalities of the state to act on behalf of the whole state” was critical in determining whether the proposed net-short and net-long thresholds would fulfill their purpose.”
In denying the request to rehear its rejection of NYISO’s statewide 1,000-MW renewable resources exemption cap, the commission contended that the cap was inconsistent with a previous order to “narrowly tailor” such caps to mitigated capacity zones. The commission said it disagreed with the NY Parties’ contention that FERC’s requirements will result in a more restrictive cap than that considered in the 2015 complaint order.
“We further disagree that the February 2020 order interferes with New York state’s authority to determine the mix of generation resources in [the New York Control Area]. The commission does not improperly intrude on the states’ authority to determine its energy resource mix and the development of new generation merely by implementing wholesale rules affecting matters within the states’ jurisdiction.”
‘Misguided Belief’
In his scathing dissent, Commissioner Glick contended that Thursday’s ruling “perverts buyer-side market power mitigation into a series of unnecessary and unreasoned obstacles to New York’s efforts to shape the resource mix.”
Glick said the application of BSM power mitigation to entities “that are not buyers or buyers that lack market power is nonsensical. Moreover, even when applied to buyers who may have market power, mitigation must reasonably address their potential to exercise that market power.”
He argued that the commission has “abandoned” the intended narrow focus of BSM mitigation rules by no longer requiring “a resource to be a buyer, much less a buyer with market power, before subjecting that resource to buyer-side market power mitigation.”
“Buyer-side market power rules — often referred to as minimum offer price rules, or MOPRs — that were once intended only as a means of preventing the exercise of market power have evolved into a scheme for propping up prices, freezing in place the current resource mix and blocking states’ exercise of their authority over resource decision-making,” Glick wrote. “The result is an ever-expanding system of administrative pricing that is, ironically enough, justified on the basis that it promotes competition. But, in reality, the commission is not promoting anything remotely resembling actual competition.”
The “administrative pricing regimes” instead “create a systemic bias in favor of existing resources and curtail resources’ incentive and ability to compete across all possible dimensions,” he wrote.
Glick also warned that FERC’s actions to support capacity prices are encroaching on the authority of states to shape their resource mix and compromising the integrity of capacity markets, putting the future of those markets at risk.
“We got to this point largely because of the commission’s misguided belief that it must ‘protect’ capacity markets from the influence of state public policies. However, as explained below, the commission’s efforts to prop up prices by mitigating the effects of state public policies upset the jurisdictional balance that is the heart of the [Federal Power Act] and interfere with capacity markets’ ability to produce efficient market outcomes,” he said.
“The more the commission interferes with state public policies under the pretext of mitigating buyer-side market power, the more it will force states to choose between their public policy priorities and the benefits of the wholesale markets that the commission has spent the last two decades fostering,” Glick said. “Although that should be a false choice, the commission is increasingly making it into a real one.”
The California Energy Commission asked panelists last week if electric vehicles could help in “compound catastrophes,” such as the combination of wildfires and COVID-19 outbreaks that many fear will occur this fall.
Commissioners asked: Will EVs become an effective tool to store renewable power and to discharge it to the grid when needed? Could battery-powered cars be a backup for homeowners who lose electricity during public safety power shutoffs (PSPS), the intentional blackouts now commonly used by investor-owned utilities to prevent wildfires?
The general answer was “maybe,” but only if policymakers and car buyers can be convinced to see EVs as more than just clean transportation.
“There’s a lot that can be done with EVs,” said Ryan Harty, head of connected and environmental business development at American Honda Motor Co. “It’s a very large energy storage resource that’s frankly sitting there for most of the time. If we look at where cars are parked, about half the cars don’t even leave the home in a typical day — so it’s an incredible energy storage resource that’s just waiting to be exploited for the purpose.”
The problem is, EVs aren’t legally allowed, anywhere in the U.S., to connect and discharge to the grid. That will have to change for vehicles to reach their full potential, he said. “The bidirectional capability of EVs opens up the ecosystem of possibilities.”
Customers asked to pay a premium for EVs must understand the cars’ potential to power their homes or perhaps eventually send energy to the grid in exchange for payments or credits, he said.
The discussion of EVs’ role in grid resilience took place in the first of three CEC workshops on the electrification of the transportation sector on Wednesday and Thursday. Two other workshops dealt with topics such as the role of ride hailing and self-driving big rigs in the state’s push toward 100% clean energy by 2045.
The workshops are part of the CEC’s 2020 update to its Integrated Energy Policy Report.
As with a CEC microgrid workshop July 7-9, the EV resilience session was timely because the state’s annual wildfire season is approaching. (See Fearing Wildfires, PG&E to Cut Power to 800,000.)
Microgrids for resilience are taking hold, but the use of EVs to help in disasters and blackouts remains a more remote solution.
‘100% Energy Security’
At the University of California, Davis, Honda built an experimental “smart home” in 2014 and has been using it to test the capabilities of EVs. In 2016, it began using a vehicle to provide power to the home (vehicle to home, or V2H) and, in 2018, installed technology that allowed an EV to charge and discharge to the local grid (vehicle to grid, or V2G).
A Honda report showed cars are typically parked at home or work, serving little purpose 96% of the time. The automaker intends to change that, Harty said.
“We want to improve the value of this product, not just to the customer but to society, by taking advantage of the fact that it’s there for the purpose of doing other things,” he said.
Researchers have been testing V2H and V2G technologies at Honda’s smart home at the University of California, Davis, since 2016. | Honda Motor Co.
At the experimental house in Davis, the Honda EV stores 20 kWh of electricity from the home’s rooftop solar array to help power heating and cooling, cooking and hot water heating, he said. A stationary battery provides 10 kWh of additional storage.
“The home can completely isolate from the grid in the case of [an outage],” Harty said. It is “still able to charge the car … and balance itself as a microgrid, providing 100% energy security both for living and for transportation to the customer.”
He said the UC Davis research builds on resilience efforts in Japan after the 2011 earthquake and tsunami that caused three reactors to melt down at the Fukushima Daiichi nuclear power plant.
Battery Degradation
A main argument against using EVs to power homes or the grid is that repeated charging and discharging of batteries causes them to degrade more quickly. Commissioner Patty Monahan asked the resilience panel about that objection.
“Part of the reason that the automakers are not investing in this technology is … the degradation,” Monahan said. “The battery is the most expensive part of the vehicle. This is going to cause some degradation.”
Harty and others said their experiences have shown that degradation wasn’t as serious as critics suggested and could be minimized.
“We’ve studied it in depth,” Harty said. “We’ve published a couple of papers in Society of Automotive Engineers journals on the modes of battery degradation and how it relates to V2G usage.
“A couple of things the battery really hates: It really hates sitting at a very high state of charge for a long time. The battery really hates being cycled from high state of charge to low state of charge, and it hates high temperatures.”
Avoiding cycling the battery “top to bottom” repeatedly is especially important, he said.
“If you just pick a nice healthy window that you’ve established through testing of the middle of the [state-of-charge] range of the battery, and you cycle within that range, then you essentially don’t affect the long-term degradation of the battery,” Harty said.
Occasionally running a car battery to zero to power a home — for instance, to preserve food during a blackout — is OK, he said.
“It’s just like customers driving to zero range on the car,” he said. “The car’s designed to do that a certain number of times in its life.”
Panelist Bjoern Christensen, who heads Northern California advisory firm next-dimension, was formerly chief strategy officer with Nuvve, a leader in V2G technology.
Nuvve has used 10 Nissan Leaf EVs for frequency regulation in Denmark since 2016, with 240,000 hours of vehicle operation in a “very demanding application,” Christensen said. Frequency regulation in Scandinavia is relatively inflexible and must be constantly monitored and adjusted, he said.
The EV batteries have handled the task without undue damage, he said.
“We’ve been measuring the battery state of health over those four years now, and we have found no degradation that is not in line with what Nissan research has predicted,” he said. “We were very surprised that we didn’t see a lot of battery degradation. It’s something … we don’t have any problems with right now for a practical application.”
First, to thank all our front-line utility folks who have kept electricity and all other vital utility services running through the pandemic. You’ve received little recognition, but where would we be without you?
Thanking not only everyone on the lines — our front lines — but everyone working at our generating facilities and our distribution and transmission centers to keep electricity flowing continuously 24/7. True heroes.
Con Ed workers wearing face masks | Con Edison
Second, every utility (and other energy provider) has an obligation to use its standard communications to customers — covering everyone in this country — to encourage the use of face masks. This is public-purpose space that costs a utility nothing to contribute to a critical public health good. And that is to encourage everyone to wear face masks.
Let’s thank our heroes and save our customers. It’s not politics. It’s the right thing to do.
FERC last week accepted SPP Tariff revisions implementing recommendations from the RTO’s stakeholders on fast-start resources and ramping products.
The commission accepted SPP’s compliance filing on fast-start pricing but directed a further compliance filing (ER20-644). It also accepted Tariff revisions creating two new ramp capability products for both ramping up and down (ER20-1617).
The proposed Tariff revisions were both included in the Holistic Integrated Tariff Team’s 21 recommendations last year. The HITT reviewed SPP’s models, processes and operations as part of its effort to integrate the expansion of renewable energy, boost reliability, and improve transmission planning and the wholesale market. (See SPP Board Approves HITT’s Recommendations.)
FERC found SPP’s fast-start pricing practices to still be unjust and unreasonable and directed another compliance filing, saying they again do not allow prices to reflect the marginal cost of serving load. The commission last year wrapped up investigations of several RTOs under Federal Power Act Section 206 and ordered SPP to eliminate inflexible operating limits and other rules that it said were preventing prices from reflecting the marginal cost. (See FERC Orders Fast-start Rules for SPP.)
Fast-start units at Oklahoma Gas & Electric’s Mustang Energy Center | OG&E
The commission said two aspects of SPP’s proposal required further revisions. It directed the RTO to provide that, for pricing purposes, fast-start resources’ composite offers be calculated with as-committed commitment costs, regardless of the current offer.
It also ordered SPP to revise its Tariff to provide that a fast-start resource’s commitment costs will be amortized over its economic maximum operating limit and its minimum run time, striking the RTO’s use of the phrase “over an hour.” It said the revisions should provide that the grid operator will calculate the no-load cost added to each breakpoint of a fast-start resource’s energy offer curve by dividing the resource’s no-load offer by its economic maximum operating limit and by the ratio of the number of intervals needed to meet the resource’s minimum run time to the number of intervals in an hour.
FERC rejected the SPP Market Monitoring Unit’s contention that the RTO’s proposal could lead to “unmitigated economic withholding in the dispatch run, potentially resulting in unrelieved congestion and reduced reliability.” The commission found insufficient evidence in the record that the instances of economic withholding contemplated by the MMU would occur frequently enough under SPP’s proposal “to warrant additional mitigation in the dispatch run.”
The commission did agree with the MMU that SPP’s proposal presents a gaming opportunity for fast-start resources because a resource “will have the unique ability to hold its energy offer constant while changing its start-up and no-load offers, and … its composite offer.”
It found that, “on balance, eliminating this potential gaming opportunity outweighs the smaller potential for improved price formation associated with allowing fast-start resources to update their commitment offers after being committed by the market and set price for legitimate reasons in order to recover costs not otherwise recoverable in incremental energy offers.”
FERC said several other issues raised by the MMU and Golden Spread Electric Cooperative were beyond the proceeding’s scope.
SPP has 60 days to reply and must include an effective date that reflects its estimate of when development, testing and software system changes are complete.
Ramp Capability Given Go-ahead
In accepting SPP’s ramp up and down products, FERC ordered the RTO to submit an informational filing notifying the commission of the actual effective date at least 30 days before the Tariff revisions are added to the system software.
Golden Spread protested SPP’s filing, contending that it did not allow offline fast-start resources to participate in the products. The co-op also said the products would reduce the instantaneous load capacity by the amount of cleared ramp capability in a given operating interval. With the reduction, the co-op said, the instantaneous load capacity could be over-procured, leading to price distortion.
FERC agreed with the MMU, which supported SPP’s filing and said that offline resource participation would be impractical under the proposed construct. “As designed, the market clearing engine would be unable to properly evaluate or efficiently dispatch these resources,” the commission said.
Noting the MMU “commits to tracking potential issues with the demand curves going forward and recommending improvements if appropriate,” FERC encouraged SPP “to remain engaged” with the MMU and stakeholders as it gains experience with the ramp products.
Exit Fee Compliance Filing Accepted
The commission also accepted SPP’s compliance filing in a docket related to the elimination of the RTO’s exit fee for non-transmission owners (ER19-2522).
FERC in December rejected a rehearing request from SPP and its load-serving entities. It directed a compliance filing revising the RTO’s Tariff to ensure that a withdrawing non-TO is only exempt from paying a share of SPP’s long-term financial obligations and not all existing obligations associated with the member’s withdrawal. (See FERC Denies Rehearing of SPP Exit Fee Decision.)
Renewable developers like EDF Renewables, behind the Golden Plains Wind Project in Iowa, will now see lower exit costs in SPP. | Business Wire
In fully accepting SPP’s compliance, FERC rejected protests by renewable energy interests, who argued that the revisions to the grid operator’s membership agreement created “ambiguity” as to which costs would be borne by withdrawing non-TOs. EDF Renewables, RWE Renewables Americas and Savion also contended that the agreement’s provisions could be interpreted to say that withdrawing non-TOs are subject to a share of SPP’s long-term financial obligations.
The commission found that the proposed phrase “incurred by SPP directly due to the termination” requires a direct connection between the costs that SPP may recover and the membership’s termination. It said it is “reasonable” for the grid operator to recover costs it incurs directly because of a member’s termination of its membership.
FERC said the requirement that departing members pay a share of SPP’s long-term debts in the event of a partial termination does not apply to non-TO members because they “do not have load, as reflected by SPP’s proposed ‘if applicable’ language.”
The proceeding stems from a 2018 complaint by the American Wind Energy Association and the Advanced Power Alliance, which have long argued against the exit fee. (See Wind Groups Challenge SPP Exit Fee.)
The Organization of MISO States continues to signal its grid operator that regulators are ready for dynamic transmission line ratings in the footprint.
OMS invited an ERCOT executive to explain the benefits of dynamic line ratings (DLRs) at its board of directors meeting Thursday.
ERCOT Senior Director of System Planning Warren Lasher said DLRs provide value, “especially in off-peak conditions like spring and fall, when you’re likely to see more wind on the system.”
The Texas grid operator now uses dynamic ratings in 60 to 70% of its circuits, Lasher said. He said it uses data lookup tables from transmission owners coupled with local weather data to assign ratings.
“We’ve seen a significant amount of benefits, in two ways really. … We’ve seen reduced congestion, and we’re able to get more lost cost power to our customers. But we also see in our reliability studies that we can schedule more maintenance outages in the spring and fall,” Lasher told regulators.
OMS has recently been in discussions with MISO Independent Market Monitor David Patton about implementing DLRs. OMS President and Minnesota Public Utilities Commissioner Matt Schuerger said in June that the RTO’s ratings are overly conservative, inconsistent and not transparently formed.
MISO TOs have also been meeting with Monitor staff to discuss dynamic and ambient temperature-adjusted line ratings, Otter Tail Power’s Stacie Hebert said last month.
During this month’s Market Subcommittee meeting, Patton said the annual value of MISO’s real-time congestion routinely exceeds $1 billion, due in part to “very conservative, static ratings by most transmission operators.”
“I think more are becoming aware of this problem,” Patton said, citing last year’s FERC technical conference and OMS’ interest.
Patton said a “broad adoption” of ambient-adjusted ratings could have reduced congestion costs by as much as $150 million in 2018 and 2019. Over those two same years, had TOs just provided short-term emergency ratings, an additional $114 million could have been saved in congestion, he said.
However, Patton said he’s had little luck so far trying to convince individual TOs to use the technology.
OMS Executive Director Marcus Hawkins said the group will present a position statement in August on the subject. He said he believes MISO’s systems are advanced enough to accommodate the technology.
FERC on Thursday approved MISO’s request for a one-time waiver giving market participants the opportunity to replace load-modifying resources affected by the coronavirus pandemic.
The waiver will permit market participants that manage an affected LMR to register new resources with MISO to fulfill capacity obligations. FERC said the temporary measure will help ensure reliability during the pandemic (ER20-2156).
“We find that the requested waiver addresses a concrete problem because, absent this waiver, market participants whose accredited LMRs will otherwise be unable to meet their performance requirements for the 2020/21 auction,” FERC said.
MISO requested the waiver in late June, saying that some LMRs that cleared the 2020/21 Planning Resource Auction may not be able to perform because of closures of businesses that would otherwise be used to control load. (See MISO Drafts COVID-19 Waiver for LMRs.) The waiver is considered effective July 15, and market participants have 90 days to register replacement LMRs.
FERC said MISO’s plan is reasonable and doesn’t carry unintended consequences for third parties. No parties protested the RTO’s request.
“The waiver will provide certain market participants affected by the COVID-19 pandemic additional flexibility to satisfy their LMR performance requirements; market participants who have registered planning resources that are not affected by the COVID-19 pandemic will not be impacted by this waiver,” the commission said.
This is MISO’s second filing for a waiver of Tariff requirements as the pandemic plays out. Some interconnection queue customers now have longer to secure proof-of-land use for their proposed generation projects. FERC granted MISO’s request for a 60-day extension of its June 25 site control demonstration deadline in May, when the pandemic locked up government offices and held up construction plans (ER20-1794).
