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 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.
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.
KEPCo’s Les Evans Steps Away
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.
