Page 1066 – RTO Insider

August 3, 2020January 15, 2025

SPP Board of Directors/MC Briefs: July 28, 2020

SP P‘s Board of Directors last week approved a staff recommendation that resolves six months of uncertainty over the weighting of futures in the 2021 transmission planning assessment.

Staff said a 50/50 weighting of the two futures in the 2021 Integrating Transmission Planning (ITP) study would acknowledge the lack of consensus over each future’s relative probability. They also suggested that any project that could not be justified under a 60/40 weighting be highlighted for further consideration.

The Markets and Operations Policy Committee earlier in July rejected the 50/50 weighting and two other suggestions during its third fruitless attempt to approve an issue that left stakeholders flummoxed. (See “Members Unable to Agree on Weighting Futures in 2021 Tx Plan,” SPP MOPC Bri e fs: July 15-16, 2020.)

The Economic Studies Working Group (ESWG) in January 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 Members Committee approved the recommendation 13-5, with a mix of transmission owners and users in opposition.

Stakeholders have struggled over Future 1’s assumption of 32 GW of installed wind capacity in 10 years and where the primarily renewable resources would be sited. SPP has said it will have 27 GW of wind capacity by the end of this year.

Oklahoma Gas & Electric’s Greg McAuley, one of five members to oppose the motion, advocated for a 70/30 weighting of the futures that leans more toward uncertainty.

“If you assume solar begins to expand at the same rate wind has over the last 10 years, is it reasonable to assume that expansion will take place in similar locations or be closer to load?” he asked. “These assumptions about resources, without associated firm transmission, kind of leaves us exposed. We will have built transmission to accommodate resources no longer available to the market.

“If you put transmission in the ground, we’re committed to it. Our customers will be paying for those facilities for a long time,” McAuley said.

Board Chair Larry Altenbaumer | SPP

SPP Vice President of Engineering Antoine Lucas pointed out that either weighting would not have affected the last three ITPs’ project portfolios.

“The best way to address this is to focus more on the sensitivity analysis of individual projects and the assumptions that drive the benefits for those projects,” he said. “If [a project] says more wind [will result], we believe we should run sensitivities around it and test the assumptions. We already do that, whether it’s the amount of wind or fuel prices.”

“What staff has proposed is to basically provide all of us with a bit of a safety net,” said Board Chair Larry Altenbaumer during the July 28 web meeting. “If there is something that is justified in the 50/50 weighting, but not in the 60/40, that allows us to dig into more detail to understand the ramifications, [then] this has taken us a step in the right direction, while recognizing there are more steps we need to take.”

Agreement on Competitive Project’s Path Forward

Stakeholders were able to reach an agreement over the suspension of a competitive project that SPP agrees would provide numerous benefits to the eastern edge of its footprint, where congestion remains a problem.

Several members wanted to lift the suspension and issue a request for proposals. However, staff cautioned the move would open a seven-day window during which they would have to issue the RFP. The RTO would also be within an 18-month window to issue funds for the project.

The 345-kV Wolf Creek-Blackberry project in Kansas and Missouri with Associated Electric Cooperative Inc. (AECI) was approved by the board last year and was included in the 2020 SPP Transmission Expansion Plan passed in January. Part of the 105-mile project, projected to cost $152 million, would be on the AECI transmission system and constructed by the cooperative. SPP cannot allocate funds to AECI without FERC approval.

The board in April suspended the project, pending negotiations with AECI and FERC’s approval of a cost-and-use agreement. Staff said AECI has reached a verbal agreement but has not yet provided SPP a signed document. (See “Directors Suspend Competitive Upgrade,” SPP Board/Members Committee Briefs: A p ril 28, 2020.)

General Counsel Paul Suskie said several risks preclude lifting the suspension. “First, whether or not we can reach a timely agreement with AECI,” though he admitted an agreement is expected within days.

Other risks include FERC’s perspective after a pre-filing meeting with commission staff and potential protests that could delay a final order, Suskie said.

“Once an agreement is signed and filed at FERC, we’re in a much better position when we see whether any protests are filed,” he continued. “The risks are further minimized as we move further out on the timeline.”

Altenbaumer suggested members wait until the agreement is executed and filed with FERC “as soon as possible.” That would open a 20-day period for any protests, during which time SPP staff could prepare the RFP.

“One thing I’m concerned about is if challenges are made to that filing, and not knowing what those objections are or FERC’s action on that filing, and how they could undercut the AECI agreement,” Altenbaumer said. “We will then have been out there with an RFP that would not be a viable RFP.”

By late August, he said, “we’ll know … more information than where we are with the FERC filing.”

“We can work with you on trying to find a path forward,” said Evergy’s Denise Buffington, who helped pen a let t er from four member utilities asking that the suspension be lifted. “Keep in mind this project is likely to be delayed even if the RFP is issued by Oct. 1. We are looking for an outside date of Oct. 1, and the path you have outlined will accommodate that.”

Evergy was joined by American Electric Power, Liberty Utilities and City Utilities of Springfield (CUS) in asking the directors to issue the RFP no later than Oct. 1. The signatories said the suspension’s initial rationale was that the cost of the AECI Blackberry termination point was unknown and noted that “these costs are now known, negotiations are complete, and the [agreement] … is about to be filed.

“Because of the critical importance of the proposed line and the benefits provided to SPP customers, the board should not further delay the RFP process,” the companies wrote.

“We own the Wolf Creek substation. It will take a minimum of four years to get work done inside the substation. The longer the delay on the NTC, the less likely we will get that in time,” Buffington said during the discussion. “We’re also worried there will be protest … we think the FERC proceeding should run in parallel with the RFP. All the information needed to issue the RFP is available to SPP today.

“As the letter points out, there are a bunch of reliability issues at stake,” she said. “This project was very, very close to being a reliability project. If it gets restudied, it could be a reliability project.”

Board OKs 4 HITT Recommendations

The board and members approved four recommendations stemming from last year’s Holistic Integr a ted Tariff Team report, bringing the total of completed recommendations to eight out of 21.

The board sided with MOPC and the ESWG’s recommendation to keep the ITP’s benefit/cost ratio for economic projects at 1.0, rather than increase it to a range between 1.05 and 1.25. Members approved the recommendation by a 15-5 vote.

Golden Spread Electric Cooperative’s Mike Wise, one of those opposed to the 1.0 B/C ratio, said transmission buildouts are “problematic” going forward when looking at benefits and costs.

“The costs are well-known ahead of time. The real issue here is [that] the benefits are estimated and not well-known,” he said. “[The benefits] are engineering estimates 40 years into the future. It’s really difficult to grasp the benefits that come from this.”

Wise found support from McAuley and Oklahoma Municipal Power Authority’s (OMPA) David Osburn.

“This is yet another example of where we are, as Mike would put it, doing this as usual, when business is anything but usual,” McAuley said. “At what point do we stop building transmission, so our transmission rates stop going up?”

“I want to stress the point [Mike] made is very valid,” Osburn said. “We make these decisions and invest in 40-year assets. We’re spending consumers’ money here, and I think they would like to see a benefit-to-cost ratio much greater than one, and one that doesn’t take 40 years to get there.”

While Dogwood Energy’s Rob Janssen and NextEra Energy Resources’ Holly Carias supported the motion, they agreed the motion warrants further analysis.

“Greg made a good point about looking out at the future and looking at economic projects more broadly,” Janssen said.

“I can’t disagree with Mike Wise and Greg that we’re in a different scenario,” Carias said. “We need to reconsider benefits.”

The board also signed off on the Cost Allocation Working Group’s white pap e r that evaluated SPP’s cost allocations for transmission projects between 100 and 300 kV that are primarily used to move power out of the local transmission pricing zones.

The Members Committee approved the motion to accept the white paper by an 11-5 vote. CUS, OG&E Transmission, OMPA, Public Service Co. of Oklahoma and Xcel Energy’s Southwestern Public Service Co. (SPS) opposed the motion.

The Regional State Committee earlier voted to endorse the white paper by a 6-5 margin.

SPS President David Hudson asked that the minutes reflect that the white paper “is a controversial issue.”

Kansas’ Sunflower Electric Power is among those that stand to benefit from the paper’s recommendation to establish a “narrow” cost-allocation review that regionally distributes the revenue requirements for the lower voltage levels. Sunflower CEO Stuart Lowry said that while the review would grant waivers from the methodology, “by no means is that a guarantee a waiver will be granted.”

“We would have to make that case before MOPC and the Board of Directors,” he said. “Bear in mind that action today does not mean byway cost-allocation relief will be granted to Sunflower or anyone else.”

Members unanimously approved two other HITT items, a staff report on essential reliability services (ERS) and other reliability services (ORS) and a revision request (MWG RR 4 0 2) that improves the Integrated Marketplace by using near real-time economic dispatch to evaluate intraday reliability unit commitment for committing fast-start resources near real time.

The ERS/ORS report evaluated the region’s reliability challenges with a changing resource mix by conducting three separate engineering studies on reactive supply, primary frequency response and flexible capacity supply. The Market Working Group will now be asked to work on an ERS/ORS compensation mechanism.

Gaw’s Voice Becoming More Prominent

Advanced Power Alliance’s Steve Gaw, a ubiquitous presence at SPP meetings for more than 17 years, took some good-natured ribbing when his name mistakenly appeared on a Members Committee list as the board meeting began.

Steve Gaw, APA | © RTO Insider

“Steve Gaw … that’s a strange name,” Altenbaumer said, taking a jibe at SPP’s newest member representative. “I’m not sure why he’s on the list, but we’ll let it go this time.”

A former chair of the Missouri Public Service Commission, Gaw was among the founding members of SPP’s Regional State Committee in 2003. He has since frequently voiced the wind industry’s concerns in stakeholder meetings, taking advantage of SPP’s practice of allowing non-members to add their input during discussions.

When Gaw commented during the ITP futures weighting discussion, he first asked whether he could be heard.

“I hear you fine. I’ve never had a problem hearing you, Steve,” Altenbaumer responded.

The APA, an industry trade association supporting renewable generation and energy storage in SPP and ER C OT, recently joined the RTO as its first alternative power/public interest member. As a member, the organization now has a vote and can officially join stakeholder groups. (See “Advance Power Alliance Now an SPP Member,” SPP Br i efs: Week of July 20, 2020.)

SPP said a clerical error resulted in Gaw’s name being included among the Members Committee’s list of 21 names. The Corporate Governance Committee must first nominate Gaw as representing the alternative power/public interest sector and the nomination be approved before he can cast a vote.

“I can only speak, “Gaw said later, noting he was invited to the board and committee’s executive session.

No Virtual Roll Call

With more than 250 persons calling in to the webcast, SPP’s Dustin Smith, who facilitated the meeting, declined to take attendance through a roll call.

“That’s virtually impossible to do virtually,” he said.

Consent Agenda Passes

The board’s consent agenda included approval of:

The Finance Committee’s 2021 operating plan, which includes developing a strategic plan for the next five years, implementing the HITT recommendations and completing generator-interconnection study requests from 2019 and before.
MOPC’s approval of RR404, which further defines the resource adequacy requirements for demand response programs and behind-the-meter generation, and its recommendation for a $20.7 million cost reduction to Basin Electric Power Cooperative’s Multi-Kummer Ridge-Roundup project in North Dakota.
A waiver of financial obligations under the membership agreement to East Texas Electric Cooperative for its transfer of transmission facilities and load from MISO to SPP and from SPP to ERCOT. The cooperative transferred facilities and load from MISO last year and is scheduled to transfer facilities and load to ERCOT between October and January. ETEC requested the waiver because it will wind up transferring more load into SPP than out, which would have triggered a partial termination.
Staff’s recommendation for out-of-cycle re-evaluations for notifications to construct an Evergy Metro 161-kV project in the Kansas City area and an OG&E 138-kV project.
Appointment of Omaha Public Power District’s Joe Lang to an open transmission owner’s seat on the Human Resources Committee. He replaces Nebraska Public Power District’s Tom Kent, who in March was promoted to CEO.

August 3, 2020

CPUC Questions CAISO Day-ahead Capacity Plan

CAISO’s proposal to develop new capacity products through its day-ahead market enhancements (DAME) initiative could radically transform California’s resource adequacy landscape while not yielding expected benefits, a key skeptic of the plan said last week.

“I agree that in the vast majority of situations having a market price is an extremely valuable thing [and] I’m not trying to come down on either side of this one right now. I’m just saying it’s a philosophical change in the way these [RA resources] are being paid that we should think about,” Mike Castelhano, an analyst with the California Public Utilities Commission, said during discussion of the proposed capacity products at a CAISO Market Surveillance Committee (MSC) meeting Thursday.

The ISO launched the DAME effort earlier this year to expand its day-ahead market with two new nodal product offerings that would significantly alter market operations:

a reliability capacity (RC) “up/down” product to help the ISO match its net load forecast (the load forecast minus the variable energy resource forecast) with sufficient non-VER supply for one-hour intervals; and
an imbalance reserves (IR) product procured for 15-minute intervals “to provide flexible capacity to accommodate the increasing uncertainty and variability of real-time net load.”

Both products would be offered on a nodal basis, an approach CAISO thinks will best guarantee those supplies will be available when and where they’re needed to ensure flexibility on a grid increasingly dependent on VERs. The DAME straw proposal envisions co-optimizing procurement of both new products — along with day-ahead energy and ancillary services — to improve scheduling efficiency.

CAISO Day-ahead Capacity Plan — Graph illustrates price differences for the same intervals among CAISO’s day-ahead (blue), hour-ahead (orange), 15-minute (green) and 5-minute markets (purple). The ISO’s DAME initiative is particularly aimed at closing the discrepancies between day-ahead and 15-minute prices. | *CAISO*

That new process would replace the existing residual unit commitment (RUC) process for ensuring resource sufficiency, in which the day-ahead market procures the incremental capacity needed to meet reliability requirements after the ISO has run its co-optimized integrated forward market (IFR) for day-ahead energy and ancillary services. The incremental capacity obtained through RUC represents the delta between what the IFR has cleared from economic bids and “the amount needed for reliability based on the net demand forecast and potential uncertainty,” the ISO notes in the straw proposal.

“The disadvantage of this sequential RUC process is that the capacity it procures is not co-optimized with the resource commitment and energy schedules produced by the integrated forward market,” CAISO said in explaining the move to the new model.

‘Vanilla’ RUC vs. Spot Market

While CAISO has counterposed two methods for compensating suppliers of the two new products, it clearly favors one option over the other.

Under the “vanilla RUC model” (as ISO Market Design Policy Specialist James Friedrich put it), resources that have been awarded contracts under the CPUC’s RA program could offer into the market at zero price and forego being paid market clearing prices for RC and IR. In that scenario, CAISO would assume the prices of RA contracts — which subject holders to a must-offer obligation (MOO) in the ISO market — “would, in part, reflect owner expectations about magnitudes and frequency of short-run costs incurred to provide RC/IR.”

According to the ISO, the RUC model approach to compensating the new capacity products would be the least disruptive to California’s current RA system because it wouldn’t require renegotiation of existing RA contracts, changes in CPUC rules around cost recovery for RA assets or revisions to CAISO’s MOO Tariff provisions. It would also avoid the need to mitigate market power for RC/IR offers.

Those advantages notwithstanding, CAISO — and the MSC — are advocating implementing a “spot market model” as much as possible to compensate providers of the new capacity products, with the hope that short-term market offers will more precisely reflect variable costs for making capacity available, including natural gas costs and the opportunity costs of not bidding into the real-time market. That arrangement would provide suppliers a stronger incentive to make resources available, according to the MSC.

Use of that model would also eliminate the must-offer obligation for contracted RA resources, which should reduce the number of zero-price offers and increase clearing prices (while also increasing the risk of double-payment before RA contracts can be renegotiated, CAISO acknowledged). That would have the upshot of opening up California’s capacity market to non-thermal resources, helping the state achieve its ambitious carbon reduction goals, one MSC member noted.

“One of the characteristics of the current design is that … demand response can’t compete to provide RUC capacity because thermal RA units are free,” said the MSC’s Scott Harvey. “And they’re not really free, but it gets rolled into the RA price, so you don’t see a separate price signal for [whether] demand response [could] provide this RUC capacity, which is really back-up capacity that we don’t need but we want to have in reserve in case we do need it. And that’s probably an ideal role for demand response … so that’s another long-run goal that could be achieved if we make this change.”

MSC member Jim Bushnell said a long-term focus of the committee is providing “short-run marginal incentives to reward units that provide truly valuable reliability capacity” and incentivizing resource availability.

“The problem with RA has been that we don’t know a year in advance and a month in advance exactly when and what types of units provide what type of value. That’s constantly changing, so the importance for short-run incentives is large here,” he said.

CPUC Concerns

CPUC’s Castelhano said he understood Harvey’s concerns about DR being unable to function as RA capacity in the CAISO market. But Castelhano noted that the RA zero-bid requirement is a CPUC capacity designation rule and not “really a RUC rule.” He cautioned CAISO against making changes that could alter the zero-bid practice in the wholesale market or pushing to revise market rules in a way that would allow DR to function as RA in California.

“The rules for RA and DR are not as well-developed, and that’s a process that’s ongoing, and I think we have to recognize that’s not something that should change at the CAISO necessarily,” Castelhano said.

“I wasn’t arguing for a change in the rules regarding DR that is RA capacity,” Harvey said, clarifying that his focus is on enabling DR — “whether or not it’s RA capacity” — to compete to provide RUC. “That’s the CAISO issue.”

Castelhano also called out CAISO for not discussing how transformative the ISO’s changes could be for California RA, potentially transforming the program from a structure based on contracts to one reliant on a spot market.

“Sure, it gets the costs out of the RA contracts, potentially, but it also then pays a market mechanism-based price to everybody that clears in that market, whereas right now the RA costs are individual” and cost based, said Castelhano. A system based on a clearing price could allow some suppliers to earn inframarginal rents — where a supplier gets paid above its costs in an otherwise competitive market.

MSC Chair Ben Hobbs acknowledged that consumers could benefit if the utilities contracting for RA hold prices down because of monopsony market power and pass on those savings. But he said it is not clear that would happen because visibility into RA contract prices “is not exactly a strong point” in California’s market.

“RA contracts tend to be near some market-clearing level, but from an efficiency point of view, hearkening all the way back to the early days of the California market of pay-as-bid versus market-clearing price, folks who have been on the MSC have tended to favor [a] single market-clearing price for its transparency and incentives,” Hobbs said. “But you might have a point. If the utilities can price-discriminate on RA perhaps there will be less ability to do that in the future, which might conceivably increase what consumers pay and provide more of the inframarginal rents to resources.”

Castelhano also questioned CAISO’s presumption that the new capacity products would reduce some of the “guesswork” behind calculating the costs of RA contracts because income for RA resources would be based on actual short-run costs rather than on a longer-term estimation of those costs.

“My speculation is that it would go very much in the opposite direction because right now part of the RA contract depends on one variable stream of income from sales into the ISO market, and you’re going to create another possibly more variable stream of income,” he said.

Hobbs countered that the proposal’s provision allowing RA resources to buy out their must-offer obligation or bid costs in the ISO market would reduce the cost risks of having a fixed MOO negotiated far in advance of potential deliveries.

“I guess that needs some more analysis, but I don’t agree with what you’re saying there,” Hobbs said.

Castelhano concluded with “a really big concern” that CAISO is considering limiting the participation of energy storage resources in the imbalance reserve markets. He noted that the CPUC’s integrated resource planning process is assuming that storage resources will play a key role providing flexibility needed to integrate variable renewables.

“If [storage] resources are not able to participate in this imbalance reserve market, then I’m very concerned about that,” Castelhano said. “If we’re paying hourly dispatchable resources instead of the stuff that can move really fast, then that’s another concern.”

August 3, 2020

Wind May Soon be SPP’s No. 1 Fuel Source

Wind energy is on track to be SPP’s No. 1 fuel source this year, executives said last week during the grid operator’s quarterly stakeholder update.

Wind production averaged 11 GW for the month of June and has accounted for 33.8% of the grid operator’s fuel mix halfway through the year. During the last three months, SPP has set footprint records for the amount of wind energy produced (18.3 GW on July 17) and the amount of wind in the fuel mix (73.2% on April 27).

“The wind continues to blow,” SPP CEO Barbara Sugg told stakeholders July 27.

SPP wind — SPP CEO Barbara Sugg delivers her quarterly report. | *SPP*

Over the last 12 months, wind has provided an average of 31.2% of the fuel mix, compared to 29.8% and 26.6% for coal and natural gas, respectively.

That has caused Bruce Rew, the RTO’s senior vice president of operations, to reconsider his prediction of when wind energy would become the No. 1 fuel source.

“I used to say wind would be our No. 1 fuel in 2021, but wind should become our No. 1 fuel this year,” he said. “It seems to be happening quite a bit faster than we thought.”

SPP currently has 24 GW of installed wind capacity, a figure it expects to grow to 27 GW by the end of the year.

Rew said the RTO’s electricity demand had fallen as much as 8 to 10% below forecasts as the COVID-19 pandemic took hold. Load has since returned to normal, he said.

In her CEO’s report, Sugg said cancelling in-person meetings and stopping business travel in March is expected to result this year in the over-recovery of $12 million in system administrative fees. That could contribute to reductions in SPP’s 2021 net revenue requirement, she said.

Sugg assured stakeholders the RTO is committed to remaining affordable and will continue holding most of its meetings virtually next year.

“Cost containment is a big item for me,” she said.

Sugg spoke from an empty conference room at the company’s corporate center in Little Rock, Ark. “It’s much better wi-fi than at home,” she said.

The corporate center has been closed to most of SPP’s staff since March. Sugg said she is hopeful of allowing employees to voluntarily return after Labor Day but said the campus won’t be fully staffed until sometime next year, “hopefully earlier, rather than later.”

Complicating matters is that Arkansas has become one of the country’s COVID-19 hot spots. The state has recorded more than 43,000 cases and 458 deaths through Aug. 1, with cases still trending up.

“You can’t go anywhere else unless you quarantine first,” Sugg said. “It’s not something we’re proud of.”

SPP has had several positive cases but no hospitalizations. The operations staff remains unaffected, Sugg said.

“Our employees are able to work from home, and work effectively,” she said. “It’s a lot of strain on our company, but things are going really well.”

RSC Approves Tx Allocation White Paper

Meeting before the quarterly stakeholder update, the Regional State Committee narrowly endorsed the Cost Allocation Working Group’s (CAWG) white paper evaluating the RTO’s cost allocations for transmission projects between 100 and 300 kV that are primarily used to move power out of SPP’s local transmission pricing zones

The RSC signed off on the white paper 6-5, with commissioners from Arkansas, Louisiana, New Mexico, Oklahoma and Texas in opposition.

SPP refers to lower-voltage economic and reliability projects as byway projects, with 33% of the costs regionally funded based on member utilities’ load-ratio share and 67% funded by the facility’s transmission pricing zone. Projects above 300 kV are considered highway projects and regionally funded according to load-ratio share.

Following a year of work, the CAWG report recommends establishing a “narrow” cost-allocation review so that the revenue requirements for certain facilities with byway voltage levels can be fully distributed on a regionwide basis.

The group also recommended that the review process include new and existing Schedule 11 facilities and that the review criteria be based on the use or expected use of the transmission facility. Schedule 11 rates reflect the costs of facilities whose costs are shared in whole or in part on a regional postage stamp basis. The rest of the costs are allocated to the facility’s transmission pricing zone.

The CAWG’s recommendations would apply to facilities with notifications to construct issued after the 2010 implementation of SPP’s highway/byway methodology. The methodology includes an exception for base plan upgrades below 300 kV and associated with wind generation. In that instance, 67% of the upgrade costs are allocated to the region, and the remaining 33% are directly assigned to the transmission customer requesting service.

The white paper would allow affected entities to request a waiver from the allocation methodology. Directly assigned facilities would not be eligible. The CAWG used the Tariff’s language on dual-voltage transformer waivers, based on their usage, as a model for the byway cost-allocation waiver process, noting only four transformer waivers have been requested.

The CAWG said that in some zones with more generation than load, upgrades identified through SPP’s transmission-planning process “are being used regularly on a more regional basis.”

“In such cases, allocating 67% of the cost of an upgrade may not be roughly commensurate with the benefits received and thus it may be more appropriate that such lines be regionally cost allocated,” the group said in the white paper.

“I keep hearing it’s a surgical approach and that not very many people will apply, but that’s only an assumption,” said Oklahoma Commissioner Dana Murphy, asking for more time to build consensus.

Texas Public Utility Commission Chair DeAnn Walker said two of her state’s three largest utilities have concerns with the issue and questioned whether they had been heard during the stakeholder process.

“I don’t disagree … that there has been a lot of work on this and that it has high potential,” she said. “I know concerns have been voiced to me that people believe a lot of entities will end up applying for this. I would like to see language added to try and make sure the words ‘narrow process’ are truly that.”

Al Tamimi, vice president of transmission planning and policy for Sunflower Electric Power, has spent the last several years pushing to resolve the issue facing utilities in wind-rich areas, like his in western Kansas. He applauded the CAWG’s white paper, which includes a Sunflower presentation, and noted the importance of revising allocation ratios based on “the ratio of power exported to other zones versus local-zone usage.”

“It’s actually the right solution at this moment,” he said. “We have pricing zones sitting out there in generation-rich areas that export three to four times their load through byway facilities. We’ve been working for three years on this. We brought data and we brought facts to come up with this conclusion. This process helps sustain the highway/byway methodology as it is.”

Albrecht Honored for 6 Years of Service

Stakeholders gave former Kansas Commissioner Shari Feist Albrecht a virtual send-off after six years on the RSC. Albrecht, having served eight years, cycled off the Kansas Corporation Commission after her term ended in March.

“I’m humbled and honored by the recognition. My success can only be measured [by] and credited to the people I was surrounded by,” said Albrecht, who presided over the RSC in 2018. “I found myself to be a much better commissioner, a better-informed commissioner, as a result of my service on the RSC.”

Walker, who has replaced Albrecht as the RSC lead on the liaison committee working with MISO, SPP Regulators Mull Seams Recommendations.)

“I agreed, reluctantly, to step into her shoes. I don’t think I’ll do as good a job as her, but I will try,” she said, borrowing a page from the legendary football coach and his equally legendary propensity for “poor-mouthing.” (“Bryant … elevated it to such an art that listeners would wink and smile at his dire pregame evaluations,” Sports Illustrated wrote in 1994.)

Albrecht’s RSC seat has been filled by Andrew French, who was appointed to the KCC in June. A commission staffer for five years, French has worked with the CAWG and RSC.

“He has SPP blood in his veins,” said SPP Board Chair Larry Altenbaumer.

Two Revision Requests Approved

In other business, the RSC endorsed a pair of revision requests and approved a clean audit of the committee’s 2019 budget.

RR373 includes base plan funding for transmission upgrades identified by SPP’s generator retirement process. 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.

The Transmission and Operating Reliability Working Groups agreed during the July Markets and Operations Policy Committee meeting to modify the measure’s language for a planned filing at SPP MOPC Briefs: July 15-16, 2020.)

Murphy addressed the use of reliability must-run policies that would keep a generator operating. She noted utilities tend to follow regulatory orders requiring a shutdown.

“Given a choice between breaking the law and breaking SPP’s rules, they’ll break SPP’s rules,” Murphy said.

RR404, previously approved by MOPC, defines the requirements for demand response programs and behind-the-meter generation to ensure their availability for meeting resource adequacy requirements and winter season obligations. The change addresses whether the resources 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.

RSC President Dennis Grennan of the Nebraska Power Review Board said Arkansas’ Kim O’Guinn will chair a nominating committee that will bring the RSC’s 2021 officer candidates to the October meeting. Murphy and New Mexico’s Jeff Byrd will also participate on the committee.

August 3, 2020March 11, 2025

FERC Rejects SPP’s WEIS Tariff

FERC on Friday sent SPP back to the drawing board, saying its proposed Tariff for its Western Energy Imbalance Service (WEIS) market fails to respect transmission rights of non-participants and could improperly burden reliability coordinators. The commission also cited shortcomings on supply adequacy, market power protections and line-loss calculations (ER20-1059 , ER20-1060).

“We recognize the potential benefits that the WEIS market could bring to utilities and customers in the Western Interconnection … and we appreciate the efforts by SPP and the market participants to develop regional solutions,” FERC said. “… Although we reject SPP’s proposed WEIS Tariff, we do so without prejudice and provide guidance on other aspects of SPP’s proposal that may require revisions to ensure SPP’s proposal is just and reasonable.”

SPP said it is reviewing the order and plans to “address [FERC’s] concerns” in a subsequent filing.

On Monday, SPP’s Market Monitoring Unit (MMU) posted a market power study on the WEIS market that concluded it presents “significant structural market power concerns” for energy and imbalance energy that should be addressed before the market’s implementation.

The MMU said market share, supplier concentration, residual supply index (RSI), and pivotal supplier analysis all indicate “high potential structural market power in the WEIS Market.”

Given its “substantial concerns,” the MMU recommends SPP and WEIS market participants consider developing a system-wide mitigation measure and using cost-based offers if the mitigation measures cannot be implemented before the market goes live.

SPP had hoped to launch WEIS in February. At launch, WEIS will include eight members and cover the Western Area Power Administration’s (WAPA) Colorado Missouri (WACM) and Upper Great Plains West (WAUW) balancing authority areas.

During the July 27 quarterly stakeholder update, Bruce Rew, SPP’s senior vice president of operations, said the RTO has received interest in WEIS from “a couple of other entities” who would sign on after the launch. Staff was preparing to begin market trials in August. (See “WEIS Market ‘At Risk,’ Waiting on FERC Approval,” SPP Briefs: Week of July 20, 2020.)

Use of Non-participants’ Transmission

Colorado utilities Xcel Energy-Colorado, Colorado Springs Utilities, Platte River Power Authority and Black Hills Energy, all of which plan to join CAISO’s Western Energy Imbalance Market, protested the WEIS filings. They contend that an existing and neighboring joint dispatch agreement could be impaired by the WEIS market dispatch and that its market flows may harm the Western Interconnection Unscheduled Flow Mitigation Plan. They also contend SPP’s proposal disregards the Northwest Power Pool’s activities and could island Xcel’s balancing authority area from the NWPP reserve sharing group.

The commission agreed with some of those concerns, saying SPP proposed using non-participating entities’ transmission in a manner that would violate Orders 890 and 890-A.

“Under the pro forma OATT, a transmission customer must reserve and pay for transmission service on a transmission provider’s system. Although SPP indicates its intent to use transmission that is reserved and contributed by participating entities, SPP also argues that it appears just and reasonable to allow all unused transmission capability within participating [balancing authority areas], whether reserved or otherwise unused on an intra-hour, as-available basis, to be made available to the WEIS Market’s least cost dispatch.”

SPP RTO, RC and WEIS footprints | SPP

FERC disagreed with arguments by SPP and WAPA that because the balancing authority is currently permitted to use any transmission in the WACM and the WAUW BAAs to serve imbalance, the WEIS market could also use all available, unused transmission in these BAAs.

“Although non-participating entities who take imbalance service from WAPA under existing contracts may currently have an expectation of WAPA’s use of their transmission to serve imbalances on their systems, SPP has not justified its proposal to alter WAPA’s current use of transmission to serve customers’ imbalance needs to a potentially more expansive use of transmission for the WEIS market,” FERC said. “As Xcel points out, this proposal would allow the WEIS market to use a far greater amount of a customer’s transmission capacity than the customer’s amount of imbalance in order to serve other customers.

“In fact, as Black Hills Service Co. asserts, it appears that under the proposal the WEIS market could use non-participating entities’ transmission capacity without compensation, even when those non-participating entities have no need for imbalance service in a particular hour, because the reorganized dispatch will likely involve wheeling of power across multiple transmission systems. SPP’s proposal therefore may limit the use of non-participating entities’ transmission capacity that is currently available for other purposes, such as the [Public Service Co. of Colorado joint dispatch agreement].”

The commission said any future proposal should ensure that the WEIS market respects the transmission capacity of non-participating entities with appropriate constraints in its security-constrained economic dispatch (SCED). “If SPP is not able to reach an arrangement with non-participating entities to use their transmission capacity, SPP must include constraints in its market model to appropriately respect the transmission rights of non-participating entities when calculating the market solution,” it said.

The commissioners noted that CAISO’s Western EIM offered a memorandum of understanding among the ISO, Bonneville Power Administration and PacifiCorp to ensure that EIM transfers would not adversely impact non-participants. “We encourage SPP to coordinate proactively with its neighbors to address these operational concerns prior to resubmitting any proposal,” FERC said.

Role of Reliability Coordinator

FERC also found SPP presumptuous in expecting that reliability coordinators and transmission operators will provide WEIS with data on the availability of transmission, saying the RTO had not proven its proposal will ensure accurate, real-time information about available transmission and congestion.

“While this obligation is not currently a concern because SPP is both the reliability coordinator and market operator for the entire WEIS footprint, SPP states that the WEIS market is flexible to operate across multiple reliability coordinator footprints. If the market expands to include participants that are not within the SPP West RC footprint, it could potentially impose an obligation on neighboring reliability coordinators to act as a conduit for market-related information in a way that is outside of the role for reliability coordinators envisioned by NERC,” the commission said.

It said SPP could propose a different arrangement to obtain information on transmission availability and other system conditions that do not rely on roles defined by NERC.

Other Issues

FERC also said it was unclear how SPP’s proposal would incentivize market participants to maintain supply adequacy.

“While the NERC reliability standards establish requirements for the reliable operation of the bulk electric system, it is not clear that reliance on these standards and after-the-fact reporting to the commission is sufficient to avoid market participants excessively leaning on the other market participants for energy supply,” it said. In the Western EIM, it noted, CAISO limits the imbalance imports of EIM entities that fail a resource sufficiency test.

SPP’s proposal to use the “average cost” method of accounting for line losses also was criticized by the commission, which cited prior rulings finding that under LMP, the use of marginal losses “better represents the optimal and efficient solution for settlements.”

It said SPP should consider including marginal losses in dispatch and LMP to “minimize imbalance costs, provide prices that accurately reflect marginal costs and preserve resources’ incentives to follow dispatch. The omission of marginal losses from dispatch prevents production costs from being minimized and could result in a less efficient market solution, especially in a geographically large market such as the WEIS market.”

Finally, FERC called for more assurances on market power mitigation.

“Other than an unsupported reference to the SPP [Market Monitoring Unit’s] analysis of six hubs, SPP has not provided any justification for its proposal to automatically increase the threshold below which energy offer curves are not subject to mitigation and the LMP impact threshold,” it said. “… SPP should either remove the automatic increase provisions or otherwise justify their inclusion.”

In its market power study Monday, the MMU said its RSI analysis revealed that if the WEIS market’s largest supplier was removed, generation can still meet demand about 50% of the time.

“This result can provide a basis for implementing mitigation measures for system-wide market power, similar to those implemented in other markets,” the MMU said, using as an example an ISO-NE mechanism that identifies system market power. “This approach … can act as a blueprint for the WEIS Market.”

“The mitigation measures in the proposed tariff and in the response to [FERC’s] deficiency letter will provide sufficient protections for participant conduct to exercise of market power with implementation of system wide mitigation measure(s) as recommended in this study,” the Monitor said.

The MMU said it relied primarily upon FERC precedent in assessing structural market power for approval of market-based rate authority applications in conducting its study. The MMU analysis defined relevant product market(s) and a relevant geographic market as two components of the market. It then assessed structural market power with the help of market concentration, market share, RSI and pivotal supplier analysis metrics within those defined product and geographic markets.

August 2, 2020

PSEG Seeking to Sell Fossil, Solar Generation

Public Service Enterprise Group (PSEG) is putting its solar and fossil fuel generation on the block as it seeks to transform into a primarily regulated electric and gas utility, company officials announced Friday during its second quarter earnings call.

In his present a tion, PSEG CEO Ralph Izzo said the company is “exploring strategic alternatives” for its non-nuclear-generating fleet, which includes more than 6,750 MW of fossil generation in New Jersey, Connecticut, New York and Maryland, and 467 MW of solar generation in 17 states.

“Our intent is to accelerate the transformation of PSEG into a primarily regulated electric and gas utility — a plan we have been executing successfully for more than a decade,” Izzo said in a statem e nt.

Izzo noted that separating its non-nuclear assets would reduce PSEG’s business risks and earnings volatility and that it would continue to improve its credit profile by investing in clean energy, methane reduction and zero-carbon generation. He said work is underway to market a potential transaction beginning in the fourth quarter of 2020 with closing sometime in 2021.

Izzo said a “shift in investor preference” toward owning regulated utility businesses without commodity exposure to merchant generation and related earnings volatility has been gaining momentum in the energy sector.

“We’re excited to explore the opportunities that will shape PSEG’s future,” Izzo said. “It is a future focused on advancing our business as a sustainable customer-focused provider of essential electricity and natural gas service, delivered by a regulated utility and contracted businesses.”

PSEG Generation’s Future

PSEG intends to retain ownership of its existing nuclear fleet under its PSEG Power subsidiary, Izzo said. Its nuclear fleet includes the 2,285-MW Salem and 1,173-MW Hope Creek Nuclear plants in Lower Alloways Creek Township, N.J., and part ownership in the 2,549-MW Peach Bottom Nuclear plant in York County, Pa.

Izzo said the Salem and Hope Creek nuclear plants produce more than 90% of New Jersey’s zero-carbon electricity and are a “cost efficient necessary component” of the state’s transition to 100% clean energy by 2050, which was outlined in the New Jersey En e rgy Master Plan finalized in January.

The New Jersey plants receive zero-emission credit (ZEC) state subsidies, he said, which added $0.02 a share in earnings in the second quarter. ZEC applications for the next three-year period are due in the fall with a decision by the New Jersey Board of Public Utilities (BPU) expected in April 2021.

“As we begin the second round of the ZEC program by filing our applications this fall, it’s important to note that the financial need for ZECs is more critical than ever,” Izzo said.

PJM’s day-ahead power prices have remained in the mid-teens to low $20s per MWh most days during the second quarter, with recent temperatures in the mid-80s to mid-90s only causing prices to cross the $30/MWh threshold twice in the last 30 days in the PSEG zone.

Izzo said PJM day-ahead prices have declined from where they were just two years ago, when forward around-the-clock prices for the PSEG zone were approximately $30/MWh to just more than $25/MWh today. He said the lower prices reflect current market conditions, characterized by reduced loads, inexpensive natural gas and abundant generation.

“This market environment is the reality we face at our nuclear stations and is the driver behind ZECs,” Izzo said.

Besides its nuclear fleet, he said PSEG is continuing to evaluate potential investments in offshore wind, including a decision regarding the opportunity to acquire a 25% interest in Ørsted’s 1,100-MW Ocean Wind project later this year. (See Orst e d Wins Record Offshore Wind Bid in NJ.)

The company is also evaluating participation in upcoming offshore wind solicitations in New Jersey and other Mid-Atlantic states. On July 21, New York opened a solicitation for up to 2,500 MW of offshore wind power generation capacity.

Earnings

Dan Cregg, PSEG’s executive vice president and CFO, ann o unced a second-quarter profit of $451 million ($0.89/share), compared to $153 million ($0.30/share) last year.

Non-GAAP operating earnings were $404 million ($0.79/share), compared to $294 million($0.58/share) in 2019. The operating earnings beat the average estimate of five analysts surveyed by Zacks Investment Research of 59 cents per share.

PSEG expects full-year earnings in the range of $3.30 to $3.50/share.

Transmission Projects

Analysts on the earnings call asked about any transmission capital expenditures that could be on the horizon for PSEG.

Izzo said its subsidiary, Public Service Enterprise & Gas, continues to make progress on its portfolio of capital improvements, including several key transmission projects. In the second quarter, the company energized the second phase of its $739 million Metuchen-Trenton-Burlington Project and upgraded the transmission circuits between the Brunswick and Trenton stations.

The company also expects to complete work on a 6-mile upgrade of a 230-kV overhead transmission circuit running between the Aldene station and the Linden variable frequency transformer station by end of the 2020, having already completed approximately half of the project.

Most of the large transmission projects that came out of the PJM Regional Transmission Expansion Plan (RTEP) are “pretty much complete or near complete,” Izzo said. There is also the possibility of increasing transmission investment as New Jersey continues pursuing offshore wind.

“One of the things that the BPU is talking to all utilities, not just us, about is the possibility for accelerating some of the infrastructure programs that we want to do to help create some economic stimulus. And just given the age of our transmission infrastructure, and age of our gas infrastructure, that is something that could provide further opportunities for us as well,” Izzo said.

August 2, 2020

Dominion Names Blue as CEO in Earnings Call

Dominion Energy announced Friday it is moving forward with its leadership succession plan, promoting Executive Vice President and Co-COO Robert Blue to president and CEO by Oct. 1.

The news came during Friday’s second quarter earnin g s call, with current Chairman, President and CEO Thomas Farrell continuing to lead the Board of Directors as executive chair. Farrell joined Dominion in 1995 and was promoted to president and CEO in 2006 and chairman in 2007.

Farrell said the board believed it to be “an appropriate time to take the next step in our management transition” with the sale earlier in July of Dominion’s natural gas assets to Berkshire Hathaway for $10 billion and a path for the company to achieve net zero carbon dioxide and methane emissions from its power generation and gas infrastructure operations by 2050. Ferrell said there is no set timeframe for his new role as executive chair.

“The primary goal of our succession planning process has been to ensure continuity of our strategy, public policy, corporate values and operational excellence,” Farrell said. “As executive chair, I will continue to represent the company, engaging with key stakeholders, industry groups and others that will be particularly focused on continuing to develop our strategic plan and Dominion’s leadership in the new clean energy economy.”

Blue joined Dominion in 2005 and has held several executive roles since his promotion to an officer in 2007, including vice president of state and federal affairs and president of Dominion Virginia Power. Prior to joining the company, Blue served as a counselor and director of policy for Virginia Gov. Mark Warner and a law clerk for the U.S. District Court in the Eastern District of Virginia.

Diane Leopold, executive vice president and co-COO, will become the company’s sole COO with responsibility for all of Dominion’s operating segments. Edward Baine was promoted to president of Dominion Energy Virginia.

Earnings

During Friday’s earnings present a tion, Dominion CFO Jim Chapman announced the company reported a second-quarter loss of $1.2 billion ($1.41/share) on revenue of $3.59 billion, compared with a net gain of $54 million ($0.05/share) on $3.97 billion in revenue for the same period in 2019. He said the loss was impacted by worse-than-normal weather in its service territories and impairment-related charges associated with the cancellation of the Atlantic Coast Pipeline and Suppl y Header projects.

Operating earnings for the second quarter were $706 million ($0.82/share), compared with operating earnings of $619 million ($0.77/share) in 2019. The results beat Wall Street operating results expectations, with the average estimate of 81 cents per share for earnings among four analysts surveyed by Zacks Investment Research.

For the third quarter, Dominion expects its per-share earnings to range from 85 cents to $1.05 and a full-year earnings in the range of $3.37 to $3.63 per share.

Company Initiatives

After cancelling the long-disputed $8 billion Atlantic Coast Pipeline in July with its partner, Duke Energy, followed by the sale of its natural gas assets to Berkshire Hathaway, Dominion is now following its plan to grow its renewable energy capacity by more than 15% annually for the next 15 years. Farrell said the company has already achieved its 3,000-MW targets for renewable generation in service or under development in Virginia, a year and a half ahead of schedule.

He also highlighted Dominion’s growing solar portfolio, which makes it currently the third-largest owner of solar capacity among utility companies in the country. And Dominion’s pilot wind project off the coast of Virginia is scheduled to begin generating electricity in the third quarter, Farrell said, with the rest of the $8 billion, 2.6-GW full-scale offshore wind project continuing on schedule.

Energy Company Controversies

Recent bribery scandals involving two of the biggest energy companies in the country, Exelon and FirstEnergy, played into Friday’s earnings call. In the question-and-answer period, Farrell was asked about Dominion’s own contributions to 501(c)(4) nonprofit social welfare organizations and whether the company has any plans to modify its political lobbying strategies considering the federal investigations going on with Exelon and FirstEnergy.

He said Dominion has “fully disclosed” its 501(c)(4) contributions for several years. Over the last five years, the company’s contributions to 501(c)(4)s have been under $500,000, with 70% of that total going to an organization associated with American Petroleum Institute that supports pipeline projects.

“We have no intention of changing our practices because they are perfectly appropriate [and] completely compliant with every state in federal law by wide margins,” Farrell said. “We have nothing to be concerned about with respect to any of our political giving or giving to these so-called 501(c)(4)s.”

August 2, 2020

US Analyzing Iowa Storage Pilot as Potential Model

An agricultural hub of about 8,000 in the northeast corner of Iowa seems an unlikely choice for a state-of-the-art battery storage project, but the Department of Energy thinks it could become a template for other American towns.

The DOE is chipping in $250,000 on a $2.5 million, 2.5-MW battery storage pilot project in Decorah, Iowa, to increase the city’s capacity for rooftop solar. Alliant Energy will build the project; Sandia National Laboratories will provide technical support and collect data. The Iowa Economic Development Authority (IEDA) is also contributing a $200,000 grant.

Those groups, and others, will analyze the storage project’s operations, looking for a cost-effective model that can be used elsewhere on the grid.

Decorah Mayor Lorraine Borowski said the Decorah grid currently doesn’t have the capacity to accommodate future customer-owned solar projects. She said the town expects the battery will yield savings on avoided distribution system investments.

Alliant hopes to have the Enel X battery in service by the end of year, though COVID-19 has slowed development.

“This grid has become a lot more complex in the last couple of years,” DOE Director of Energy Storage Research Imre Gyuk said during a July 30 DOE webinar on the project. “We now have an appreciable amount of renewable energy … and for good reason because we need to worry about the world warming up and pollution … You can’t just put photovoltaics or other renewables on the grid without expecting disturbances.”

Gyuk said electric vehicles and on-site generation is also complicating once cut-and-dried load patterns.

Decorah’s “typical small Midwestern town” façade belies Iowa’s status as a storage trailblazer, Gyuk said. In 2006, he noted, Iowa Associated Municipal Utilities and the Iowa Stored Energy Project tried to install a 200-MW compressed air energy storage project in an aquifer before project leads discovered the sandstone terrain was unsuitable.

“It’s time for Iowa to get back in the game,” Gyuk said. But he said Iowa and other states still need appropriate regulatory frameworks to develop a grid containing high renewable penetration.

“What we look for is strong local support. You need a local champion,” Gyuk said of finding the right location in small-town Iowa. “You need people who are committed and will stick with the thing to make it work.”

Iowa Storage Pilot — Enel X battery storage | *Enel X*

The City of Decorah is providing leased space for the project in a public park.

Borowski said Decorah’s residents are often out-of-state imports and like-minded about a renewable-dominant future. And Decorah’s hard-rock topography of bluffs and hills makes line-building a challenge, Borowski said. She called the pilot program a “natural fit.”

Alliant Energy Solutions Engineer Sarah Martz said the Norwegian cultural hotspot famous for its eagle-hatching camera is on par to reach its distributed generation hosting capacity limit in a few years.

Rather than wait for the limit to approach, Martz said, Alliant wants to create capacity now in an innovative way.

Traditional line and substation upgrades to host the distributed energy could cost from $1 to $10 million, a wide range of uncertainty. The $2.5 million investment in the battery will have the added benefit of being able to manage voltage and real power flows on the circuit.

“Some of these hosting capacity issues cannot be solved by traditional line and substation upgrades,” Martz said, adding that voltage increases on a circuit still can’t manage backflows from distributed generation.

Martz said Alliant will also monitor the project to make a blueprint for other communities the utility serves.

Martz said Alliant is interested in offering the battery’s services into the More Time Needed for Storage Compliance, MISO Says.)

Last May, the IEDA’s energy office released the Iowa Energy Storage Action Plan, which encourages such pilot programs.

“We really understand that you have to walk before you can run. We have to have these pilot programs for lessons learned,” said Brian Selinger, director of the energy office.

“Iowa really is on the cutting edge of the transformation of the grid,” Director of Iowa State University’s Electric Power Research Center Anne Kimber said. Iowa State also plans to study the project’s effectiveness. She said the real-world data gathered from the Decorah battery project and distribution system will be extremely useful.

“We can use the Decorah feeder data … to make better models to predict voltage stability under certain conditions,” Kimber said.

The university will also use the project to study battery health and performance over time.

August 2, 2020

Max Gen Event Managed Efficiently, MISO Says

MISO said last week it quickly regained control during its first maximum generation emergency July 7 during a lasting heatwave.

“Uncertainty in both load and supply, impacted by COVID-19, created some challenges that I think we successfully managed,” MISO Executive Director of Real-Time Operations Rob Benbow said during a July 30 Reliability Subcommittee meeting.

Since 2016, the RTO has not completed a single year without a maximum generation event, amassing 10 emergency events in four years. However, summertime emergencies are relatively rare for the grid operator, representing only two of the 10 events.

Benbow said MISO needed “abnormal and emergency procedures” from July 1 through July 20 to navigate tight conditions.

The RTO and its members operated under a hot weather alert July 1-10 and a capacity advisory and conservative system operations — where maintenance outages are asked to be put on hold — July 6-10.

MISO declared a maximum generation event July 7 as high temperatures collided with an unusually large number of unavailable generators in the RTO’s North and Central regions. The emergency lasted from about 1:00 to 5:30 p.m. Load peaked at 116 GW, below the 120-GW forecast.

MISO max gen event — MISO control room transmission map | *MISO*

Benbow said MISO anticipated the hot weather and communicated with its members as early as possible.

After the RTO had committed all available resources, almost all of the 600 MW in emergency resources called upon stepped up, he said. MISO also recalled some scheduled transmission outages during the day.

MISO maintained good communication with neighbors PJM, SPP, Tennessee Valley Authority and Southern Co. during the event, Benbow said. The RTO discussed temporarily raising the 2,500-MW MISO South to Midwest regional transfer limit with its southern neighbors, but it ultimately wasn’t necessary.

Following the July 7 event, the RTO again declared a hot weather alert July 16-20 for its Central region.

“Especially the North and Central regions were in the mid-90s for most of early July,” Benbow said.

He noted that MISO would return to the Reliability Subcommittee in August with more information on generation outages and emergency resource performance.

Multiple stakeholders said while the emergency declaration communications to members were clear, it was less clear when MISO terminated its conservative operations and hot weather alerts during July.

Some stakeholders asked if unavailable nuclear generation played a role in the emergency because nuclear plant operators tend to be older and more susceptible to severe COVID-19 infection. Benbow said while one nuclear plant was out during the emergency, he suspected it was “because of mechanical reasons.”

Mild June in MISO

June operations were a different story for the grid operator, with load peaking at just 107 GW on June 30.

June 2020 in the footprint registered at one degree Fahrenheit above NOAA’s 30-year average, according to MISO.

Low natural gas prices also kept prices low during the month.

“The real-time LMP was $18/MWh for the second straight month, a 25% decrease over 2019,” MISO Executive Director of System Operations Renuka Chatterjee reported during a July 21 MISO Informational Forum.

Chatterjee also said load — subdued by the pandemic since mid-March — has gradually begun to rebound. The RTO load bottomed out to about 10% below normal levels during May; the impact has since decreased to about 5%.

“June and July data suggests [that] COVID-19 impact on load and energy is diminishing due to warmer weather, recovering to more historical levels,” Benbow said.

MISO is still using its back-up control center at its Carmel, Ind., headquarters, he said. To date, no operators have tested positive for the novel coronavirus.

Benbow also said its non-core operations employees can now return to MISO offices on a voluntary basis. The RTO currently has no plans to make in-person work mandatory for non-operations staff, but it will likely reevaluate sometime in the fall if the pandemic crisis abates.

Meanwhile, MISO is still rearranging some generation outages after virus-induced barebones work crews caused some utilities to hold off on scheduled spring maintenance outages.

MISO Outage Coordinator Trevor Hines said the RTO is connecting with market participants to discuss rescheduling outages in the fall.

“If you have flexibility to adjust your outage schedule, please reach out to MISO,” he asked members.

August 2, 2020

Xcel Earnings Overcome COVID-19 Sales Drop

Xcel Energy on Thursday reported improved second quarter earnings despite a drop in sales due to the COVID-19 pandemic.

Executives said the Minneapolis-based company had earnings of $287 million ($0.54/share) during the quarter, reflecting lower operations and maintenance expenses, lower income taxes and favorable weather that offset sales declines. That was an improvement from last year’s second quarter, when Xcel reported earnings of $238 million ($0.46/share).

Xcel said its operating companies’ weather-normalized sales for the quarter were down 7.1% compared to last year. Commercial and industrial sales were down 11.5%, but residential sales were up 5.4%.

While executives acknowledged they are seeing some positive economic signals, the company said in its earnings release that “there continues to be substantial uncertainty related to the impact of the COVID-19 pandemic on the remainder of the year.”

The Xcel Energy Center in Minneapolis is home to the NHL’s Minnesota Wild. | *Xcel Energy Center*

CEO Ben Fowke said Xcel is still on track with its financial plan and reaffirmed the 2020 earnings guidance of $2.73-2.83/share.

“We’ll continue to monitor and manage through the economic uncertainty of this pandemic,” he said.

Xcel recently proposed a $3 billion investment plan in Minnesota. The plan includes $1.8 billion of incremental capital expenditures for repowering wind turbines, a 460-MW solar facility and $1.2 billion of accelerated transmission, distribution and natural gas investment.

Fowke said the plan would create an estimated 5,000 jobs and add more wind and solar to its Northern States Power-Minnesota system.

Xcel’s stock gained 27 cents on the NASDAQ Thursday, closing at $69/share.

August 2, 2020

ERCOT Technical Advisory Committee Briefs: July 29, 2020

ERCOT’s Technical Advisory Committee continues to refine its virtual voting practices, reverting to a combined ballot to reduce the number of roll-call votes and make the best use of members’ time.

Last week, that resulted in the unanimous approval of a ballot loaded with 23 revision requests, two key topics/concepts from the Battery Energy Storage Task Force (BESTF) and seven other items.

Only two nodal protocol revision requests (NPRRs) were voted on separately during TAC’s July 29 meeting. Both were easily endorsed. NPRR984 adds a fourth standard contract term per year for emergency response service (ERS), and NPRR1020 allows energy storage resources with integrated loads that cannot be metered as designed to use internal sensors in calculating the loads.

ERCOT granted the latter change urgent status because it affects ongoing interconnections. The revision will be sent to the Board of Directors for its Aug. 11 meeting.

Staff added clarifying comments to NPRR1020 for the required annual audit of the congestion revenue rights’ (CRR) allocation methodology by the resource entity calculating its ESR’s auxiliary load value. They said their revisions “simply require the audit to confirm that the resource entity’s calculation of auxiliary load ‘does not understate the load value,’ rather than specifying a band of allowable measurement error.”

ERCOT has estimated it will cost between $175,000 and $225,000 to make the change. Staff said resource limitations on software developers will delay work on the change until early next year. System implementation would also require revisions to the settlement metering operating guide.

NPRR1020’s sponsor, Tesla, said the urgent status will help it “achieve regulatory certainty and allow its investments to move forward.”

“I think we’ve got Tesla a level playing field with everyone else,” said Bob Wittmeyer, who represented energy-storage developer Broad Reach Power during the early stages of the revision request’s progress through the stakeholder process.

The measure passed without an opposing vote. EDF Trading North America abstained.

TAC endorsed NPRR984 28-1, with independent power marketer Morgan Stanley voting against the motion. Morgan Stanley representative Clayton Greer also indicated he would vote against tabling the change or moving it to the combination ballot, forcing the roll-call vote.

“I’ll vote no on everything with ERS,” he said.

ERCOT said changing the ERS standard contract terms would allow it to better align with typical seasonal conditions and help improve the service’s procurement.

Members, Staff Debate RR Development Budget

TAC approved two key topics/concepts (KTCs) from the BESTF, an initiative to address how to integrate ESRs into the ERCOT system.

Staff first had to allay stakeholder concerns that ERCOT is running out of time and money to incorporate the task force’s work, along with that of the Real-Time Co-optimization Task Force and other projects.

The Advanced Power Alliance’s Walter Reid called for the BESTF and distributed generation to be placed at the top of the ISO’s priority list of development projects

“The work the BEST Force has been doing to get batteries into the protocols needs to be finished,” he said. “We need to facilitate that [investment] … For DG, getting that done is critical.”

ERCOT currently allocates $4 million from its capital project budget to fund revision requests’ development. It has the flexibility to “exceed the target for priority needs,” spokesperson Leslie Sopko said in an email.

“We really do need to consider if there’s some way to relax that $4 million [limit],” Reid said.

Kenan Ögelman, the grid operator’s vice president of commercial operations, cautioned stakeholders against increasing the $4 million allocation.

“Expanding that doesn’t necessarily get [Reid] the relief he wants. The limits … are also resource limits,” Ögelman said. “You also have to look at expanding a budget in this environment of low interest rates and economic uncertainty. The only two options are to move dollars from elsewhere into the $4 million or expand the budget. I think you are at risk of moving dollars out of things ERCOT is doing behind the scene to deliver DG and BEST.”

Staff promised a prioritized list of projects on Aug. 3, with a follow-up discussion during a Protocol Revision Subcommittee meeting on Aug. 13.

The two endorsed KTCs are:

KTC 15-7: Restricts ESRs from withdrawing energy during a Level 3 energy emergency alert and addresses ancillary service responsibility compliance related to the charging suspensions.
KTC 15-8: Grandfathers NPRR989 ‘s reactive power requirements.

ERCOT Updates Price-correction Issue

Dave Maggio, ERCOT’s director of market design and analytics, told the committee staff expects to complete in two weeks a review of day-ahead and real-time market prices following the discovery of erroneous dynamic ratings for three 345/138-kV transformers.

Ratings from unrelated transformers were applied to the three transformers, possibly causing or missing congestion, on operating days between Feb. 12 and July 7, he said. Staff developed a software fix to resolve the issue on July 14.

ERCOT was able to issue a price correction for affected July 7 day-ahead prices. Should staff discover a need for price corrections during the historical period, which is outside the normal 30-day notification period, they will ask the Board of Directors to approve corrections, Maggio said.

Maggio said staff also discovered in May that a software glitch prevented the operating reserve demand curve (ORDC) from properly calculating certain resources’ capacity. Staff corrected the error with a software patch and conducted a detailed review of the ORDC calculations back to when it went live in 2014. They found no additional errors, Maggio said.

ERCOT staff is proposing a revision request to remove requirements that modify DC-tie load zones requiring board approval and a 48-month waiting period after approval. The issue stems from American Electric Power’s recent retirement of a DC tie near the Mexican border in South Texas.

“I think the majority of sensitivity around changes to typical load zone boundaries is because entities serving load to those areas potentially have long-term contracts,” said Reliant Energy Retail Services’ Bill Barnes. “There’s no load served there. It’s just used for export and import [of energy].”

TAC OKs Consent Agenda’s 23 Changes

TAC added NPRR1030 to the combination ballot after agreeing on a desktop edit provided by Greer. Or, as one member jokingly surmised, language provided by a ghostwriter.

“I had some help,” Greer acknowledged.

The measure changes the CRR auction revenue distribution allocation methodology from a peak 15-minute settlement interval to load ratio share based on adjusted metered load totals for each month. It also makes parallel changes for the CRR balancing account and certain block load transfers for consistency and ease of implementation.

Greer offered language that provided market participants will not engage in DC tie export transactions “that are reasonably expected to be uneconomic in consideration of all costs and revenues associated with the transaction.” The language excludes CRR auction revenue distribution and CRR balancing account allocations.

By making clear such transactions would violate the Protocols, TAC was able to agree on accepting ERCOT’s comments, whose complexity extended to the measure’s implementation timeline from an estimated three months to 12 months. Staff corrected and clarified settlement formulas and corresponding variable definitions.

The edits will be temporarily “grey boxed” and eliminated with NPRR1030’s implementation.

The combination ballot included seven other NPRRs, a Load Profiling Guide revision (LPGRR), four changes to the Nodal Operating Guide (NOGRRs), four other binding document revisions (OBDRRs), a pair of changes to the Planning Guide (PGRRs), three revisions to the resource registration glossary (RRGRR) and one change to the verifiable cost manual (VCMRR).

It also included committee and subcommittee goals, a list of other binding documents and the 2021 meeting calendar. TAC will continue holding monthly meetings on the fourth Wednesday of the month to avoid conflicts with the Texas Public Utility Commission open meetings.

NPRR9 96: Aligns the Protocols’ hub bus names with the substation names within the ERCOT model.
NPRR 1000: Removes the term “dynamically scheduled resource” from the Protocols.
NPRR 1002: Establishes energy storage resource “single model” registration and charging restrictions during emergency conditions.
NPRR 1003: Replaces all remaining references to the resource asset registration form (RARF) with more general language in anticipation of the RARF’s elimination.
NPRR 1004: Creates a new process for determining the congestion revenue rights (CRR) auctions and day-ahead market clearing load-distribution factors by using load forecasting models and existing validation/error correction.
NPRR10 15: Clarifies the market system’s submission and reporting changes necessary to complete NPRR863, implement changes to responsive reserve service (RRS) and add ERCOT contingency reserve service.
NPRR10 16: Clarifies important reliability requirements for distribution generation resources (DGRs) seeking qualification to provide ancillary service(s) and/or participation in security-constrained economic dispatch.
LPG RR 067: Streamlines the assignment of oil and gas profiles by eliminating current processes that are no longer applicable. The revision validates weather sensitivity only for non-interval data recorder electric service identifiers that request the oil and gas flat profile; removes the “TOU Schedules” and “Non-ERCOT Profile IDs” worksheets; and changes the distributed generation profile segment assignment process.
NOGRR 195: Addresses the Texas Reliability Entity’s audit recommendations for ERCOT and modifies generator voltage control tolerance bands.
NOGRR20 8: Aligns the Nodal Operating Guide with the nodal Protocols as modified by NPRR1002. An alignment NOGRR for energy emergency alert will be filed following NPRR1002’s approval to align with the Protocols.
NOGRR20 9: Replaces all remaining references to the RARF with more general language to align with NPRR1003.
NOGRR 2 1 2: Aligns the Guide with NPRR1016’s revisions and clarifies DGRs’ reliability requirements.
OBDRR 0 18: Aligns the procedure for identifying resource nodes with NPRR1003’s changes by replacing all remaining references to the RARF with more general language.
OBDRR 0 19: Aligns the requirements for aggregate load resource participation in the ERCOT markets with NPRR1003’s changes by replacing all remaining references to the RARF and updates the process’ change control process with similar other binding documents.
OBDRR 0 21: Aligns the language in the calculation of RRS limits’ procedures for individual resources with the Protocols following NPRR863’s Phase 1 implementation. Also corrects inadvertent errors in the formulas for calculating droop performance to determine RRS limits.
OBDRR 022: Incorporates minor edits to the initial other binding document previously approved in conjunction with NPRR933.
PGRR07 6: Changes the generation resource interconnection or change request (GINR) process to specify that the proposed commercial operations date in the initial GINR application must be at least 15 months after the date of the application; redefines the security screening study output; creates separate reports for the full interconnection study; coordinates reactive study; and clarifies when the dynamic data model should be submitted to meet the quarterly stability assessment prerequisite deadline.
PGRR07 9: Aligns the guide with NPRR1003’s changes by replacing all remaining references to the RARF.
RR GRR023: Establishes the guide’s provisions and requirements for ESRs identical to those already in place for generation resources and settlement-only generators.
RRGRR02 4: Aligns the glossary with NPRR 1003’s changes by replacing all remaining references to the RARF.
RRGRR026: Adds a new data point to support implementation of an interim solution representing DGRs and distribution ESRs in the ERCOT network operations model.
VCMRR 0 2 9: Aligns the manual with NPRR1003’s changes by replacing all remaining references to the RARF.