Page 1127 – RTO Insider

July 17, 2020

NYISO BIC Balks on Increased Reserves

NYISO stakeholders on Wednesday delayed a vote on the ISO’s proposal to procure up to 500 MW of additional reserves for Southeast New York (SENY) pending an additional cost analysis.

The Business Issues Committee tabled the proposal with a 68% roll-call vote on which many members abstained.

The ISO wants to procure up to 500 MW of additional 30-minute reserves in the SENY reserve region (zones G-K) as part of its Reserves for Resource Flexibility project. This proposal would increase SENY’s portion of the total statewide reserve requirement from 1,300 MW to 1,550 or 1,800 MW depending on the hour, said NYISO’s Ethan Avallone, who presented the proposal.

The proposal would shift current locational reserve procurements and would not increase the 2,620-MW procurement for the entire state.

The region’s current 30-minute reserves are used to bring transmission assets to emergency transfer criteria — below short-term emergency ratings — after suffering from the first worst contingency in SENY. The additional reserves would provide a market-based mechanism for obtaining resources to bring transmission assets to normal transfer criteria — below long-term emergency ratings — following a contingency, minimizing the need for ISO operators from having to employ out-of-market actions.

NYISO would procure an additional 250 MW for the hours beginning 6 and 22, with an additional 500 MW procured for hours beginning 7 to 21. There would be no increase for hours beginning 23 through 5.

NYISO reserves — Proposed SENY 30-minute reserve demand curve | *NYISO*

Unlike the existing 30-minute reserves, which are priced at $500/MWh, the incremental reserves would have a shortage price of $25/MWh. “This lower shortage price recognizes that reserves procured for emergency transfer criteria are a higher relative priority than reserves procured for normal transfer criteria,” the ISO said.

Avallone noted that NYISO plans to increase the $25/MWh demand curve point to $40/MWh as part of its separate A ncillary S ervice S hortage P ricing proposal.

Amanda De Vito Trinsey, representing New York City, asked for the delay, complaining that while the ISO had estimated the cost of the $25/MWh to be about $300,000 annually, it had not provided an analysis on the impact of the $40/MWh price, which the city had requested at previous stakeholder meetings.

“You’re having us vote before we see the impact analysis [on the $40/MWh price], which defeats the whole point of having an impact analysis,” she said.

“You’re setting a very poor precedent,” agreed Erin Hogan of the New York Department of State’s Utility Intervention Unit.

“I can’t say it any better, but I do agree with Amanda and Erin on that point,” added Chris Hall of the New York State Energy Research and Development Authority.

Howard Fromer, representing Bayonne Energy Center, estimated the $40/MWh price would be no more than 60% higher than the $25/MWh price — a total of about $480,000 a year.

“I don’t quite understand … the call for more delaying,” he said. “We’re talking about noise.”

A NYISO spokesman said after the meeting that the ISO had not endorsed the stakeholders’ cost estimates.

Trinsey countered Fromer, saying that the ISO doesn’t expect to implement the program for two years. “Why are we being rushed to a vote before seeing an appropriate consumer impact analysis?” she asked.

Matt Schwall of the Independent Power Producers of New York, who noted the $40 price will be voted on separately, said delaying the vote on the $25 reserves could impact investment decisions. “We have developers in New York who are looking at making investments in facilities today to respond to changes in the system that are coming in the next couple years. Even a six-month delay … has serious consequences for investors moving forward.”

A stakeholder who asked not to be identified urged members to respect NYISO operators’ concerns, saying the ISO has leaned on “latent reserves” such as Indian Point, which will be completely shut down by April 2021 and peakers that will retire between 2023 and 2025.

“I am pretty appalled … that there appear to be parties that are going to take a stand against reliability because it might have a cost of $480,000” a year, said Mark Younger of Hudson Energy Economics, who represents generation owner Indeck Energy Services and other suppliers Mercuria Energy America and Eastern Generation.

“That’s a gross mischaracterization of what I said,” responded Hogan.

Andy Antinori of the New York Power Authority pressed ISO officials on how long it would take to conduct the analysis of the $40/MWh shortage price.

Avallone initially declined to answer, saying, “We do intend to move forward on the vote today.”

But Tariq Niazi, the ISO’s senior manager for consumer interest liaison, said information on the impact of the $40/MWh shortage price would be included as part of the impact analysis of the Ancillary Services Project, which the ISO hopes to present in August.

With that, Trinsey successfully moved to table the vote to recommend the proposal to the Management Committee.

Fromer said after the vote, however, that there is “precedent” for the MC considering proposals without a BIC recommendation.

July 17, 2020

FERC Rejects Net Metering Challenge

FERC on Thursday rejected a request by a purported ratepayer group that could have ended net metering for rooftop solar generation, prompting relief among state regulators and renewable power advocates (EL20-42).

The commission unanimously rejected the New England Ratepayers Association’s (NERA) petition for declaratory order asking it to essentially outlaw net metering by ruling that FERC has exclusive jurisdiction over sales of rooftop solar power.

NERA asked FERC to assert jurisdiction over energy sales from rooftop solar facilities and other distributed generation located on the customer side of the retail meter whenever their output exceeds the customer’s demand or the energy from such generators is designed to bypass the customer’s load.

The association said such transactions were wholesale sales in interstate commerce, which should be priced at the utility’s avoided cost of energy if the sale is made under the Public Utility Regulatory Policies Act of 1978 or a just and reasonable wholesale rate if the sale is made pursuant to the Federal Power Act. Making such sales subject to the FPA might have required individual homeowner-generators to have a rate on file with FERC, a mandate that critics said would virtually eliminate net metering.

FERC Net Metering — Solar panels line the roof of a turkey barn in Iowa. | *Iowa Farm Bureau*

The commission said it was using its discretion in declining to address the issues raised by the petition. “We find that the issues presented in the petition do not warrant a generic statement from the commission at this time,” it said, adding that the petition “does not identify a specific controversy or harm that the commission should address in a declaratory order to terminate a controversy or to remove uncertainty.”

FERC also said NERA did not meet the requirements for an enforcement action under PURPA because such actions are limited to electric utilities and qualifying small power production and cogeneration facilities.

Widespread Opposition

Thousands of individuals and groups filed comments urging FERC to reject the petition. State officials and others alleged it would upset two decades of legal precedent supporting state and local policies used by 2.3 million net metering participants in 49 states. (See Thousands Oppose Bid to Undo Net Metering.)

Other commenters complained NERA was a front for investor-owned utilities and the fossil fuel industry and said its funding made it akin to a trade group.

Only a handful of groups — Americans for Tax Reform, Californians for Green Nuclear Power, CAlifornians for Renewable Energy, Citizens Against Government Waste, Competitive Enterprise Institute and the Heartland Institute — supported the petition.

Questions over Net Metering Remain

Although the commission was unanimous in rejecting the petition on procedural grounds, Commissioners Bernard McNamee and James Danly issued concurrences expressing concern over the substantive issues raised.

“The commission’s order is not a decision on whether the commission lacks jurisdiction over the energy sales made through net metering; nor is it a decision on the merits of the issues raised by and contained in the petition,” McNamee said. “I also note that, as a general proposition, I think it is best to decide important legal and jurisdictional questions, like the ones raised in in the petition, when applying the law to a specific set of facts, such as in a Section 206 complaint, or through a rulemaking proceeding.”

Danly said the petition raised “difficult legal questions,” including the rate treatment for excess generation and the boundary between federal and state jurisdiction.

“I have yet to reach any conclusion regarding either rate treatment or jurisdictional boundaries, but I am certain that these are questions of profound importance and the commission will eventually have to address them,” Danly said. “I am concerned that dismissing the petition on procedural grounds may well result in a patchwork quilt of conflicting decisions if the questions raised in the petition are instead presented to federal district courts across the country. While the federal courts are more than capable of adjudicating pre-emption claims, they are not steeped in the history of the Federal Power Act nor in matters of national energy policy. Confusion, delay and inconsistent rules — some of which will apply to individual states or parts of states — will be the inevitable result.”

NERA President Marc Brown said while he was disappointed by FERC’s decision, he agreed with McNamee’s and Danly’s comments. “We will review the decision to determine the appropriate course of action we will take in order to ensure that ratepayers are protected from the billions of dollars in cost-shifts unwittingly and unfairly paid by ratepayers to support the rooftop solar industry,” he said in a statement.

States, Renewable Supporters Rejoice

State officials and solar power backers nonetheless rejoiced at the ruling.

“This decision is a victory for state regulators and for anyone with a vested interest in net metering policy,” said Mississippi Public Service Commissioner Brandon Presley, president of the National Association of Regulatory Utility Commissioners. “The timing of this decision is also excellent, as NARUC and our members can prepare for next week’s National Policy Summit knowing that we have been able to uphold a core principle of state utility regulation.”

“FERC made the right call,” said Joseph L. Fiordaliso, president of the New Jersey Board of Public Utilities. “New Jersey has relied on FERC precedent for 20 years as we’ve advanced our net metering programs. As we explained in our pleading, net metering is a retail billing method.”

“As the leader of a coalition of conservative groups, solar advocates, state regulators and elected officials from both sides of the aisle in opposition to this petition, [the Solar Energy Industries Association] applauds FERC’s unanimous decision to dismiss this flawed petition,” said SEIA CEO Abigail Ross Hopper. “We are grateful to the state utility commissions and many other partners who strongly opposed this petition. We will continue working in the states to strengthen net metering policies to generate more jobs and investment, and we will advocate for fair treatment of solar at FERC where it has jurisdiction.”

Gregory Wetstone, CEO of the American Council on Renewable Energy, said moving net metering from state to federal jurisdiction “would have severely limited its appeal by lowering participants’ compensation rate.”

“While we are gratified that today’s decision respects the Federal Power Act, we will continue to stay vigilant about protecting forward-looking state energy policies that deliver the pollution-free renewable power Americans want,” Wetstone said.

“Had FERC taken up NERA’s arguments, it would not only have upended the legal basis for net metering programs but would also have severely hampered ongoing efforts by numerous states to develop programs that value [distributed energy resources] with greater accuracy,” the Institute for Policy Integrity at New York University School of Law said.

July 17, 2020

FERC Proposes Tougher Hydro Safety Rules

Responding to the 2017 Oroville Dam incident, FERC on Thursday proposed tougher safety standards for commission-regulated hydropower projects, including a two-tier safety inspection process (RM20-9).

The Notice of Proposed Rulemaking would change part 12 of FERC’s regulations to codify existing guidance requiring certain licensees to develop dam safety and public safety programs and update regulations regarding incident reporting.

The two-tier inspection structure would include a comprehensive assessment and a periodic inspection.

As under current rules, an inspection by an independent consultant would continue to be required every five years, but the scope would alternate between a “comprehensive” assessment and a “periodic” inspection. These inspections will be in addition to FERC staff’s safety inspections.

The alternating two-tier structure is similar to those used by the Bureau of Reclamation and the U.S. Army Corps of Engineers. “The comprehensive assessment would require a more in-depth review than the current part 12 inspection, would formally incorporate the existing potential failure modes analysis process and would require a semiquantitative risk analysis,” FERC said. “The periodic inspection would have a narrower scope than the current part 12 inspection and focus primarily on the performance of project works between comprehensive assessments.”

FERC Hydro Safety Rules — Oroville Dam on Feb. 17, 2017 | *California Department of Water Resources*

FERC also would change how it evaluates the qualifications of the consultants to ensure those conducting inspections have sufficient expertise for site-specific conditions under what is known as the Part 12D Program.

The change follows a recommendation by the Federal Emergency Management Administration that “the inspection team should be chosen on a site-specific basis considering the nature and type of dam … [and] should comprise individuals having appropriate specialized knowledge in structural, mechanical, electrical, hydraulic and embankment design; geology; concrete materials; and construction procedures.”

FERC said the change “reflects the reality that, for many of the hydropower projects under the commission’s jurisdiction, a single independent consultant will not possess the appropriate degree and diversity of technical proficiency necessary to evaluate all aspects of the project.”

The current requirement that an independent consultant be a licensed professional engineer with a minimum of 10 years’ experience in “dam design and construction and in the investigation of the safety of existing dams” would remain. “However, as proposed, this requirement would apply only to the designated independent consultants and not to other supporting members of the independent consultant team,” FERC said.

Oroville Dam Failure

The commission said the proposed changes are the product of recommendations that resulted from an analysis of the February 2017 incident in which the Oroville Dam in California saw major damage to its primary spillway and the first activation of its auxiliary spillway. About 180,000 people were forced to evacuate the surrounding area.

An independent forensics team concluded there was no single cause of the failure of the dam’s spillway. “The incident was caused by a complex interaction of relatively common physical, human, organizational and industry factors, starting with the design of the project and continuing until the incident,” the report said. (See Report: Regulatory Failure Caused Oroville Incident.)

FERC said the changes were “substantially complete” before the failures of the Edenville and Sanford dams in Michigan in May, which it said remain under investigation. About 10,000 central Michigan residents had to evacuate after the failure of the Edenville Dam after heavy rainfall. FERC revoked the dam owner’s license in 2018 over concerns about the facility not being able to handle floods. (See Michigan Dam with Prolonged Safety Issues Fails.)

Comments on the NOPR are due 60 days after publication in the Federal Register.

The commission also said it plans to update and add new chapters to its engineering guidelines document. Drafts will be issued in four advisory dockets: AD20-20 (Supporting Technical Information Document); AD20-21 (Part 12D Program); AD20-22 (Potential Failure Modes Analysis); and AD20-23 (Level 2 Risk Analysis).

July 17, 2020March 6, 2026

FERC Briefs: July 16, 2020

FERC issued a flurry of orders Thursday in its last open meeting before September. (The commission does not meet in August.)

The commission:

CAISO

Ordered additional briefing concerning the calculation of the return on common equity for the DATC Path 15 upgrade to reflect the commission’s revised ROE methodology in Opinions 569 and 569-A. The 84-mile, 500-kV transmission line was built to relieve congestion on the existing Path 15 corridor between northern and southern California (ER17-998-001).
Upheld the result of its January 2020 order that denied Pacific Gas and Electric’s request to recover 100% of the costs from its abandoned Central Valley Power Connect Project (ER19-2582-001).

ISO-NE

Rejected a complaint by Liberty Power Holdings alleging that ISO-NE inappropriately refused to correct a $200,000 billing error resulting from Eversource Energy’s reporting to the RTO load for the Smith & Wesson plant in Western Massachusetts that was mistakenly attributed to Liberty. The commission said Liberty waited too long to seek a correction (EL20-27).
Approved Paper Birch’s request to make wholesale sales of electric energy, capacity and ancillary services at market-based rates in the NYISO and ISO-NE markets. The order said the commission intends to release affiliate information for which Paper Birch requested privileged treatment (ER20-1120).

MISO

Approved an uncontested settlement on Entergy Arkansas’ tariff revisions to ensure the return of excess accumulated deferred income taxes resulting from the Tax Cuts and Jobs Act of 2017 (ER18-1247-001).
Upheld the result of its November 2019 order denying the Louisiana Public Service Commission’s complaint alleging that Entergy Services’ off-system sales of energy to third-party power marketers and others for the benefit of Entergy Arkansas violated its generation and transmission pooling arrangement (EL19-50-001). (See La. PSC Complaints Denied in Entergy System Disputes.)

NYISO

Approved in part and denied in part Alcoa Power Generating’s requests for waivers of the requirements for the company’s Tapoco and Long Sault Divisions to have open-access transmission tariffs, maintain an Open Access Same-Time Information System, and comply with the Standards of Conduct and other regulations (ER20-1580).

PJM

FERC orders — DATC Path 15 tx line | *Duke-American Transmission Co.*

Accepted PJM MRC Briefs: Dec. 19, 2019.)
Upheld its January 2020 ruling allowing Potomac-Appalachian Highline Transmission to recover certain advertising and public advocacy costs incurred during its efforts to win approval for the canceled PATH project (ER09-1256-006). (See FERC Grants Recovery on PATH Project Costs.)
Upheld the result of its October 2019 order finding that Dominion Energy Virginia met its burden under Section 205 of the Federal Power Act to show that changing to the 12-coincident-peak transmission cost allocation method is just and reasonable because it is based on Dominion’s transmission planning (ER19-1661-002). (See FERC OKs New Dominion Tx Rate Structure.) (This order had not been posted to the commission’s website as of press time.)
Ordered hearing and settlement procedures in the North Carolina Eastern Municipal Power Agency’s complaint that Duke Energy Progress’ 11% ROE in the companies’ power supply agreement is excessive. It rejected Duke’s request to dismiss the complaint and set a refund effective date of Oct. 11, 2019 (EL20-4).
Ordered a paper hearing to determine a reasonable proxy for determining the capital structure and cost of capital for a merchant generator in response to a petition for a declaratory order seeking guidance on the commission’s cost-based methodology for compensating reactive power generators. The petition was filed by Ares EIF Management; Competitive Power Ventures; Invenergy Thermal Development; J-Power USA Development; Panda Power Generation Infrastructure Fund; Tenaska; and Vistra Energy (EL19-70).
Accepted PSEG Energy Resources & Trade’s tariff revisions to cancel reactive power service tariff records for the Yards Creek Generating Facility. PSEG has proposed selling its 50% interest in the facility, a 420-MW hydro facility in Warren County, N.J. (ER20-1441).
Ordered hearing and settlement procedures on the continued justness and reasonableness of Constellation Power Source Generation’s reactive supply and voltage control rates (ER17-801-006).

SPP

Reduced ITC Great Plains’ adder for being an independent transmission company from 100 basis points to 25 in response to a complaint by the Kansas Corporation Commission (EL19-80).

July 17, 2020

Xcel to Begin Seasonal Operation at 2 Coal Plants

Minnesota regulators this week approved Xcel Energy’s request to operate two of its four coal units on a part-time basis.

The Minnesota Public Utilities Commission’s order Wednesday allows Xcel to idle its Allen S. King Generating Station and Sherburne County Generating Station Unit 2 during the low-demand spring and fall shoulder seasons (20207-164928-02). Xcel asked in December for permission to implement seasonal operations.

Xcel spokesperson Matt Lindstrom said the utility expects to begin seasonal operations this fall.

The PUC said the move will save customers money and represents “a significant step toward meeting Minnesota’s greenhouse gas emission-reduction goal.” It opened a docket last year to investigate the self-scheduling of coal plants in the state.

“This is an important proposal, and I appreciate Xcel Energy bringing it forward,” Commissioner Matt Schuerger said in a release. “I think this highlights Xcel’s focus on saving their customers money, on meeting Minnesota’s environmental policies and in being responsive to the investigation the commission opened.”

The Union of Concerned Scientists applauded the order. The organization has blasted coal self-commitments as expensive and wasteful. In a recent UCS report, the group named Xcel subsidiary Northern States Power one of the worst offenders for uneconomic operation, saying it ran the two coal plants at a $56.9 million loss in 2018. (See UCS Analysis Knocks Coal Self-commitments.)

Xcel Energy coal plants — Sherco Generating Station | *Xcel Energy*

“Xcel Energy was identified as one of the most egregious actors in our analysis, but this news is a welcome change in behavior,” UCS Senior Energy Analyst Joe Daniel said in an emailed statement. “Xcel, like most utilities, was initially reluctant to recognize the costliness of uneconomic self-commitment. But now, both the utility and the state commission have codified a path forward that will save Xcel’s customers millions of dollars, not to mention the public health benefits of reduced pollution.

“Had all utilities given up their uneconomic coal plant operations in 2018, the average family in Minnesota would have saved $5/month on their electricity bills. Unfortunately, other utilities in Minnesota remain reticent when it comes to changing their operations,” Daniel said.

Xcel said its own analysis found the move could save its customers up to $1.45 million in 2020 and up to nearly $3.5 million by 2023. The commission said customer savings could be reflected in Xcel’s next rate case. The utility also estimated it will save about $13 million in operations and maintenance and another $7 million in capital costs through 2023.

Xcel also said seasonal operations would cut its greenhouse gas emissions by 4 million tons in 2020 and a little more than 7 million tons by 2023. The commission said the decrease could account for a quarter of Minnesota’s goal to reduce emissions 30% below 2005 levels by 2025.

“As we lead the clean energy transition with a plan to reduce carbon emissions 80% by 2030 and pursue our vision of 100% carbon-free electricity by 2050, we’ll pursue innovative ideas like seasonally operating our coal plants,” Xcel said in an emailed statement. “These changes will allow us to add more renewable energy for our customers, reduce carbon emissions and save money on fuel and operations costs, savings we can deliver to our customers.”

But even the seasonal operation will be finite, as both plants are slated for retirement by 2030. Xcel said the King plant will close in 2028 while all three Sherco units will shutter by 2030. The closures will make good on the company’s promise to quit coal by 2030 in its Upper Midwest service territory. (See Xcel Latest MISO Utility to Pledge Zero Coal.)

Lindstrom said that as Xcel idles coal plants, it’s focusing on avoiding workforce layoffs. He said the company will probably let some of the positions at its coal plants disappear as employees retire.

“As we look toward the future of our system and the eventual retirement of our coal plants, we are working with employees, communities and other stakeholders to develop specific plans for each area to determine how we can bring new jobs and capital investment to the region. We’ve transitioned coal plants in the past and believe we can do so without layoffs, by normal attrition and job retraining,” Lindstrom said.

July 17, 2020

MISO Keeps Wait-and-See COVID-19 Approach

MISO is likely still months away from returning its full workforce on-site to its multiple offices in the Midwest and South, based on indications this week from its pandemic incident response team.

The RTO said that while it is creating detailed return-to-work plans, it remains in a holding pattern and is still advising most non-control room employees to continue working from home.

MISO COVID-19 — Angela Weber, MISO | © *RTO Insider*

“The problem for us, and I think everyone right now, is the situation is fluid, and we don’t have a solution yet,” MISO Executive Director of Incident Response Angela Weber told MISO South stakeholders during an Entergy Regional State Committee teleconference Monday. “It’s something we’re still working on and taking our time to do it right.”

MISO meets regularly with an infectious disease doctor and an epidemiologist for updates and advice, Weber said. “We make sure we’re responding in a very measured and informed way.”

The RTO is also monitoring infection rates around the country and pairing the Centers for Disease Control and Prevention’s recommended 14 days of sustained declining infection rates with adequate testing, contact tracing and ample hospital capacity, Weber said. If those criteria are satisfied, MISO would begin moving to normal operations, she said.

Weber’s comments came as the nation’s daily count of new infections nearly hit 66,000, the 37th straight day that the seven-day average of new infections in the U.S. had trended upward. Total COVID-19 deaths, which lag infections, are approaching 140,000.

Most of MISO’s non-control room employees have been working from home since mid-March, and the RTO has isolated its control room staff by forbidding other staff from entering control room buildings. (See Heat Counteracts COVID-19 Impact on MISO Load.) MISO’s meeting spaces are closed to in-person stakeholder meetings through at least the end of the year.

The grid operator has also expanded the financial and mental health counseling it offers its employees, Weber added.

July 16, 2020February 18, 2025

AVR Standards Team Faces Industry Pushback

Industry respondents criticized the team working on revisions to NERC’s standard for protection functions in automatic voltage regulators (AVR) for expanding the scope of the project beyond its initial mandate.

Comments on the proposed standard authorization request (SAR) for Project 2019-04 — modifications to reliability standard PRC-005-6 — opened June 2 and closed July 8. This is the second round of comments for the draft SAR; the first round opened in July 2019 and closed the following month.

The project was originally proposed in May 2019 by the North American Generator Forum (NAGF), which felt that the existing standard did not clearly explain its applicability to AVRs or prescribe appropriate maintenance activities for these devices. In the latest comment round, the SAR drafting team asked for comments on the following changes that it was considering:

Should bulk electric system protective functions that respond to electrical quantities inside excitation systems and other BES element control systems be included in PRC-005?
Does NERC’s current definition of “protection system” — which omits protective functions in the excitation and other control systems — create confusion concerning protective functions embedded in control systems?
Should the PRC-005 standard provide for the use of emerging DC supply technologies, battery-based or non-battery-based, and ensure that they are subject to maintenance requirements?
Is it reasonable for entities registered as under-frequency load shedding (UFLS)-only to be listed as applicable entities in the standard?

Entities Object to Scope Expansion

The scope of the changes took many respondents aback. Most notably, NAGF — despite submitting the original SAR — objected to what it characterized as an unwarranted expansion in the drafting team’s goals, particularly in their attempt to apply PRC-005 to control systems, for which it would be inappropriate.

“The updated SAR currently posted for comment appears to have expanded the scope significantly from the original wording of the NAGF SAR and evolved into a draft that the NAGF can no longer support,” NAGF’s Wayne Sipperly said in his comment on the first question. “NAGF requests that the SAR drafting team revert back to the original SAR as previously submitted … and limit this project to providing clear guidance on the scope and applicability of [AVR] protective functions on a synchronous generating unit with an installed digital AVR.”

Automatic voltage regulator

Sipperly’s comment was endorsed by a number of other industry representatives, as was his response to the second question. In that answer, he said that there was no chance that the definition of “protection system” could create confusion, unless it were extended to protective functions within control systems as the drafting team proposed.

Some respondents expressed more openness to the proposed expansion, though they were still uncertain about “vague” wording that created the chance of scope creep. Jennie Wike of Tacoma Public Utilities argued for unambiguous definitions of exactly which equipment was proposed for inclusion in the SAR.

“The protective functions should be limited to only those functions that impact the overall reliability and security of the BES,” Wike said.

Justification Falls Short, Commenters Say

Commenters also reacted with ambivalence to the proposal to set maintenance requirements for DC supply technologies as part of PRC-005. In a comment supported by several others, Edison Electric Institute’s Mark Gray said that he felt unable to support an expansion to the scope of the SAR without clear proof that the affected equipment were not covered by any existing standards.

“The description of the technology and industry need has not been adequately stated and explained in the SAR. It is also unclear how the current standard does not already address this technology,” Gray said. “Proposed changes to a reliability standard should clearly address any reliability gaps and other industry needs. … At this time, no justification has been provided nor has the increased scope been approved by the Standards Committee.”

On the final question regarding the extension of PRC-005 to cover UFLS-only entities, comments were generally supportive of including such utilities as consistent with other standards. The only significant objection came from Matthew Nutsch of Seattle City Light, who asked about “how many of these entities exist and how much impact … they have on the BES,” and whether their impact is great enough to justify the burden of requiring compliance with the standard. The potential compliance burden also weighed heavily in Nutsch’s overall reaction to the proposal.

“This SAR likely causes more burden than benefit to the protection and control of our BES assets,” Nutsch said. “If there is sufficient evidence to show that AVR trips are causing havoc across the interconnections, perhaps it is worth further consideration. However, as it is currently written, this SAR seems to add little value for the amount of effort it would entail to employ.”

July 16, 2020

Record Number of Entrants Line up for MISO Queue

Facing an unprecedented number of new generator applicants, MISO this week reaffirmed its aim to speed up its interconnection queue.

The grid operator hopes to shrink the time it takes to complete generation interconnection agreement negotiations and clear the queue’s three-part definitive planning phase (DPP), when it performs interconnection studies.

Currently, the queue’s DPP alone takes approximately a year to complete. Combined with interconnection agreement negotiations, the timeline grows to about 505 days. Earlier this year, stakeholders asked through a formal submission to the Steering Committee that MISO address DPP delays.

MISO has said that if the queue’s DPP and GIA negotiations could be shortened to a year total, it would further its goal of aligning the interconnection queue with planning under its annual Transmission Expansion Plan. (See MISO Targets Swifter Queue Processing.)

A speedier process could keep MISO executing interconnection agreements as it prepares to face its largest-ever queue. The June 2020 cycle of prospective projects could bring the interconnection queue to more than 750 projects totaling 112 GW.

Through early June, the RTO was performing interconnection studies on 406 projects totaling 62 GW, more than half of it solar generation. More than 350 additional projects totaling more than 50 GW applied to enter the interconnection queue before the June 25 deadline, interconnection engineer Cody Doll told the Interconnection Process Working Group on Tuesday.

Not all of the 350 projects may survive MISO’s application validation. “We won’t know until we go through and validate the projects which ones will be in the 2020 cycle,” Manager of Resource Utilization Project Management Jesse Phillips said.

This isn’t the first time the queue will exceed 100 GW. It peaked at a proposed 101 GW worth of projects in 2019 before declining as projects withdrew. MISO says about 20% of projects entering the queue complete the interconnection process.

“The cycles are massive, and they’re not slowing down,” Doll said. “It’s going to lead to challenges because there are so many projects.”

The 2020 cycle was the first time MISO used a completely online application process. (See Wary of Contagion, MISO Bars Visitors for 2020.)

Doll said that with increased queue entrants, MISO’s ability to handle the administrative processing of the interconnection requests may be stretched thin. “We may need to throw more people at certain tasks,” he said.

Doll also said affected-system studies, where MISO must wait on other RTOs to study projects near the seams for impacts, remain an obstacle to shortening the timelines.

Several active queue cycles dating from 2017 are currently delayed at least into fall by ongoing affected-system studies. SPP’s studies are affecting projects in the Central and West planning regions, while PJM’s impact the East region’s projects.

Phillips said MISO continues to work with SPP on how the two can cut down on the time needed to conduct affected-system studies.

MISO’s next queue application deadline is March 18, 2021.

July 16, 2020

Panel: Much More Tx Needed for New England OSW

New England needs to build much more onshore transmission to facilitate the incoming surge of offshore wind generation, panelists on a Northeast Energy and Commerce Association webinar said Wednesday.

NECA convened the webinar to discuss how much offshore wind New England can integrate, with representatives from the New England States Committee on Electricity (NESCOE), Anbaric Development Partners and RENEW Northeast summarizing the results of studies their organizations requested from ISO-NE Planning Advisory Committee Briefs: June 17, 2020.)

NESCOE counsel and analyst Ben D’Antonio provided an overview of ISO-NE’s findings under the organization’s requested assumptions. The RTO concluded that about 5.8 GW of offshore wind can be interconnected using AC transmission without significant upgrades to the onshore grid. That’s “if you do it in a strategic way,” at certain points of interconnection, D’Antonio said.

But “above that threshold … major reinforcements to the system were identified as being necessary.” The RTO identified at least four 345-kV onshore lines that would need to be built to facilitate additional offshore resources.

New England Offshore Wind — ISO-NE identified several strategic points of interconnection for offshore wind resources that would negate the need for major onshore transmission upgrades — but only up to 5.8 GW. | *ISO-NE*

It also determined that it’s possible to interconnect up to an additional 2.2 GW — for a total of 8 GW — through long-distance HVDC lines without the need for new onshore transmission. But regardless of the solution, it found the costs to reaching the 8-GW mark were comparable: about $1 billion, D’Antonio said.

Perhaps more stark, however, is the huge amount of renewable energy that would be “spilled,” or curtailed, even with the additional transmission identified: more than 15 TWh/year. Most of that is attributable to oversupply during the fall and spring shoulder months, when load is low, and not to transmission congestion.

“This loss of clean generation can undermine state initiatives to reduce our carbon footprint,” said Katie Bellezza, senior vice president of commercial management and strategy for Novatus Energy, a RENEW member. RENEW’s study focused on Maine’s existing onshore wind, which already experiences significant curtailment.

“Land-based wind and new transmission is currently the least-cost renewable resource available in New England,” she said. “However, due to smaller procurements, it’s difficult to justify those transmission costs. With infrequent onshore renewable procurements of limited scale, we really need to look at other ways besides procurement to fund transmission.”

Anbaric requested that ISO-NE look at higher penetration levels than NESCOE, up to 12 GW. “When we put that request in just last year, it seemed potentially pretty ambitious, but it’s just been remarkable to see the [state OSW] goals increase,” said Peter Shattuck, Anbaric senior vice president for communications.

“When we look big-picture, what we need to avoid is the sort of situation we have now in Maine, where transmission was considered essentially an afterthought, and now there are a lot of bottled-up resources,” he said.

Shattuck also reviewed Anbaric’s proposed undersea transmission network and the Brattle Group’s analysis of it. (See Brattle Study Highlights Benefits of Offshore Grid.)

Moderator Mary Usovicz, principal of consulting firm MUConnections, brought up Eversource Energy and National Grid’s finalist bid in ISO-NE’s first competitive transmission solicitation under National Grid, Eversource Finalist for Boston Tx Plan.)

Usovicz asked the panelists whether they thought there was a better solution.

Shattuck, whose company submitted its own proposal, said, “It just seems like this decision was made on a very narrow, capital-cost basis, and that [basis] risks deferring the upgrades that are going to be needed [for OSW]. … It was essentially a missed opportunity to think bigger picture and really reflect the moment that we’re in right now in New England, where we need a grid that’s centered on renewables.”

“I’ll just kind of state the obvious and say that [decision] was done for reliability, and trying to right-size a solution for reliability is a little bit different than trying to right-size it for maybe a public policy-related issue,” D’Antonio said.

July 16, 2020

Southeast Utilities Talking Regional Market

Utilities and cooperatives in the Southeast have been meeting for months on a plan to create a regional 15-minute energy market, officials confirmed Wednesday.

The talks, led by Southern Co. and Duke Energy, were largely secret until Monday, when the initiative was mentioned at a meeting of stakeholders working on North Carolina Gov. Roy Cooper’s Clean Energy Plan. The Charlotte Business Journal was the first to report on the plan Tuesday, saying as many as 20 companies may be involved.

Officials of Southern, Duke and the Tennessee Valley Authority confirmed the talks Wednesday, saying the Southeast Energy Exchange Market (SEEM) would be a 15-minute energy market designed to lower customer costs, optimize new renewable energy resources and improve reliability.

Dominion Energy South Carolina; Oglethorpe Power; PPL subsidiary LG&E and KU Energy; Santee Cooper (the South Carolina Public Service Authority); the North Carolina Electric Membership Corp.; the North Carolina municipal members of ElectriCities; and several electric cooperatives also are reportedly involved in the talks.

‘Exploratory Stage’

Southern Co. spokesman Schuyler Baehman said talks are in the “exploratory stage.”

“If we determine that partnering with our neighbors makes sense, we’ll certainly take the appropriate steps to describe that more fully for regulators and stakeholders,” he said.

“While we’re still early in the learning phase, we’re eager to see the kind of benefits a regional energy market might have for our customers, particularly if it helps improve how we can jointly operate growing solar resources on our systems,” Duke spokeswoman Erin Culbert said. “This evaluation is a response to stakeholder interest we’ve been hearing for a few years on a potential energy market so we can advance these concepts and see if they make sense.”

Southeast Regional Market — | *ISO/RTO Council*

“If we determine that partnering with our neighbors makes sense, we’ll certainly take the appropriate steps to describe that more fully for the 10 million people we serve,” TVA spokesman Jim Hopson said.

The Southeast is the only region of the continental U.S. that has not moved to some form of regional market, continuing to be served by vertically integrated monopoly utilities. Lawmakers in North and South Carolina, however, have been discussing prospects for joining or creating a new regional market for more than a year.

Culbert said the SEEM would be limited to energy — not capacity — and build on the existing bilateral market. It would use the “same principles” as the Western Energy Imbalance Market but be less “granular [and] costly to set up,” she said.

“It would allow participants to buy and sell power close to the time electricity is consumed and would give system operators real-time visibility across neighboring electric grids,” she said, adding that better integration of renewables could mean fewer solar curtailments.

“This isn’t a regional transmission organization, nor does it prohibit the ability for any of the companies to form or join an RTO in the future,” she added. “No decisions have been made yet. As we learn more details, we’ll be sharing those with regulators and stakeholders and, if we proceed, would make the appropriate filings with FERC, etc.”

Lack of Transparency?

News of the utility discussions alarmed some stakeholders.

“More competition in the electricity sector is inherently good for ratepayers and the economy, but it’s not truly competition if vertically integrated utilities can continue exercising their monopoly power,” Katherine Gensler, vice president of regulatory affairs for the Solar Energy Industries Association, said in a statement. “As details emerge, policymakers must ensure that this imbalance market has the proper governance to ensure that ratepayers, generators and participating utilities can all share the benefits.

“While an energy imbalance market may be the best solution for the Southeast, we should take a collaborative approach to discussing utility business model reforms, including robust stakeholder input,” Gensler continued. “We cannot be in the situation where utilities ignore stakeholders and state legislators and simply announce their preferred solution. We care deeply about expanding competition, but today’s news shows an alarming lack of transparency.”

“The South’s power sector — dominated by large monopolies with not enough accountability or competition — is in need of significant change,” said Frank Rambo, senior attorney for the Southern Environmental Law Center. “A fully open wholesale electricity market could produce the efficiencies and competition that would result in cleaner energy and lower power bills, but a plan hatched in secret by the monopoly utilities that have most benefited from the status quo is not a promising vehicle to deliver that kind of change.”

A spokesman for the South Carolina Public Service Commission said he was unaware of the discussions. The North Carolina Utilities Commission did not immediately respond to a request for comment.

RTO Legislation

North Carolina House Bill 958, introduced in April 2019, would authorize the NCUC to require the state’s investor-owned utilities establish or join a regional transmission entity after determining such a move would be in the public interest. It was referred to the House Committee on Rules, Calendar and Operations of the House.

South Carolina lawmakers introduced legislation (S. 998 and H. 4940) in January 2020 that would establish an Electricity Market Reform Measures Study Committee to study the benefits of electricity market reforms and whether the legislature should adopt them. In February, H. 4940 crossed over to the Senate.

Prior Studies

In May, law firm Nelson Mullins Riley & Scarborough sponsored a webinar on “How Markets and Reform Can Reduce Electricity Costs in the Carolinas.”

Among those who spoke were Jennifer Chen of Duke University’s Nicholas Institute for Environmental Policy Solutions and the author of a March 2020 policy brief titled “Evaluating Options for Enhancing Wholesale Competition and Implications for the Southeastern United States.”

Rachel Wilson of Synapse Energy Economics shared evidence indicating that membership in an RTO would result in savings for Duke customers.

She said the 2012 merger of Duke and Progress Energy, which combined their generation fleets in the Carolinas, “resulted in hundreds of millions of dollars in savings,” prompting questions about whether joining an RTO would produce bigger savings.

One study estimated that joining PJM could reduce production costs for Duke’s North Carolina customers by up to $600 million annually, a savings of 9 to 11%, Wilson said.

In Duke’s 2018 integrated resource plan proceedings, Synapse compared the company’s proposed IRP with an alternative scenario for the North Carolina Sustainable Energy Association.

While the Duke IRP called for using new gas resources to meet future demand, the “market scenario” used solar paired with storage, as well as standalone solar and battery resources, to meet projected peak.

Under Duke’s IRP, fossil fuels would be 42% of its fuel mix with renewables representing 9%. The market scenario reduced coal to 1% and gas to 8%, with renewables taking a 27% share, imports representing 18% and nuclear making up most of the rest.

By 2033, Synapse said, wholesale costs under the market scenario would be 30% lower than under the IRP.