Page 1060 – RTO Insider

March 15, 2019

NERC Chief: No ‘Appetite’ for Expanding Authority

By Rich Heidorn Jr.

WASHINGTON — NERC CEO Jim Robb said Thursday he sees no “appetite” among policymakers for expanding the organization’s authority despite rising concerns over the visibility of distributed energy resources.

NERC CEO Jim Robb speaking Thursday at the agency’s biennial Reliability Leadership Summit at the Mayflower Hotel in D.C. | © *RTO Insider*

Robb made the comments to reporters after NERC’s daylong biennial Reliability Leadership Summit, where more than 130 regulators, utility officials, RTO executives and others gathered to compare notes on best practices, industry trends and emerging challenges.

The discussions turned repeatedly to the reliability challenges posed by a changing generation mix and the increasing volume of DERs, which are not under the operational control of regional grid operators.

“In the current model, [for] vertically integrated utilities, it’s pretty clear who’s accountable for generator performance, maintenance, testing … but that gets very fuzzy in the DER world,” said John Stephens of City Utilities of Springfield Missouri. “How do we hold them accountable? How do we know our planning assumptions are valid for more than the next six weeks?”

Talking with reporters after the conference, Robb was asked if he thought federal policymakers would someday look to expand NERC’s authority beyond the bulk power system.

“I don’t think there’s a whole lot of appetite for that,” he responded.

“I think visibility is very important. I think that’s one of the issues that … can be done voluntarily. It doesn’t necessarily have to be done through a standard or regulation — because nobody wants this issue, right? Nobody wants to be the [regulator] sitting on top of a major reliability event.”

Robb said NERC has “maintained a fairly regular dialogue” with the National Association of Utility Regulatory Commissions and individual state regulatory agencies. “So, they’re aware of the work we’re doing that’s applicable to them. That’s one of the areas both sides have agreed we need to do more of as this line continues to blur and more and more of the resource sits on the distribution side of the house, or the sub-BPS.”

Confident on Cybersecurity

Robb also expressed confidence over the grid’s ability to withstand cyberattacks, despite the Worldwide Threat Assessment released by U.S. intelligence agencies in January, which raised warnings about the ability of Russian and Chinese hackers to disrupt electrical service and natural gas pipelines in the U.S. (See Senators Call for Urgency on Energy Cybersecurity.)

“The system provides substantial protections in terms of a major cyber event. … It’s built to withstand the loss of large assets,” Robb said. “So, while I would never say zero [risk], I don’t think this is something that we need to be worried about — something taking down half of the Eastern Interconnection.”

How about blacking out a major city?

“Possibly more vulnerability there, but even then, it would be likely something that could be recovered from fairly quickly,” Robb said.

The NERC chief said he agrees that China and Russia “are persistent threat actors.”

“They are working very, very hard to build capabilities to penetrate the grid. Most of the vulnerabilities are on the enterprise side of the house — IT systems — not the operating systems. And we have very vigorous rules around firewalls and air gaps between enterprise systems and the operating systems. If somebody could even get into a company’s enterprise system, their ability to translate that into something actionable on the control side of the system is substantially mitigated.”

Asked whether fuel security is more of a concern than cybersecurity, Robb paused, then laughed.

“It depends on the day. Both are very, very important. The difference is that [with] cyber, you’re dealing with a persistent threat, whereas fuel security is more of a random event, like any other reliability event. But there are clearly areas of the country that are getting closer and closer to the edge, related to fuel. We’ve heard about New England. We heard about the issues in Southern California. And we’ll see more and more of that as the system becomes more and more reliant on natural gas and it becomes harder and harder to develop the gas infrastructure to support it.”

March 13, 2019

Courts Misread Hughes on Nuke Subsidies, Supreme Court Told

By Rich Heidorn Jr.

Merchant generators’ Hail Mary pass for a U.S. Supreme Court review of Illinois and New York nuclear subsidies has won support from PJM’s Independent Market Monitor and others, who said lower courts have misinterpreted precedent on federal jurisdiction.

The Electric Power Supply Association asked the court in January to review rulings by the 2nd and 7th U.S. Circuit Courts of Appeals that the subsidies did not intrude on EPSA Asks Supreme Court to Review ZEC Rulings.)

Exelon joined Illinois and New York officials in saying the court should leave standing the states’ zero-emission credit programs. EPSA was supported by the Monitor, PJM industrial customers, the American Petroleum Institute and a group of economists.

The Supreme Court hears a small percentage of the cases on which it is petitioned. But the stakes of a ruling could have impacts beyond New York and Illinois. New Jersey and Connecticut have also approved nuclear subsidies and Pennsylvania regulators introduced a subsidy bill on Monday. (See Pa. Lawmakers Unveil $500M Nuke Subsidy Bill.)

‘Artful Description’

EPSA’s supporters said the appellate courts misinterpreted the Supreme Court’s 2016 ruling in Hughes v. Talen, in which the court unanimously rejected Maryland’s contract-for-differences with a natural gas plant.

The court also provided state regulators guidance for crafting their programs in the future, saying it rejected Maryland’s initiative only because it was tied to PJM capacity prices. “So long as a state does not condition payment of funds on capacity clearing the auction, the state’s program would not suffer from the fatal defect that renders Maryland’s program unacceptable,” the court said.

Monitoring Analytics, PJM’s Monitor, said the appellate courts were mistaken in upholding the ZEC programs based on the Hughes ruling.

“Legislators can easily contravene FERC’s authority over wholesale rates by artful description or avoiding description of the mechanism rather than transparent statutory language. An explicit tether like that appearing in Hughes is easily avoidable, as the ZECs programs at issue here illustrate,” the Monitor wrote.

The Monitor said failing to overturn the appellate rulings “may effectively end federal control over the interstate wholesale power markets, contrary to the jurisdictional framework in the Federal Power Act. The record shows that FERC has gone out its way to accommodate the states. How have the states accommodated FERC? If anything, petitioners understate the risk. The public will be ill served if regulation through competition survives in name only.”

Seven economists, including Roy Shanker and Harvard’s William Hogan, agreed.

“The courts of appeals sought to distinguish the ZEC subsidies adopted by Illinois and New York from the contract-for-differences subsidy adopted in Maryland. From an economic point of view, however, those distinctions are without substance,” they wrote. “As with the Maryland program, the ZECs pay favored generators a subsidy based on their wholesale market participation, thereby guaranteeing them a price that is different from the price set in the auction. Although there are differences in the details of the price-setting mechanisms employed by the subsidy programs, those differences are largely irrelevant to their basic design and purpose.”

The economists also said the ZEC programs may not support carbon-free electric generation, as their supporters contend.

“There is no assurance that the generating resources that the nuclear generators will displace are carbon-emitting: on the contrary, the distorted market may discourage entry of clean energy sources and thereby perpetuate carbon emissions,” they said. “It also may discourage conservation, and indeed encourage greater consumption, due to lower wholesale prices, resulting in greater amounts of generation from less ‘clean’ resources.”

A group of industrial consumers disagreed with the lower courts’ likening of ZECs to renewable energy credits. “ZECs are calibrated to backfill the difference between wholesale market revenue and the claimed revenue requirement of particular uneconomic nuclear units,” said the PJM Industrial Customer Coalition, the American Forest & Paper Association, the Illinois Industrial Energy Consumers and the Electricity Consumers Resource Council. “While RECs are traded on an open market among various market participants, ZECs are state-mandated payments from customers in that state to specific qualifying nuclear units.”

The American Petroleum Institute also called for a Supreme Court review of the New York program, calling it “incompatible with federal energy policy governing wholesale markets.”

Exelon, States Respond

Exelon Generation, the largest nuclear operator in the U.S., said the court should leave the circuit court rulings alone, citing what it said are procedural problems with EPSA’s petition.

“FERC, the states and all eight judges to have considered the question agree: There is no pre-emption,” Exelon said. “Petitioners cry that ZEC programs will destroy FERC’s markets, but that is belied by FERC’s own words. FERC and the United States told the court that FERC ‘has the means and the authority to confront’ any ‘effects’ on its markets from ZEC programs, and that ‘the Federal Power Act does not pre-empt’ such state programs.”

Exelon noted that FERC is considering market rule changes to accommodate state programs while insulating wholesale markets. “Judicial intervention now would disrupt FERC’s effort to use the scalpel of regulation, rather than the chainsaw of pre-emption,” it said.

The Illinois Power Agency and Illinois Commerce Commission insisted the 7th Circuit’s ruling upholding the state program was consistent with Hughes and other precedents under the FPA.

“Petitioners’ argument disregards key differences between the two programs that firmly support the 7th Circuit’s conclusion that the ZEC program falls comfortably within the states’ authority over power generation and does not invade FERC’s authority to regulate rates for wholesale sales of electricity,” they said. “Put simply, ZEC payments for generating emission-free electricity do not set the price for any wholesale sale of that electricity.”

The New York Department of Public Service agreed. “Because ZECs are awarded for production without regard to sales, they will not change how eligible plants sell their output,” it said. “They will not induce a generator to sell in a wholesale auction instead of by contract or at retail. Nor will they change the bidding behavior of a generator that opts to sell in a wholesale auction. When a nuclear plant sells its output in a wholesale auction, it does so as a price taker because it cannot readily turn off and on in response to short-term price fluctuations.”

March 13, 2019

PJM to FERC: Hurry Up with Auction Guidance

By Christen Smith

PJM urged FERC on Monday to expedite guidance on the RTO’s upcoming Base Residual Auction as stakeholders prepare for deadlines on two different sets of rules (E L 16-49).

The filing comes days after PJM’s Jeff Bastian walked the Market Implementation Committee through the upcoming schedule in what he called a “parallel path” to the Aug. 14 auction, for delivery year 2022/23. Sellers will have to confirm whether they will be offering resources with “actional subsidies” by March 17 — a deadline stakeholders said was unreasonable. (See Capacity Market Sellers Anxious Over Uncertain PJM Auction Rules.)

FERC last summer granted PJM’s request to delay the auction in response to the commission’s ruling requiring the RTO to revamp its minimum offer price rule (MOPR) to address price suppression from rising state subsidies for renewable and nuclear power (ER18-2 222). PJM filed its proposed MOPR changes Oct. 2 and said a FERC ruling by March 15 would keep the August schedule on track — though Bastian said on March 6 it seemed no direction from the commission was imminent.

Stakeholders pressed PJM to file an additional waiver delaying the auction again, but the RTO preferred to prepare for two different scenarios: moving ahead with existing Tariff provisions in the absence of FERC guidance and also requiring sellers to file based on PJM’s proposed rules.

“To avoid a ‘self-fulfilling prophecy’ of frustrating the ability of PJM to implement the substitute Tariff provisions it served up to the commission in this proceeding, PJM believes that for the moment, it is prudent to continue to require submittals under both the new proposed and existing Tariff provisions,” PJM said in its March 11 informational filing.

The RTO went on to say FERC’s inaction grows more problematic every day.

“A timely comprehensive ruling by the commission is clearly needed as we approach the August BRA and the various preparatory deadlines for submittals by market participants leading up to the August auction,” PJM said in the filing. “However, in the interim and at least for the present upcoming deadlines, PJM believes it prudent to continue, as it has done in other instances, to proceed down a path requiring submittals under both the existing market rules as well as the PJM proposed market rules.”

PJM pointed out that while it has previously conducted auctions in the face of pending Section 205 filings and Section 206 complaints, “it has not conducted an auction when there has already been a commission finding that its existing capacity market rules are unjust and unreasonable with no established just and reasonable replacement rate in place — as is the circumstance PJM finds itself in now.”

March 13, 2019

RTO Insider Reporter Admitted to NEPOOL

The New England Power Pool voted Wednesday to admit RTO Insider correspondent Michael Kuser as an End User member under strict rules that prevent him from reporting publicly on what he hears in meetings.

The organization acted in response to NEPOOL Seeks Rehearing on Press Ban Order.)

Many of NEPOOL’s meetings are held at the Westborough, Mass., DoubleTree Hotel. | *Google*

The stakeholder group had sought to amend the NEPOOL Agreement to bar members of the press from joining after Kuser, an electric ratepayer in Vermont, applied to join in March 2018.

In its vote Wednesday, NEPOOL’s Participants Committee conditioned Kuser’s admission on compliance with its bylaws, which were rewritten in June 2018 in response to his application.

NEPOOL said the revisions were intended to codify a longstanding practice barring disclosure of meeting proceedings to nonmembers. But they also appear to carve out an exception for members who are not members of the press.

Section 5.6(a)(ii) states that:

“Attendees may use the information received in discussion, and may share the information received within their respective organizations or with those they represent, provided those who receive such communications are not press and also are aware of and agree to respect the nonpublic nature of the information. In no event may attendees reveal publicly the identity or the affiliation (other than sector affiliation) of those participating in meeting discussions…”

Members who violate the provision, the bylaws state, will have their attendance privileges revoked.

FERC’s January order said it would rule separately on RTO Insider’s complaint asking the commission to terminate the group’s stakeholder role or direct ISO-NE to adopt an open stakeholder process like those used by other RTOs (EL18-196). New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings or discussing them publicly.

RTO’s Interim Winter Fuel Proposal Rejected

In other action Wednesday, NEPOOL stakeholders rejected ISO-NE’s interim proposal for compensating generators for maintaining fuel inventories during winter.

The proposal, which would cover capacity commitment period 14 (2023/24) and 15 (2024/25), received less than 33% vote in favor, with most support from the Generation, Transmission and Publicly Owned sectors.

Members also rejected a proposal by energy services firm Energy New England that would have limited compensation to oil and certain natural gas, demand response and electric storage resources. It failed with less than 40% support, with most backing from the Supplier, Publicly Owned and End User sectors.

The votes were no surprise: Both proposals also fell short at NEPOOL’s Markets Committee last week. However, an ISO-NE Steady on Fuel Plan Despite NEPOOL Rebuff.)

ISO-NE’s plan is intended to prevent otherwise economic resources from retiring because they are not fully compensated for their winter energy security attributes. The RTO describes it as an interim measure until it completes development of a market-based compensation scheme for energy security.

The Participants Committee agenda had teed up a potential vote on proposals concerning the treatment of energy efficiency resources under the Pay-for-Performance capacity rules. However, no motion was made on the issue, according to NEPOOL.

At last week’s Markets Committee meeting, members had rejected a proposal by the New England Power Generators Association to address a disconnect in the calculation of PfP penalties during scarcity conditions in off-peak hours.

— Rich Heidorn Jr.

March 13, 2019

MISO Details Fast-track Queue Options

By Amanda Durish Cook

MISO on Tuesday confirmed that it will work with stakeholders to develop a fast-track option in its interconnection queue to accelerate the process for projects that can demonstrate readiness for development.

The RTO’s effort will focus on creating an expedited definitive planning phase (DPP) to move projects into generation interconnection agreements (GIA) faster than in the existing three-phase process.

In what was an about-face for MISO, staff last month expressed receptiveness to a fast-track queue option for shovel-ready projects. (See FERC Again Denies MISO Wind Developers’ Queue Complaint.)

MISO’s queue now contains about 420 projects worth a combined 70 GW, after interconnection customers withdrew 43 projects in January, with renewable resources accounting for about 90% of the queue. The average project takes a little more than 500 days to work its way from application to interconnection approval.

Although MISO has signaled readiness for a proposal, it says several design details need to be worked out. Resource Interconnection Planning Manager Neil Shah said the move would be heavily shaped by stakeholder input.

“We’re all open ears on this,” Shah told stakeholders during a March 12 Interconnection Process Working Group meeting.

Shah said MISO, which deferred fast-track discussion in 2017 based on lukewarm response from interconnection customers, has since received “a handful” of new requests for an expedited DPP. Devising a fast-track option now would be a “proactive” move, he said, adding that MISO’s current provisional GIA process has limitations, with customers completing the process without a permanent GIA in place.

“We heard the process is not meeting needs for shovel-ready projects,” he said.

Shah foresees an expedited DPP that can be scaled in three to six months for select projects: “That’s what I envision. Obviously, they should be ready to provide all the evidence that they’re ready.”

He said project owners would have to “submit evidence of viability at the time of request” to use the expedited process.

However, MISO staff said they have not yet determined exactly how to measure project readiness.

But the RTO is considering multiple requirements for entering the expedited DPP, Shah said, including higher queue fees, more certain environmental permitting, cash as security and a method for covering the risk of queue restudies.

MISO also said projects opting for the expedited process will still be responsible for the full cost of necessary network upgrades.

‘Queue-jumping?’

Entergy’s Yarrow Etheredge asked MISO to look into the possibility of project owners using the expedited process to “game” the interconnection queue.

Shah agreed and asked if stakeholders would have “queue-jumping concerns” if the expedited option becomes available to all interconnection customers. He also asked whether they would prefer either a megawatt cap or a limit of the number of projects an interconnection customer can request.

“If it’s available to all customers, is it queue-jumping?” Shah asked stakeholders. He added that if MISO crafts stringent enough requirements, it may not have to worry about limits.

“If there’s two queues, one for shovel-ready projects, and one for speculative projects, it might not be queue-jumping,” Etheredge said.

“Excellent point,” Shah replied.

Shah also asked for written stakeholder input until April 2. MISO staff will review the feedback and return with more discussion at the May 14 meeting of the Interconnection Process Working Group.

Measures to Accelerate Existing DPP

MISO says it is also developing a plan to reduce its regular, three-phase queue design and GIA process. The current DPP alone is approximately 355 days, which the RTO is proposing to reduce to 265 days, with Phase 1 cut from 140 to 80 days, Phase 2 staying roughly the same at about 80 days and Phase 3 slimmed from 135 days to about 105 days. MISO will also attempt to reduce the timeline allotted to negotiate GIAs from 150 days to about 100 days.

“We looked back in the history of queue reform. We’ve gone through a number of process improvements. … After reassessing the queue … we thought maybe we can look at a different angle to gain efficiencies to reduce the timeline,” MISO Manager of Resource Interconnection Arash Ghodsian said.

To achieve the reductions, MISO said it will start generation modeling before Phase 1 of the DPP begins and complete voltage and thermal studies internally rather than outsourcing them. Ghodsian said MISO found it can complete the study quicker than it takes a third party to develop study models. The RTO also expects less complicated Phase 3 modeling and system impact studies after already moving to reduce the number of late project dropouts by increasing site control deposits and milestone fees. (See MISO to File Queue Changes Before Year-end.)

Ghodsian also noted that reduced time spent on GIA negotiations is an obvious spot to seek efficiencies, given that 57% of projects that sign interconnection agreements do so under the full timeline outlined in the Tariff.

But stakeholders said multiple project applications currently in the queue claim the same patch of land for building generation, which could complicate early modeling. MISO staff agreed that certain steps must be taken before the RTO holds scoping-level calls as part of the queue application process.

“Those things must be addressed before we start analysis. I agree we’re seeing some of this today,” Ghodsian said. He said MISO’s queue improvements proposed last year should help “quality control” the project applications.

“There’s going to be a lot of back-and-forth going on. We’re going to have checkpoints,” Ghodsian said of drafting the models. He also called MISO’s proposed timeline “a starting point” and asked for written stakeholder input through April 2.

“This is just a proposal; we would like to hear your thoughts on these changes,” Ghodsian said.

March 13, 2019

Murkowski and Manchin: Ds, Rs Can Work Together on Climate

By Tom Kleckner

HOUSTON — Sometime in the future, pigs may fly, the moon might turn blue and bipartisanship could break out in D.C. Until then, there’s the Senate Energy and Natural Resources Committee (ENR), led by Chair Lisa Murkowski (R-Alaska) and ranking member Joe Manchin (D-W.Va.).

Sen. Joe Manchin (D-W.Va.) at CERAWeek by IHS Markit | © *RTO Insider*

“We like each other. Being a Democrat and a Republican does not interfere with our job,” Manchin said during an appearance at the CERAWeek by IHS Markit energy conference Monday. “We represent our states and do what’s best for the country.”

“I always wonder when did energy become a partisan issue, and why does it have to be partisan? It used to be a regional issue,” said Murkowski, who has chaired or served as the committee’s ranking member for the past 10 years. “I like to think we can show the leadership in Congress that we should be working together in key areas.”

“Stand down on the rhetoric,” she continued. “I want to set a tone that is bipartisan, that is welcoming … where there is a safe space for dialogue that leads to pragmatic solutions.”

Murkowski and Manchin appeared together on a CERAWeek panel days after publishing an op-ed in The Washington Post that called for “responsible” action on climate change. “There is no question that climate change is real or that human activities are driving much of it,” they wrote, taking a position their constituents might consider heresy.

The op-ed was a follow-up to the ENR Committee’s hearing on climate change last week. (See Senate ENR Committee Discusses Climate Change.)

The column did not mention Manchin’s staunch support for West Virginia coal mining, nor Murkowski’s backing of oil drilling in the Arctic National Wildlife Refuge, policies that contribute to carbon emissions. Nor did it make any concrete policy proposals. They suggested only that the solution to climate change is unleashing American ingenuity, saying that the U.S. “must continue to lead the world in the development of new and improved technologies.”

“If we’re going to talk the talk about how we innovate our way to a lower-carbon economy, let’s make sure we facilitate and foster these really great ideas,” Murkowski said, referring to CERAWeek’s exhibit halls filled with the latest in energy technology. “It’s like dream stuff out there. This is what we need to advance a lower-carbon economy. Is it the government’s role to take every great idea and underwrite it? Absolutely not, but we can wisely help facilitate their development.”

President Trump’s proposed 2020 budget would cut funding for the Department of Energy’s Office of Energy Efficiency & Renewable Energy (EERE) by 70% and eliminate the Advanced Research Projects Agency–Energy. Congress rejected similar proposals last year.

“We come from communities with challenging environments. We have to reduce emissions in a way that does not leave the community worse off,” Murkowski said. “Let’s try to dial down some of the rhetoric out there. Let’s stop the messaging and the name-calling and the finger-pointing. Instead, let’s decide what are some of the paths forward.”

Manchin said coal and other fossil fuels still need to be part of the energy mix. “You’re not going to eliminate fossil fuels, so you better find the solution or next generation. There has to be a balance,” he said.

Sen. Lisa Murkowski (R-Alaska) speaks during a Q&A session at CERAWeek by IHS Markit. | © *RTO Insider*

Murkowski and Manchin both took shots at the proposed Green New Deal. Manchin referred to the resolution as a position statement, while Murkowski bemoaned its use as a political wedge. Senate Majority Leader Mitch McConnell (R-Ky.) intends to put the measure up for a vote to get the Senate on the record.

The Green New Deal has “created even more of a divide when we should be coming together to address the problem,” Murkowski said. “Now is not the time to put everyone in their corners and have them come out fighting with rhetoric. I find it distracts from the solutions. If you don’t like the Green New Deal, what is your plan?”

During both his press briefing and panel appearance, Manchin referred to a competing op-e d penned for CNBC by former Energy Secretary Ernest Moniz, who served under President Barack Obama, and Andy Karsner, who headed EERE during George W. Bush’s administration. Moniz and Karsner refer to a “Green Real Deal” that ensures a “wise and just transition to a low-carbon economy” and minimizes “stranded physical assets … workers and communities.”

“They say we’re not getting there as fast as we want, but we’re getting there as fast as we can politically,” Manchin said.

Murkowski worked for years with former ENR ranking member Maria Cantwell (D-Wash.) to craft a new energy policy to update the last sweeping energy bill, the Energy Policy Act of 2005.

“The energy bill is coming; we have not given up that,” Murkowski said. “When you think what has happened in the energy space, with LNG terminals, renewables, batteries … when you think how much we’ve done and how we’ve done it with the anchor of policy that hasn’t been enacted … there’s so much that is not fresh.”

But this time may be different, Murkowski said.

“You’re seeing others, not just Democrats, opening up the conversation, which you didn’t see five years ago,” she said. “How we move forward with it is going to be important. We’re putting together a conceptual plan. Saying you’re either for this or you’re part of the problem, that’s not the way to get started.

“The more we push people off in either lane here, it will be hard for people to get to the center to come up with solutions that gain political support. Let’s be practical about this.”

March 12, 2019

ERCOT Stakeholders Dig into Real-time Co-optimization

By Tom Kleckner

ERCOT stakeholders last week began taking a deeper look at real-time co-optimization (RTC), the market tool that procures both energy and ancillary services every five minutes to find the most cost-effective solution for both requirements.

Asked by Texas’ Public Utility Commission to “reinitiate discussions” with stakeholders on the tool, ERCOT held a workshop on Wednesday. The PUC, which wants to see RTC “sooner rather than later,” is working to hold its own workshop in early June and is soliciting stakeholder feedback on a list of related issues. (See “PUC, ERCOT Set Real-time Co-optimization Workshops,” Texas PUC Briefs: Week of Feb. 25, 2019.)

Meanwhile, the member-led Technical Advisory Committee, which makes recommendations to the ERCOT Board of Directors, has been gathering member feedback on an RTC task force in advance of its upcoming March 27 meeting. TAC Chair Bob Helton, of ENGIE, said in an email to members that the committee’s leadership would like to see the task force led by two co-chairs reporting directly to the committee.

“The task force would not be a voting body, and [its] leadership would report any recommendations to TAC, including any minority positions,” Helton wrote.

The TAC will endorse the group’s final structure, leadership and other details, with the board making the final decision.

“This is a good opportunity for our stakeholders to come together and work to ensure we design something that helps achieve our objectives and reflects the value of ancillary service,” ERCOT COO Cheryl Mele said at a recent market summit.

ENGIE’s Bob Helton and ERCOT’s Cheryl Mele | © *RTO Insider*

Staff told stakeholders during the workshop that RTC will efficiently coordinate the provision of energy and AS in the real-time market and, similar to the operating reserve demand curve (ORDC), price AS shortages according to their defined demand curves.

Sai Moorty, ERCOT’s market design and analysis principal, said the RTC process will be executed with each security-constrained economic dispatch run, yielding “better visibility of the constraints and the capabilities of the resources.”

“As a result, the system can be operated more economically and reliably,” he said. “This benefits loads by selecting the lowest-cost resources to provide energy and AS.”

Unlike the ORDC, the SCED engine will apply a demand curve for each AS product, establishing offer-based prices for energy and AS types in the real-time market, staff said. The defined AS demand curve will set AS shortage conditions, and ORDC price adders will no longer exist.

“Real-time co-optimization will definitely impact temporary price spikes we’ve seen outside the ORDC,” NRG Energy’s Bill Barnes said at the same summit. “Demand curves for ancillary service … ensure we’re sending proper price signals during times of scarcity.”

ERCOT’s Operations Center | © *RTO Insider*

ERCOT grid operations have not yet identified a reliability need to define a local reserve product, staff said, noting the RTC design will co-optimize the required reserves.

The PUC, which has opened a project for RTC (48540), is considering whether to allow financial-only AS offers.

Staff have said it will take four to five years and about $40 million to implement the RTC process and software.

March 12, 2019April 22, 2024

Overheard at Transmission Summit East 2019

ARLINGTON, Va. — Transmission developers, planners and regulators gathered last week on the top floor of the Key Bridge Marriott, overlooking D.C. from across the Potomac River, for Infocast’s annual Transmission Summit East. Panels and presentations covered a little bit of everything, from energy storage to cybersecurity.

Hoecker, Demarest Propose Interstate Tx Siting Bill

James Hoecker and William Demarest, both senior counsel at Kansas City-based law firm Husch Blackwell, proposed to the conference a legislative solution to the problem of getting high-voltage interstate transmission lines built.

The pair’s proposal would essentially give FERC jurisdiction over siting interstate transmission projects, similar to how the Natural Gas Act gave the commission siting approval over gas projects, but with numerous caveats and exceptions that they said would preserve some state authority. Crucially, only projects that have facilities in multiple states would be subject to FERC approval. Intrastate transmission projects, unlike intrastate gas pipelines, would remain solely under the purview of the states.

Hoecker, a former FERC chairman, said demand for renewable resources is growing as states increase their portfolio targets. Currently, transmission developers must get approval from a “multiplicity” of regulatory agencies in each state their projects pass through, he said. But “if the momentum picks up for interregional and multistate forms of transmission, I think there’ll be a growing drumbeat to somehow limit state authority in this area.”

The desire to access cleaner generation will be come a very powerful force in the transmission industry, Hoecker predicted. But without a good policy, “you could have states essentially getting steamrolled.”

Demarest elaborated on that point, noting his years working for Rep. John Dingell (D-Mich.). When members of Congress “get on a course, they tend to take political, rather than economic … solutions. They are frequently looking for a solution, and it need not be the best solution, because they delude themselves into believing that they can come back and address it and adjust it and fix it, which they never or rarely do.” State regulators and industry need to find a solution before Congress imposes something they don’t like, he said.

Under their plan, transmission rates for interstate service would be regulated by FERC, but any intrastate service rates would be regulated by each state the project serves. It also would not eliminate, nor allow FERC to eliminate, any state rights of first refusal for incumbent utilities to build intrastate projects. These projects would also not be subject to an “affecting commerce” standard, even though they’re still part of interstate commerce.

RTOs would continue their role as planners, but RTO sponsorship would not be necessary. “RTOs, at least in my view, are political critters, often captive to certain stakeholders,” Demarest said.

Order 841’s Impact on New York

New York is a very desirable market for the energy storage industry, but NYISO’s proposed compliance with FERC Order 841 is somewhat concerning, speakers said during a panel on the order’s implementation.

“When we think about what drives the business case for storage … by and large it is the need for capacity,” said Ray Hohenstein, market applications director for storage developer Fluence. Peaking plants are retiring at a faster rate because of the state’s increasing emissions targets. “New York is a state where if they get FERC 841 right, there could be a lot of energy storage that is making money.”

The state’s Public Service Commission has set a goal of 3 GW by 2030, with an interim target of 1.5 GW by 2025.

In its Order 841 compliance filing, NYISO said it would offer four modes for storage resources to participate: ISO-committed fixed, ISO-committed flexible, self-committed fixed and self-committed flexible. In the ISO-committed modes, suppliers would leave it up to NYISO to determine the most optimal dispatch times for their resources.

Last month, the Energy Storage Association filed responses to the grid operators’ compliance filings. With NYISO, the group focused on what it called “rules that bias against self-management of state of charge.”

Steve Wemple of Consolidated Edison, however, had an optimistic view on NYISO managing resources’ state of charge. The ISO would “look at the beginning charge level and look forward and try to find the right pairs of charging and discharging to meet the bidder’s economic desire … so I think that’s very positive.”

Hohenstein agreed. “I think state-of-charge management is one of the keys to unlocking participation in wholesale markets in general. It actually is a really great development to have the ability to … define your beginning and end-of-hour state of charge to ensure that you are available, for instance, if you have to provide a peak reliability service for part of the day. So it provides a lot more certainty.”

As an example, he said a resource could tell the ISO that it was bidding into the frequency regulation market but it has to be fully charged by 6 p.m.

Melissa Kemp, policy director at Cypress Creek Renewables, was skeptical of that. “I think if it were something that nuanced, we would not have a problem with it. My understanding of what they filed is that it’s not that nuanced, and that it’s more ‘We need to control what you’re doing here’ and that there’s a lot of concern from a lot of stakeholders in the ISO process [who] would like the option to select the ISO to control … but that just simply turning over the ability to control the asset to the ISO is a great concern and kind of a nonstarter.”

The ‘Weakest Link’ in Cybersecurity

A panel on cybersecurity focused on figuring out the most effective practices, which speakers said don’t apply to every utility in the country.

Among the panelists was Iowa Utilities Board Member, and president of the National Association of Regulatory Utility Commissioners, Nick Wagner, who said criminal or hostile foreign hackers are probably not interested in taking down a rural, municipal cooperative in his state.

When asked about NERC critical infrastructure protection standards, Wagner said, “I think those are important beginning points. I don’t necessarily [think] they should be a hard-and-fast rule that everybody should follow. One of the nice things about … our grid today is a conglomerate of very different systems, which in itself is inherently secure. So if a person gets in a system of one utility, that doesn’t necessarily mean that they’ll be able to get into every system. …

“Government does not move at the speed of industry. And it certainly does not move at the speed of hackers. So we will, from a standards standpoint, always be behind. And we want our utilities and our industry and our suppliers to move faster than that and be able to keep up with the threats that are out there,” he said.

Instead, Wagner said, industry needs to focus on training employees to recognize hacking attempts. “People are the weakest link,” he said. “Whether we like to admit it or not, we are the weakest link. … I’ve gotten into the habit of, when I get an email from my family, I call them up and say, ‘Did you send this email?’ Because that’s how sophisticated these hackers are getting.”

Pennsylvania Public Utility Commission Chair Gladys Brown said that applies to state regulatory agencies as well. Agencies “have a wealth of information” that hackers would love to get their hands on, she said. Brown said that despite the robust training NARUC directs, even she has fallen for a phishing attempt, when she responded to an email from someone she thought was a state cabinet secretary. (Thankfully there was no link in the email to click.)

As part of the Electric Power Research Institute’s training, the organization sends out its own phishing emails to test its employees, said Ralph King, cybersecurity program manager. And “if you actually click on a phishing email, you get to sit down with someone pretty high up in the company.”

But King also warned that one utility company he worked with went too far in its training. “They had to back it off because all the employees, anything external, they deleted. And so they were missing a lot of emails.”

King also said that many cyber experts think “the biggest threat in the next five years are insider threats. These could be malicious; they could be mistakes.” Noticing unusual employee behavior — logging into a system in the middle of the night, logging into systems they’re unauthorized to access, etc. — will be key to preventing disruptions. He told the story of another company he worked with that had an employee displaying “very odd behavior. And by looking for these things, we actually uncovered a serious health problem that they didn’t know about. So it’s not always malicious; it could be other things. But regardless of what it is, you want to be able to identify it.”

“It may not impact the grid or the system overall, but it can certainly impact you as individuals and be a real pain to have to deal with some of that stuff,” Wagner said.

March 12, 2019

AWEA Balks at PJM Plan on Wind, Solar Capacity

By Christen Smith

VALLEY FORGE, Pa. — The American Wind Energy Association on Thursday said that PJM’s proposal to change how wind and solar capacity values are calculated does not account for the technologies’ performance improvements over the last decade.

After a year of stakeholder discussions, PJM staff will ask the Planning Committee in April to endorse calculations based on effective load-carrying capability (ELCC), which measures the additional load that a group of generators can supply without a reduction in reliability. Jerry Bell, of PJM’s resource adequacy department, presented the Manual 21 changes during the March 7 PC meeting.

PJM’s five-step process for delivery year 2022/23 begins with an average of the ELCCs for each year since 2012/13. The RTO determined that the composite ELCC is 4,181 MW, 21% of the 19,910 MW of nameplate wind and solar capacity projected for 2022/23.

After calculating the ELCC’s for the two generation types separately, PJM then prorated the shares between wind and solar, resulting in capacity factors of 12.3% and 45.1%, respectively. (See “PJM Pushes Change in Wind, Solar Capacity Measurements,” PJM PC/TEAC Briefs: Feb. 7, 2019.)

PJM would assign the ELCCs to existing individual units based on their output during the top 10 daily peak load hours in the 10 most recent delivery years. Future units will get the class average credit unless they request a project-specific calculation.

PJM is proposing to change its capacity calculation for wind and solar resources. In step 1 of the plan, the RTO determined that the composite effective load-carrying capability (ELCC) is 4,181 MW, 21% of the 19,910 MW of nameplate capacity projected for 2022/23. | *PJM*

AWEA Proposals

Travis Stewart, Gabel Associates | © *RTO Insider*

Representing AWEA, Gabel Associates’ Travis Stewart told the PC that the RTO’s proposal understates the current fleet’s capacity value by giving equal weight to all years in the sample.

Stewart said federal data shows wind capacity factors increased from 30.2% to 42.5% between 2009 and 2016, while solar’s capacity factors increased from 20.8% to 26.8% between 2010 and 2016. PJM’s equal weighting ignores the fact that older, less productive projects represent a small share of the current fleet, AWEA says.

“When PJM attaches an ELCC average to the entire renewable generation fleet, it fails to account for the individual generator’s share,” Stewart said.

The association proposed two options for remedying its concerns:

Option 1: Find the average ELCC for each renewable project vintage across all historical years, and then calculate the ELCC for the current fleet by weighting according to each vintage’s share of the current fleet.
Option 2: To account for Option 1’s potential to mask the underlying renewable performance trend, AWEA proposes building a larger dataset by combining each year’s renewable output profile with corresponding load patterns to calculate an average ELCC. The trendline of ELCC change across years could then be used to weight PJM’s results under its current method to recreate what ELCC performance in prior years would have been with the current fleet.

Patricio Rocha Garrido, PJM | © *RTO Insider*

Patricio Rocha Garrido, of PJM’s resource adequacy department, said staff have “some issues” with AWEA’s second option.

“We want to capture the relationship between wind output and load. … Once you start mixing outputs from one year with load shapes from another year, then that relationship gets totally missed,” he said. “You achieve your goal of increasing sample size, but you totally lose that correlation.”

Next Steps

PJM will present a first read of the manual changes at the March 21 Markets and Reliability Committee meeting before seeking an endorsement in April. The discussion will likely rehash stakeholder concerns over the handling of capacity interconnection rights (CIRs). (See related story, Showdown Set on PJM Must-offer Exceptions.)

“We purchased a lot of these CIRs through upgrades. … [PJM is] making a change here; this is not us retiring units,” said John Brodbeck of EDP Renewables. “This is not the good Lord knocking a whole bunch of towers down. This is a decision to rerate units by PJM and that has a different impact than anything else. We don’t like to see our assets taken away.”

John Brodbeck, EDP Renewables | © *RTO Insider*

PJM’s ELCC formula represents a shift in thinking for the RTO, which had been pushing an alternative method using average values. The new methodology is more representative of the incremental value of adding a new unit to the existing fleet, PJM’s Tom Falin said in February.

The Manual 21 changes include a new section devoted to obtaining, maintaining or losing CIRs, as well as sections devoted to installed capacity calculations and testing requirements.

New rules on testing within temperature bounds will take effect June 1 with rules on simultaneous testing and the ELCC effective for delivery year 2022/23. Wind and solar units losing CIRs would be notified before Jan. 1, 2025.

Notably, the testing window for generators remains June 1 through Aug. 31 after stakeholders expressed concerns over an earlier proposal from PJM to instead start in July. (See “Skepticism of Gen Capability Changes Continues,” PJM Operating Committee Briefs: June 5, 2018.)

PJM wants MRC endorsement by the April meeting so that unforced capacity (UCAP) values for wind and solar can be posted by May 1 for use in the 2022/23 Base Residual Auction in August. They would not affect UCAP values from prior auctions.

March 12, 2019

MISO Prototyping Short-term Reserve Product

By Amanda Durish Cook

CARMEL, Ind. — MISO will prototype its proposed short-term reserve product to demonstrate cost and benefits to its members.

The move comes in part at the behest of stakeholders, who want more information on the availability of resources that might provide the reserves; the cost and reliability impacts of a reserve product; and how the product would interact with out-of-market commitments, according to MISO Market Design Adviser Bill Peters.

MISO has said it hopes to roll out the product in mid-2021, supported by its soon-to-be-replaced market platform. (See New MISO Platform Headed to the Cloud.)

The product would be designed to furnish capacity within 30 minutes. The RTO has said it will be especially helpful in MISO South, which has less than 500 MW of offline capacity available within that time frame.

However, Robert Francis, speaking on behalf of the Entergy Operating Companies, questioned whether MISO South’s load pockets even have an adequate number of offline resources to support the 30-minute response time.

“One concern is that there may not be sufficient online and offline resources in the load pockets to enable the proposed product to work as intended,” Francis said in comments to MISO. “Of the load pocket units that are typically online during periods of system stress, are these units historically dispatched at levels that they would lend themselves to the [reserve] product?”

Peters said the reserve product will better compensate available resources while “incenting new capability for offline response.” He said there won’t be a minimum target amount of such reserves.

MISO Director of Market Design Kevin Vannoy said the short-term reserves would differentiate themselves from the current contingency reserves by addressing either an excess of flow on the regional dispatch transfer constraint or restoring normal operating conditions in a load pocket following the loss of a generator sooner to avoid violations of contracts and reliability standards.

“This is a method of making sure we’re able to replenish contingency reserves following a contingency. To date, we’ve been flush, but we’re finding” that reserves are thinning, Vannoy said. He added that the short-term reserve’s price signal will attract more generation willing to furnish reserves.

MISO has published a conceptual design of short-term operating reserves where online resources and offline resources can either register as a supplier or provide availability through hourly offers in the day-ahead and real-time markets. It plans to clear the resources according to opportunity costs, offer prices and a demand curve when insufficient amounts of the reserve exist.

Restoration Energy, Uninstructed Deviations and Tx Settlements

MISO plans to form a task team later this month to begin discussions on how it should price restoration energy — energy delivered to restore the system in the event of the real-time market ceasing to function. The RTO and stakeholders revived the idea of a plan to compensate restoration energy last year. (See Old Analysis Could Guide MISO Restoration Pricing Effort.)

It will also begin holding weekly conference calls Thursday to answer questions about its new uninstructed deviation threshold. The new threshold calculates a generator’s uninstructed deviation with a tolerance based on the minimum of five times the real-time ramp rate or 12% from the average set point instructions. Generators in MISO are currently flagged after they deviate by more than 8% from dispatch signals over four consecutive intervals. (See MISO Plans for New Uninstructed Deviation Rules.)

Lastly, MISO has delayed the introduction of its new transmission settlements system until spring. The new system was slated to go live March 1, but the RTO decided it required more test runs before rollout.

John Weissenborn said MISO decided to delay the new system “to allow testing and validation from market participants.” He said it will schedule a follow-up conference call in the middle of March to evaluate testing progress and discuss implementation.