FERC’s Glick Navigates Political Dynamic

By Tom Kleckner

HOUSTON — The FERC that Richard Glick joined as a commissioner in November 2017 was nothing like the “sleepy agency” he came to know during his many years as a D.C. insider.

“For the most part, it’s been a nonpartisan agency. The vast majority of orders have gone out on non-party-line votes,” Glick said in keynoting the 18th Annual Gas and Power Institute last week near the heart of the nation’s energy industry.

“That’s starting to change, for a variety of reasons,” he said. “With technology changes, these issues are becoming much more contentious. The more traditional technologies are clearly fighting to protect their turf, and the newer technologies are fighting to get a part of that. That’s posed some issues for us.”

But the greater issue is the political divide, said Glick, the lone Democrat among the three men sitting on the commission.

“Some of atmosphere at FERC is a little more tense than it has been, in large part because of what’s going on in Washington, D.C., in general,” he said. “It’s a different atmosphere than before, and FERC is reflective of that.”

FERC Commissioner Richard Glick | © *RTO Insider*

Glick said he has dissented a “lot more” than he thought he would have when he joined FERC. Most recently, he argued that the commission’s recent move to adopt proposed revisions to how it administers the Public Utility Regulatory Policies Act of 1978 would essentially “gut” a law that has spurred renewable energy growth. (See FERC to Reshape PURPA Rules.)

Glick has often been the only commissioner taking a stand against approving gas pipelines and LNG projects. He has repeatedly expressed concerns about the lack of greenhouse gas considerations in commission rulings and now has begun charges that FERC is “scrubbing” references to climate change from its orders. He noted that boilerplate language encouraging developers to take GHG emissions into consideration has been removed from recent orders.

“All of a sudden, that’s been taken out of the orders,” he said. “The commission is choosing to stick its head in the sand and not consider greenhouse gas emissions, and that’s problematic.”

“Glick is the lone voice in the wilderness,” Tom Hirsch, a D.C.-based lawyer with Norton Rose Fulbright, told attendees.

“My beef with the majority, and what FERC has been doing for a number of years, is relying on precedent agreement, and not even arguing it,” Glick said. “We’ve been called a ‘rubber stamp’ for the pipelines. That’s not always true … but I don’t think we’ve done our job [in determining a project’s need] as we should.”

Compounding Glick’s frustration is the turmoil surrounding FERC itself. The commission, which struggled to reach a quorum in 2017 following the change in administrations, is now back to three members following Cheryl LaFleur’s departure in August. (See FERC Heaps Praise on Departing LaFleur.)

Normally, the administration would nominate a candidate from each party to fill the two vacant seats, maintaining a 3-2 split favoring the party holding the White House. “That’s been the tradition,” Glick said.

However, the talk in D.C. is that FERC General Counsel James Danly will be nominated for the Republican position and the Democratic seat would be left open. Asked if he was familiar with the rumor, Glick said, “I hear the same things you do. I will guarantee you the White House did not call me up and ask my opinion.

“Even if you change one commissioner for another, it takes a while to get used to each other’s rhythms,” Glick said. “There’s a lack of stability. I’m very hopeful that we will get another commissioner [soon].”

FERC Chairman Neil Chatterjee declined to comment on Danly during an earlier September visit to Houston.

Compounding matters is a recent determination by FERC’s designated agency ethics official (DAEO) that Glick should continue to recuse himself from proceedings related to his former employer Iberdrola USA (now Avangrid), again making quorum an issue, particularly in a key proceeding related to PJM’s capacity market. (See Glick Recusal May Mean No MOPR Ruling Before December.) Glick said he initially understood the two-year recusal would have expired two years after he left Avangrid in February 2016. In reality, he was later told, the clock started ticking when his term began in November 2017.

“I think he made an honest mistake,” Glick said of the DAEO’s first ruling.

The same ethics office has advised Commissioner Bernard McNamee that he doesn’t have to recuse himself from the commission’s grid resilience proceeding, unless it “closely resembles” the debate over the coal and nuclear subsidies he helped write at the Department of Energy.

Still, Glick soldiers on. While appearing reserved at first glance, he seems comfortable speaking out while manifesting a wry sense of humor.

When he mentioned he disagreed with a fellow commissioner, a reporter tried to pry Glick into naming names. “I think I disagree with both of my colleagues. I like them, but we disagree on policy.”

ERCOT Monitor: August ‘High Excitement’ for RT ‘Geeks’

Also speaking at the conference, Potomac Economics’ Beth Garza, executive director of ERCOT’s Independent Market Monitor, described the Texas grid operator’s ability to meet customer demand during scarcity conditions this August as “high excitement for those of us who are real-time energy market geeks.”

ERCOT called its first energy emergency alerts (EEAs) in five years this summer and relied on emergency response service and DC tie imports to meet record-breaking demand. However, the two EEAs weren’t called on days when load reached record levels, but during days when West Texas winds died down before the late afternoon peak. (See “ERCOT CEO Briefs Commission on Summer Performance,” Texas PUC Briefs: Aug. 29, 2019.)

“In ERCOT, high loads used to be driven by high temperatures, but it’s no longer that,” Garza said. “Now, it’s, ‘Is it going to be hot? Is it going to be still? Now, the third piece is, ‘Is it going to be cloudy?’ Those are the drivers for pricing and price outcomes.”

Prices briefly hit $9,000/MWh during both EEAs. “Prices should be reflective of the conditions you are in,” Garza said. “If you are in scarce conditions where you may have to curtail load, the price should be high.”

Geek that she may be, Garza noted that ERCOT’s real-time energy prices averaged $50.70/MWh through August, a 40% increase year-to-date over 2018 ($36.20/MWh). This despite a 15% decrease in natural gas prices so far in 2019.

But, Garza asked, is that enough for people to “plunk their money down and build a power plant” to take advantage of scarcity prices? She would only point to the 2020 summer’s forward on-peak prices, which spiked to more than $400/MWh in August but have since dropped to $250/MWh, and let her audience decide.

Glick offered his own positive outlook on the ERCOT market.

“Texas has a very unique market,” he said. “It’s an energy-only market, yeah, and prices spike during certain hours in the summer, but contrary to predictions, the lights didn’t go out.”

Questions over Capacity, Traditional Markets

Glick also shared his insight on capacity markets, which he said are one of the biggest policy issues before FERC. He suggested participants are losing faith in the markets as they attempt to integrate renewable generation.

“Capacity markets procure a lot of reserves that aren’t needed, and that costs a lot of money,” he said. “Generators are asking us to intervene. … To me, we’re spending a lot of time arguing about whether we need to subsidize nuclear or coal. To me, that’s an argument from a long time ago. What we need, with intermittent resources, is a lot of flexibility on the gird. We should incentivize and reward flexibility.”

Tim Wang, a director with Filsinger Energy Partners, questioned whether energy markets will even remain viable in the future.

“Energy markets are based on 1990s technology and fuel costs. That is all changing,” he said.

Wang said energy storage costs are dropping as dramatically as wind and solar costs, further reducing marginal costs.

“In the future, with 100% renewable energy markets, the marginal costs could be zero. There are no coal or gas heat rates. All that is gone … so what does the future look like? Will the markets still be there?”

September 29, 2019

NYISO Management Committee Briefs: Sept. 25, 2019

The New York Control Area summer peak load of 30,397 MW on July 20 fell below the 50/50 projection for the sixth consecutive summer, Operations Vice President Wes Yeomans told the Management Committee on Wednesday.

The summer 2019 50/50 forecast was 32,382 MW, while actual peak load last summer was 31,861 MW.

“Things were relatively easy for the NYISO this summer, operationally speaking, with two heat waves, on July 18-21 and July 29-30,” Yeomans said. He noted there were four days with peak loads over 30,000 MW.

“We did go into this summer knowing this was the last summer we’d have six nuclear plants,” he said, referring to next spring’s phased shutdown of the first of the two reactors at Indian Point, with the second unit to be decommissioned in 2021.

Yeomans noted that NYISO termed the July 29-30 period as “hot weather operations” on his slides, as the heat has to last three days to be classified a heat wave.

NYISO recorded the all-time peak for a Sunday on July 21 at 30,339 MW and met reliability criteria with surplus operating margins, with no emergency activations and no need for statewide supplemental capacity commitments, he said.

“Prior to July 18, transmission owners rescheduled a lot of their transmission work in anticipation of the heat wave,” Yeomans said. “And it was hot, with heat indexes as high as 110 degrees [Fahrenheit] over the weekend [July 18-21].”

Daily mean temperatures were above the 20-year average in July, near average in June and August, and below average in May, with Albany posting 12 days with highs above 90 F.

Staff Transitions

CEO Rich Dewey mentioned a couple of “public service announcements,” saying the NYISO Board of Directors’ search is underway to fill the upcoming vacancy of Robert Hiney, who is set to leave in April 2020.

The board also approved the appointment of Robb Pike as vice president of market operations, Dewey said. Pike worked for NYISO’s legacy organization, the New York Power Pool, and moved to the ISO at its inception in 1999.

Parallel Testing of EMS/BMS

NYISO hopes to go live with a new energy management system (EMS) and business management system (BMS) at the end of October and is operating a parallel testing phase through Oct. 7.

“That application is receiving all the telemetry that our legacy system is receiving and is doing everything but sending dispatch signals,” Chief Information Officer Doug Chapman said.

The testing is an important phase, with EMS/BMS “running pretty well” except for a few issues that need to be resolved with vendor ABB before going live in October, he said.

If NYISO decides to proceed with the new EMS/BMS, it will move into parallel operations for two weeks in mid-October, double-staffing the control room, Chapman said.

The cutover date is currently targeted for Oct. 22. NYISO’s last opportunity to switch to EMS/BMS in 2019 will be Oct. 31, which is the latest NYISO can cut over to the new system and still issue a necessary System and Organization Controls report to stakeholders by the deadline of Jan. 15, 2020.

“If we miss, the next opportunity to go live is March 1, and that delay has cascading impacts to our 2020 plans,” Chapman said.

The ISO also is replacing the tool used to model the electric system, he said.

Draft 2020 Budget

Alan Ackerman, of Customized Energy Solutions and chair of the Budget and Priorities Working Group, delivered budget highlights.

NYISO’s draft 2020 budget totals $168 million allocated across a forecast of 154.3 million MWh, for a Rate Schedule 1 charge of $1.089/MWh. Comparatively, the 2019 budget was $168.2 million allocated across 157.1 million MWh for a Rate Schedule 1 charge of $1.071/MWh.

The draft budget would represent a 0.12% decrease in revenue requirement from 2019 and a 1.78% decrease in projected megawatt-hours, for an overall Rate Schedule 1 increase of 1.66%.

Cost avoidance is the main strategy behind keeping the ISO’s budget flat for the fourth year in a row, according to the presentation, with salaries and benefits increasing $500,000 from this year, but employee health insurance plan changes effective for the 2020 plan year projected to avoid additional ISO cost increases of $400,000.

The board will review the draft budget in October ahead of an MC vote on it at the end of the month. The budget will then go to the board for approval at its Nov. 19 meeting.

— Michael Kuser

September 29, 2019April 16, 2025

Bonneville Power Signs Agreement with CAISO EIM

By Hudson Sangree

The Bonneville Power Administration signed an implementation agreement with CAISO’s Western Energy Imbalance Market on Thursday, positioning a vast region of the Pacific Northwest, with its powerful hydroelectric dams and thousands of miles of transmission lines, to begin participating in the ISO’s real-time market in 2022.

“We see BPA’s participation in the Western EIM as the natural next step in a collaborative partnership that began many years ago to optimize transmission connections and boost reliability throughout the West,” CAISO CEO Steve Berberich said in a statement. “BPA will provide exceptional benefits to the real-time energy market, as it leverages its robust and regionally strategic transmission system and energy resources.”

BPA would be the largest transmission owner and hydroelectric provider in the EIM. The federal power marketing administration owns and operates three-quarters of the high-voltage transmission lines in the Pacific Northwest, totaling about 15,000 circuit-miles. Its footprint occupies an area larger than the size of France, encompassing the sprawling drainage areas of the Columbia and Snake rivers.

The agency’s assets include 31 hydroelectric projects, such as the 7,079-MW Grand Coulee Dam and the 2,614-MW Chief Joseph Dam. It supplies electricity to 143 electric utilities that serve millions of customers in Washington, Oregon, Idaho, Montana, California, Nevada, Utah and Wyoming.

The Bonneville Power Administration’s service area stretches across a vast area of the Pacific Northwest. | BPA

The move also boosts CAISO’s EIM in competition with WAPA, Basin, Tri-State Sign up with SPP EIS.)

While the implementation agreement is nonbinding, it commits BPA to paying a $1.8 million nonrefundable implementation fee, the first payment of up to $35 million in estimated start-up costs. BPA will not issue its final record of decision on becoming a member until late 2021, just months before it plans to join in March 2022. (See BPA Marches Toward EIM Membership.)

“This milestone was made possible by the collaboration and broad participation of our customers and constituents in the Northwest,” BPA Administrator Elliot Mainzer said in a statement. “We’ve also benefited from a strong partnership with the CAISO that allowed us to carefully explore the value of the EIM for BPA and its customers, while addressing issues important to the region.”

BPA said the EIM will allow it to more efficiently market its hydropower and manage transmission usage and congestion. The agency has touted the ability to use the EIM as a “non-wires” solution to address congestion and avoid new transmission builds while helping to identify areas of needed investment.

“Selling surplus energy and capacity in the Western markets is essential to keeping Bonneville’s rates low,” the agency said on its website. “BPA must adapt its business model as these markets change. Our analysis shows that joining the Western Energy Imbalance Market is one potential method to achieve this outcome.”

In June, BPA kicked off a monthlong public comment process in hopes of signing an implementation agreement with the EIM in September. During a July meeting at BPA headquarters, BPA “preference” customers concerned about their inability to trade in the EIM’s intra-hour market probed agency officials about short-term opportunities to purchase surplus hydropower before it’s offered into the EIM. (See Customers Probe BPA on EIM Impact.) While those concerns remain unresolved, no BPA customers apparently opposed joining the EIM.

“We got 100% support for signing that agreement,” Mainzer said at the Northwest & Intermountain Power Producers Coalition annual meeting in Union, Wash., on Sept. 9.

CAISO is evaluating adding an extended day-ahead market (EDAM) to the real-time EIM to increase its usefulness as a regional marketplace, and the BPA administrator said he believed the EDAM is needed to help move BPA’s hydropower and other renewable resources across the West.

“It’s not going be enough to sell all this stuff on a five-minute market,” Mainzer said.

CAISO says its five-minute market has saved participants more than $736 million in the five years since it started.

The Balancing Area of Northern California (BANC) and the Western Area Power Administration recently said they will sign an implementation agreement with CAISO that would allow WAPA’s Sierra Nevada region and BANC members Modesto Irrigation District, Redding Electric Utility and Roseville Electric Utility to begin trading in the EIM in April 2021. The decision does not affect any other WAPA regions.

WAPA SN would be the first PMA to participate, potentially followed by BPA. The agreement represents the second phase of BANC’s approach to incorporating its members into the EIM. Sacramento Municipal Utility District entered the market in April. (See SMUD Goes Live in Western EIM.)

Other current Western EIM participants include CAISO, PacifiCorp, NV Energy, Arizona Public Service, Puget Sound Energy, Portland General Electric, Idaho Power, Powerex and BANC (Phase 1). The Western EIM is slated to expand with the participation of Salt River Project and Seattle City Light in 2020; Los Angeles Department of Water and Power, NorthWestern Energy, Turlock Irrigation District, Public Service Company of New Mexico and BANC (Phase 2) in 2021; and Tucson Electric Power, Avista and Tacoma Power in 2022.

September 29, 2019

RTOs Gather to Discuss Real-time Co-optimization

By Tom Kleckner

AUSTIN, Texas — Normally, Texas’ electricity industry points to ERCOT’s energy-only — and deregulated — market as a model for the rest of the country to follow.

Last week, however, ERCOT staffers and stakeholders gathered to hear advice from the RTOs that have already implemented real-time co-optimization (RTC) in their markets. MISO, PJM and SPP staff gave high-level overviews of their forward markets and lessons learned from their experience with the practice.

The Texas grid operator is just months into a multiyear effort to improve its market by adding RTC, a market tool that procures both energy and ancillary services (AS) every five minutes to find the most cost-effective solution for both requirements.

Gary Cate, SPP’s manager of market design, told members of the Real-Time Co-optimization Task Force gathered at ERCOT’s headquarters that his RTO’s implementation of RTC was “clean once we went there” with its integrated marketplace in 2014.

“[Our] real-time market doesn’t have performance issues,” Cate said, rapping the podium in front of him. “The day-ahead market did have commitment issues initially, with reg[ulation] up and reg down as separate products … but we didn’t have a lot of issues from a co-optimization perspective. We did co-optimization after multiple RTOs did it, so we kind of learned from their missteps.”

MISO added RTC to its market in 2009 at a cost of $75 million. Jeff Bladen, MISO’s executive director of digital strategy, said the tool provides an annual return of at least $60 million through a more efficient commitment and dispatch of energy and reserves.

“Our fundamental belief is co-optimization for all our products is necessary to be as efficient as our customers expect us to be. The market is now compensating for availability and flexibility, not just energy,” Bladen said. He noted the RTO plans to file a request with FERC to offer a short-term, 30-minute spinning reserve product.

MISO suggested ERCOT pay attention to ramp sharing, where energy and reserves share the same ramp capability. Bladen said the RTO observed frequent price spikes during parallel operations, which increased reliability risks because insufficient reserves were cleared. With ramp sharing, he said, reserve requirements are scaled up to account for the sharing.

ERCOT’s Matt Mereness, who chairs the RTCTF, said he found the information beneficial for the team’s current principle design phase, including the need to focus on “market education and technical details.”

MISO, PJM and SPP operate capacity markets, designed to ensure reliability by requiring suppliers to have enough resources to meet customer demand and a reserve amount. ERCOT’s energy-only market pays generators only when they provide power day-to-day, relying on scarcity pricing to incent additional generation.

‘Grappling’ with RTC

Reliant Energy’s Bill Barnes said RTC will work well in ERCOT’s market, pointing to the construction of demand curves as being the important difference.

“The energy-only market relies on the ASDC [ancillary services demand curve] to set scarcity prices to drive operational and investment decisions,” he told RTO Insider. “The must-offer requirement in the other markets is due to resource adequacy requirements that don’t exist in ERCOT.”

Resmi Surendran, senior director of regulatory policy for Shell Energy, agreed with Barnes. She said the AS demand curve’s design and the restrictions placed on AS offers could significantly affect the reserve margins the market can sustain.

Capacity markets expect must-offers from resources with capacity obligations, “which seems reasonable as they are paid to be available,” she said. She pointed out SPP and MISO were “very explicit” during their discussion that AS must-offers and near-zero offers for the services shouldn’t be expected if the RTO values the AS product.

“They don’t require resources that don’t have capacity obligations to offer into the AS market, and their offer caps for these AS products are high,” Surendran said. “AS markets are not a key revenue stream for the generators in those markets. In ERCOT, that is not the case. … How we design it could have an impact on the new type and amount of investments the market will attract.”

Shams Siddiqi, Crescent Power | © *RTO Insider*

Shams Siddiqi, who has been involved in much of ERCOT’s market design and is now president of consulting firm Crescent Power, has freely offered his expertise to the RTC task force. He said the tool will be more efficient in ERCOT’s nodal market, where all AS-capable resources are required to offer or let the system create proxy offers.

ERCOT’s must-offer requirement and reduced risk to selling AS under co-optimization will likely reduce AS prices, he said.

“Even if [ERCOT’s] proxy AS offers are set to [$0], when the resource does not submit an offer [under RTC], it’s unlikely that AS clearing prices will be $0, as AS clearing prices always take into account opportunity cost,” Siddiqi said. “Unlike what’s being proposed by ERCOT, other ISOs substitute higher-value AS capacity for lower-value AS capacity and maintain the substituted AS capacity as the higher-value service. This … results in higher level of reliability, making the ASDC continuous so that additional higher-value products always have value greater than or equal to lower-value AS service, and ensures higher or equal clearing price for higher-value AS compared to lower-value AS.”

Barnes said stakeholders are “grappling” with how to set AS proxy offers for RTC. “The pricing of AS in other markets with RTC helps inform our decision,” he said.

TAC Endorses 2 More Key Principles

The RTCTF also received endorsement last week of two additional key principles (KPs) from ERCOT’s Technical Advisory Committee. (See related story, ERCOT Technical Advisory Committee Briefs: Sept. 25, 2019.)

The latest KPs are:

KP 1.1: Replaces the operating reserve demand curve’s adders with ASDCs to determine market-clearing capacity prices for AS products, while continuing to adjust for ERCOT’s defined out-of-market actions to maintain reliability.
KP 1.2: Evaluates the values of and interaction between the systemwide offer cap, value of lost load and power balance penalty price as part of RTC’s implementation. The principle also sets parameters for the values.

The KPs will be sent to the ERCOT Board of Directors, which will now “consider,” rather than “approve,” the principles as a result of a tweak to the group’s scope. Following the KPs’ consideration, staff will draft and sponsor the necessary revision requests, according to the protocols.

The task force plans to consider 19 more KPs during its Oct. 9 meeting.

The TAC also reaffirmed Bryan Sams as the task force’s vice chair. Sams recently left Lone Star Transmission for a position with Calpine as director of government and regulatory affairs.

September 29, 2019

More MISO Members Join Call for Tx Planning Change

By Amanda Durish Cook

CARMEL, Ind. — A growing number of stakeholders are prodding MISO to create a task team to improve transmission planning assumptions and devise ways to prevent new generation projects from becoming responsible for most transmission development.

Multiple stakeholders at a Planning Advisory Committee meeting Wednesday said MISO’s lagging renewable forecasts and increasingly pricey network upgrades for queue projects merit examination by a new task team.

Clean Grid Alliance’s Natalie McIntire said MISO’s 15-year futures — even the accelerated fleet change scenario — project smaller renewable growth than indicated by projects that have already signed interconnection agreements in the queue. Projects set to come online in the next few years eclipse all futures expectations, she said.

Representatives from the Organization of MISO States and CGA appeared before the RTO’s Board of Directors in mid-September to warn about the increasing trend of otherwise economically viable renewable projects exiting the queue because of prohibitively expensive network upgrades. (See MISO Readies MTEP 19, Debates Futures Change.)

MISO has promised to evaluate special, targeted economic planning studies in its 2020 Transmission Expansion Plan (MTEP 20), while postponing a futures overhaul until the 2021 cycle. (See MISO Halts Futures Work for 2020, Plans 2021 Rebuild.) During the PAC meeting, MISO project manager Sandy Boegeman asked stakeholders for suggestions on the targeted studies.

Several members have said the RTO cannot afford to wait another year before recasting its future scenarios. MISO will essentially snub transmission projects designed to help facilitate the renewables growth indicated by the interconnection queue, creating a self-fulfilling prophecy, they say.

The accelerated fleet change future should now be considered MISO’s base case future scenario, while the three other futures are “not at all representative of what we might expect,” McIntire said Wednesday. She called for a “better alignment” between planning assumptions and queued generation projects.

McIntire said the Helena-to-Hampton Corners second circuit project should be included in MTEP 19 as a market efficiency project, a contention her organization already put before the board. (See MISO Readies MTEP 19, Debates Futures Change.) The $36.1 million, 345-kV project, originally identified in this year’s Market Congestion Planning Study, was set to solve congestion in southern Minnesota at a 4.22:1 benefit-to-cost ratio, but MISO said the project quickly lost value once forecasted wind generation was removed from the equation.

McIntire said there was “not a very robust stakeholder process” around testing of the project, which should have been subject to more vetting and a PAC review.

She also said network upgrades borne by new generators in the queue “provide benefits well beyond simply interconnecting generators.” She pointed out that the February 2017 definitive planning phase studies showed that the batch of projects needed more than $1.3 billion in upgrades, an average of $1.5 million per megawatt of new generation.

“It is not efficient or cost-effective for MISO to plan the system one interconnection queue at a time,” said McIntire, who issued the first call for a task team to examine network upgrades and transmission planning. She said MISO should also consider creating a new transmission project category that allows for cost sharing between generators and load.

At a special workshop on MTEP futures Thursday, MISO Planning Manager Tony Hunziker said the RTO is developing a strawman proposal on new futures development for stakeholder review at an Oct. 17 workshop.

Hunziker agreed that industry projections are already “outpacing” even MISO’s accelerated fleet change future, which predicts wind and solar will account for 29% of capacity by 2033. He said there are signs that wind and solar generation will make up more than 30% of the generation mix by that time.

CGA’s Sean Brady noted that some MISO states are targeting a 40 to 50% renewables mix by the mid-2030s.

Veriquest Group’s David Harlan said MISO’s reliance on planning for new generation based on a reliability-focused planning reserve margin might now be “too narrow” to use in transmission planning. He said MISO should consider that the future generation portfolio will have ramping, reactive power and voltage support needs among others.

Hunziker said MISO could move to a “dynamic” — instead of static — planning reserve margin for transmission planning. Though still undefined by the RTO, a dynamic planning reserve margin could change in out-years based on forecasts. Currently, MISO’s futures ensure its planning reserve margin is met.

Some stakeholders have also suggested MISO create a member survey to better capture its members’ carbon-reduction goals and resource additions and retirements.

MISO is also asking whether it should split its footprint into subsections for planning studies or allow for different input assumptions at the local resource zone level, state level, or the MISO Midwest and South regions. Hunziker said subregional futures would require significantly more work.

September 26, 2019

PJM Suspends Auction Deadlines Pending FERC Action

Storage Changes also in Limbo

By Christen Smith

VALLEY FORGE, Pa. — PJM told its Markets and Reliability Committee on Thursday that all deadlines for upcoming capacity auctions will be suspended pending FERC action on the RTO’s proposed revisions to its capacity market.

The news follows Commissioner Richard Glick’s disclosure that he will recuse himself from any matters involving his former employer, Avangrid, until Nov. 29, after FERC’s designated agency ethics official changed his interpretation of an ethics pledge signed by all presidential appointees under an order from President Trump. Avangrid has filed comments and testimony in the case, and Glick has indicated he won’t seek a waiver. (See Glick Recusal May Mean No MOPR Ruling Before December.)

PJM had anticipated commission action before the end of year, when many deadlines for the 2023/24 Base Residual Auction would come due. (See “Capacity Auction Ruling Anticipated Before 2020,” FERC Halts PJM Capacity Auction.)

“PJM is not going to run forward with any BRA-related deadlines until we receive a FERC order and can establish a timeline from that order,” said Jen Tribulski, the RTO’s associate general counsel. The suspension applies to all future delivery years, though PJM will continue running Incremental Auctions for all previously completed BRAs.

Glick’s recusal also leaves the RTO’s second Order 841 compliance filing (ER19-469) in limbo, said Andrew Levitt, PJM’s senior business solution architect for applied innovation.

Although Avangrid was not a party to PJM’s compliance filing, Levitt said it’s unclear whether Glick will sit out from issuing an order ahead of the filing’s requested Dec. 3 implementation date.

Meanwhile, PJM plans to proceed with the multi-use, load-serving energy storage resource (ESR) settlement provisions approved in docket ER19-462. The pending changes detailed in docket ER19-469 — which deal with real-time and day-ahead market changes and billing related to charging ESRs that take transmission service — will be placed on hold. Instead, PJM will adhere to status quo rules, which allow ESRs to participate in all its markets and will count battery charging as “negative generation” that does not take transmission service.

September 26, 2019

Despite Pushback, MISO Pursuing TO-only SATA

By Amanda Durish Cook

CARMEL, Ind. — MISO plans to file its first storage-as-transmission asset (SATA) ruleset next month, despite complaints from some members that the proposed provisions limit resource ownership to transmission owners.

Speaking at a Sept. 25 Planning Advisory Committee meeting, DTE Energy’s Nick Griffin said he and others still see an “equality” issue with the ownership restriction. Griffin has told MISO’s Board of Directors that if the provision remains in the filing, DTE would file a protest in the docket arguing that similarly situated parties stand to be treated inequitably. (See MISO Firming Up 1st SATA Ruleset.)

Discussion at the PAC meeting quickly waded into murky waters over what it means to be a TO and what constitutes a transmission asset.

Griffin has suggested a compromise in which MISO allows non-TOs to own storage that provides reliability transmission services while simultaneously completing the approximately three-year interconnection queue to allow the asset to become a market-based generator. The resource would initially be classified as a transmission asset, then transition to a market resource.

“We can’t defer transmission unless we have an assurance that the transmission alternative” will be there, MISO Director of Planning Jeff Webb said. “If it’s built and constructed and goes into service — and it can’t participate in the market until it goes through the queue — what if it never goes through the queue? Who pays for that? Where are you going to get your cost recovery?

“That’s the fundamental problem we’re having: What is a transmission asset? This feels like a transmission asset owned by a non-transmission owner,” he said. “I’m really worried about the slippery slope here; it’s a gateway drug. The next question might be, ‘Hey, can I do this with a peaking gas generator?’ … We have to find a place for [SATA] that respects our framework.”

“I think already in this process there’s a lot of gray area between transmission and non-transmission assets [NTAs], and unfortunately, that’s where FERC has left us,” Clean Grid Alliance’s Natalie McIntire said. Part of the gray area stems from MISO not having a particularly clear definition of NTAs, she said.

“The dream I have is we would abolish the term ‘non-transmission alternatives’ and define it for what it is versus what it’s not,” Webb said.

MISO has one SATA project proposed for Wisconsin in this year’s Transmission Expansion Plan (MTEP), making the filing a bit of a race against the clock because the RTO doesn’t yet have cost recovery in place. (See MTEP 19 Could Yield First MISO SATA Project.)

Webb said it’s unlikely that FERC will rule on the SATA rules by the board’s approval of MTEP 19 in December. Because MISO doesn’t want to proceed with an uncertain project, it will likely formally recommend the storage project after the usual December timeline. PAC Chair Cynthia Crane said RTO planning staff can appear before the board at the March 2020 meeting to make a one-off recommendation for a project.

MISO last month began drafting SATA provisions to be included in its business practices manual covering transmission planning processes. The drafts place several mentions of electric storage resources into BPM 20, the existing rules on selecting NTAs in place of transmission projects. The provisions would add an inverter-based reliability analysis and allow the RTO to consider the life cycle, degradation and cost assumptions of storage resources, as well as the impacts on proposed generation in the interconnection queue. The changes would also require SATA operators to develop an operating guide for each asset approved in the MTEP process.

But MISO will now put the proposed BPM edits on hold, pending the outcome of the FERC filing, responding to the complaints of stakeholders who said they were premature. Several members said MISO shouldn’t create BPM provisions before defining a method for evaluating SATA projects.

“The BPM was a vehicle to vet changes,” Webb said, explaining the BPM is subject to revision to align with whatever version of Tariff revisions FERC accepts. He said the minimal BPM edits are simply the “essential features” to implement SATA.

September 26, 2019

Supply Side not Buying ISO-NE’s ICR Numbers

By Rich Heidorn Jr.

NEPOOL’s Reliability Committee on Wednesday rejected ISO-NE’s proposed installed capacity requirement (ICR) calculations, with unanimous opposition from the Generation and Supplier sectors.

Needing a 60% majority to recommend them to the Participants Committee, the ICR values including and excluding Mystic Units 8 and 9 failed with only 49.65% support.

With the Generation and Supplier sectors unanimously opposed and the Transmission and Publicly Owned sectors unanimously in support, the vote hinged on a split in the Alternative Resources sector (8.71% in favor, 11.78% opposed). The End User sector lacked a quorum and was reported 0.98% in favor and 0% opposed.

Excluding Mystic 8 and 9, ISO-NE is proposing a net ICR of 32,495 MW for Forward Capacity Auction 14 (2023/24), a reduction of 1,255 MW from FCA 13.

The committee did approve a 941-MW value for the Hydro-Québec interconnection capability credit (HQICC) for FCA 14 including the capacity associated with Mystic, and a 943-MW HQICC excluding it.

NEPOOL rules prohibit RTO Insider from quoting stakeholders’ comments during the meeting. However, Bruce Anderson, vice president of market and regulatory affairs for the New England Power Generators Association, explained the generators’ objections after the meeting. He said the reduced net ICR from FCA 13 “will undoubtedly put downward pressure on prices if accepted by FERC.

ISO-NE installed capacity requirement — The system demand curve shows an installed capacity requirement (ICR) of 32,495 MW for Forward Capacity Auction 14 (excluding Mystic 8 and 9), a reduction of 1,255 MW from FCA 13. | *ISO-NE*

“NEPGA has raised a number of concerns with how the ISO modified its load forecasting methodology, which drove the decrease in NICR, including that it was done based in part on only a handful of days in summer 2018. We also believe that ISO-NE may not properly recognize that the peak-load hour is moving farther out due to solar penetration, and thus there may be actual less peak load shaving coming from the behind-the-meter solar than is shown in the load forecast,” Anderson said in an email.

“In addition, ISO-NE has changed the load forecast methodology for purposes of calculating demand (the NICR) but not for purposes of calculating the cost of new entry (for which the load forecast is a significant variable). This inconsistent application of the change in load forecast methodology will cause the FCA to price capacity below its economic price.”

Other stakeholders who criticized the RTO’s calculations declined, or did not respond to, requests for comment.

“Developing the installed capacity requirement is a complex calculation involving many factors. The ISO develops the ICR according to national and regional power system reliability standards and requirements,” ISO-NE spokeswoman Marcia Blomberg responded. “For stakeholders, there may be other considerations.”

Opposition in 2018

It is at least the second year in a row that ISO-NE has faced opposition to its ICR calculations.

Last September, the committee approved an ICR value of 34,719 MW without Clear River Unit 1 for FCA 13, with more than 65.% support. But the RTO’s 34,739-MW ICR with Clear River failed with only 50.01% support. In October, the Participants Committee voted likewise on the two values.

In January, FERC approved the 34,719-MW ICR after accepting the termination of Clear River’s capacity supply obligation for 2021/22 (ER19-291).

FERC approved the ICR values over protests from NEPGA, FirstLight Power Resources and the New England States Committee on Electricity (NESCOE).

NESCOE complained that the filing by ISO-NE and NEPOOL failed to justify increasing system reserves to 700 MW from 200 MW, the level it had been at since 1980. NESCOE contended that ISO-NE was trying to justify its ICR value rather than determining the amount needed to support resource adequacy.

FERC defended the 700-MW reserve level as “a matter of engineering judgment.” It noted that the system’s peak load had nearly doubled since 1980 from about 15,000 MW to 28,000 MW today. The single largest contingencies in 1980 were two nuclear units of 800 to 900 MW each. “Today, New England can experience a single credible contingency of up to 2,000 MW associated with the Phase II interconnection with Hydro-Québec and three other large credible contingencies ranging between 1,250 [and] 1,650 MW each,” FERC said.

FirstLight and NEPGA objected that the ICR-related values used in ISO-NE’s ICR study are based on lower outage rates and higher tie benefit assumptions than those used in the RTO’s fuel security study.

The commission said the generators’ request to calculate ICR using the assumptions from the fuel security study would violate the Tariff.

“These two study processes are distinct and seek to achieve different objectives,” the commission said. “While ISO-NE uses the ICR-related values to address an installed capacity problem, it uses the fuel security study to address a different problem: whether capacity procured in the Forward Capacity Market has sufficient fuel necessary to produce energy needed to meet demand and maintain required operating reserves. That is, a region may have sufficient installed capacity but insufficient fuel to produce energy from that capacity.”

FCA 14 vs. 13

The new ICR values show a 1,065-MW reduction in the load forecast from FCA 13, including a 965-MW drop in the gross load forecast and a 105-MW reduction from updated estimates for behind-the-meter PV generation. The load also was affected by changes to the load forecast methodology, including the addition of a second weather variable (cooling degree days), the separation of the July and August peak load model, and the shortening of the historical weather period from 40 to 25 years.

Also reducing the ICR were improvements to system outage rates.

Those reductions were partially offset by a reduction in tie benefits (+70 MW) and the load relief assumed obtainable from implementing a 5% voltage reduction (+150 MW).

Other Action

In other action Wednesday, the Reliability Committee approved a number of projects, including Exelon Generation’s plan to replace the excitation controllers and automatic voltage regulators (AVRs) at Mystic 8 and 9. The company will install ABB UNITROL Static Excitation Systems at each generator to provide excitation current to the exciters and replace the existing AVRs. They are expected to be in service in October.

Members also approved revisions to:

Operating Procedure 19 to allow adjustments to phase-shifting transformers or reactive flow to maintain system reliability.
the reactive capability audit request form to clarify the types of tests that can be selected on the form.
Planning Procedure 10 to delete provisions related to interconnection service adjustments (Sections 7.7 and 7.8), which are being moved to a new section in the Open Access Transmission Tariff. The change won’t take effect until FERC approves the Tariff amendment.
Sections I.2.2 and III.12.6 of the Tariff to allow the inclusion of competitively developed transmission solutions into the FCM network model.

September 26, 2019

MISO Zeroes in on Queue Overhaul Filing

By Amanda Durish Cook

CARMEL, Ind. — MISO will soon take a second crack at getting FERC approval for Tariff revisions intended to thin out and speed up its overflowing generator interconnection queue.

The RTO is targeting a refiling of the rule changes by early October, a few months later than originally anticipated. (See MISO Makes Second Attempt at More Rigorous Queue.)

The commission in March rejected the RTO’s plan to impose more stringent site control requirements and increase milestone payments for interconnection customers, but it agreed the changes would reduce speculative and duplicative projects. (See MISO Promises Refile on Stricter Queue Requirements.)

Speaking Wednesday at a Planning Advisory Committee meeting, Resource Interconnection Planning Manager Neil Shah made clear that the proposal is no longer up for debate. He began his presentation on the plan with an anecdote about a fixed-price, no-haggle experience at a car dealership.

“So, me, in front of you, I feel like that” car salesperson, he joked.

Shah said MISO’s queue is in dire need of the firmer site control requirements and milestone fees outlined in the plan, adding that a large volume of unready projects translates into inflated costs and cost volatility for other queued projects. The queue now includes 590 projects totaling about 92 GW after hovering around 100 GW for most of this year. In the last three years, about 800 projects comprising about 120 GW have entered the queue.

“We’ve seen projects with power purchase agreements, projects with provisional [generator interconnection agreements] forced to withdraw because of high costs,” he said.

Shah pointed to the February 2017 cycle of projects entering the queue as an example. Of 27 projects at 3.4 GW joining the queue, only two at 250 MW cleared. As a result, the MISO system went from requiring an estimated $3.4 billion in network upgrades to not needing a single one.

While the penalty-free “off-ramps” incorporated into the queue in 2017 are working as intended, MISO still needs a means to discourage unprepared project owners from prematurely lining up for interconnection in the first place, Shah said.

“It still needs adjustment up front,” he said.

MISO’s proposal would require developers of proposed generating facilities to demonstrate site control 90 days before a project enters the first phase of the three-phase definitive planning phase (DPP). It would also eliminate the RTO’s current practice of accepting a $100,000 deposit in lieu of proof of site control.

The refiled plan will no longer seek changes to the queue’s first milestone payment, which will remain $4,000/MW instead of becoming a variable cost representing 10% of the average network upgrade costs from the last three DPP cycles. The new plan will also add a refund mechanism to the total milestone fees imposed on a customer. The “true down” feature would cap total milestones at 20% of a project’s network upgrade cost, with any excess payment refunded back to interconnection customers after a project clears the second decision point, roughly 220 days into the queue.

As with MISO’s first filing, 50% of milestone fees would be considered at risk of not being refunded if they’re needed to help defray network upgrade costs should a project withdraw.

Additionally, MISO will now allow different fuel types and multiple generation projects to share the same site, scrapping the first proposal’s requirement that project owners show exclusive use of land.

September 26, 2019

Comments Open on Draft 2 of Inverter Standard

By Rich Heidorn Jr.

NERC is accepting comments until Nov. 4 on the second draft of a revised standard to improve the ride-through performance of inverter-based resources (PRC-024-3: Frequency and Voltage Protection Settings for Generating Resources).

The standard is intended to address issues identified in the Inverter-Based Resource Performance Task Force’s PRC-024-2 Gaps Whitepaper, which was prompted by the August 2016 Blue Cut wildfire, when 1,200 MW of solar generation disconnected, and the October 2017 Canyon 2 fire, which resulted in the loss of more than 900 MW.

The 45-day comment period opened Sept. 20 after a Sept. 4 webinar, at which the standard drafting team (SDT) explained changes made in response to industry comments on the initial draft. (See Comments due July 26 on Revised Inverter Standard.)

Draft 2 increases the implementation plan to 24 months from the original 18 months, which was criticized as too short.

Definitions

The term “point of interconnection” — which the current standard defines as the “the transmission (high voltage) side of the generator step-up (GSU) or collector transformer” — was eliminated.

The original term “meant so many different things to different entities,” explained SDT Chair Bryan Burch, of Southern Co.

“What a lot of folks call the point of interconnection in industry is actually not the high side of the GSU,” added Vice Chair Jeff Billo, of ERCOT.

The new draft also replaces the term “momentary cessation” with “cease to inject current.”

“The team talked about that with the inverter industry and … we came to the conclusion that the best path was to eliminate the use of the term ‘momentary cessation’ and go instead with the term ‘cease to inject current’ to better specify the intent and be more uniformly understood,” said team member John Anderson, of Xcel Energy.

The standard also replaces the term “protective relays” with “protection” to include both relays and protective functions embedded in control systems.

No-trip Zone

The team also eliminated the label “may-trip zone” from illustrations in the standard.

“There were comments made that we were then encouraging people to set their protection to trip before there were any machine requirements requiring that trip,” Anderson said. “As a response, the drafting team has eliminated these ‘may-trip zone’ labels on our curves and instead specified with a footnote that the area outside the no-trip zone is not a must -trip zone — hopefully to eliminate encouraging people to set their relay to prematurely trip.”

“The true intent, which is not enforceable on our end, is that we don’t want the protection to encroach on that boundary,” Burch said.

NERC inverter standard — Proposed revisions to PRC-024 would eliminate the label “may-trip zone” from illustrations in the standard to avoid premature generator tripping. | *NERC*

The team declined requests to specify what voltage protection settings should be beyond four seconds after a fault, saying anything after four seconds was outside the scope of the standard.

“We did a lot of research on this — looking back at what went into the original PRC-024-1 determination — and we pretty much found that this whole purpose of this standard was to define these frequency and voltage excursions that might be experienced during and after the clearing of a fault,” Anderson explained. “And we pretty much came to the conclusion that we didn’t have any basis to change that four seconds from the determination that was originally applied in PRC-024-1.”

Conflict with PRC-005-6?

The team was asked whether the standard would cover control systems such as automatic voltage regulators (AVRs) and, if so, how the initiative would mesh with a separate one to revise PRC-005-6. That standard authorization request says the standard needs clarification so that industry can “consistently identify and implement the required maintenance activities” on AVRs.

Anderson said PRC-024 would cover AVRs. “If it causes tripping of the generator either directly [or indirectly], then it is in scope,” he said.

“We can’t really commit to what the PRC-05 SAR and drafting team will do. We can specify that AVRs’ trips on voltage frequency and volts per hertz are in scope for PRC-024. PRC-05 might have other field-over-current-type functions that aren’t applicable to PRC-024,” he continued. “PRC-05 also deals with maintenance of those components, and we’re just dealing with the settings. So, there’s certainly some potential for misalignment. But since PRC-024 is focused on voltage and frequency — volts-per-hertz-type settings — potentially there will be some commonality.”

6 Questions

In its posting of draft 2, the SDT asked industry six questions, including whether the proposed changes are a cost-effective way to address the “ambiguities, inconsistencies and technical errors” in the existing standard.

The team also asked for comment on its decision not to make the standard — which covers the setting of voltage and frequency protective relays on GSU transformers and collector transformers — applicable to transmission owners in the U.S.

No TOs have been identified in the U.S. as owners of such transformers. However, the standard would apply to Hydro-Québec TransÉnergie, which owns the GSUs for about 37 GW of generation that it does not own. (See Tx Owners to be Exempt from Inverter Standard.)

The team also sought feedback on:

its modification of the “facilities” section to clarify both the types of “protection” applicable, if activated, and the specific equipment the protection is applied on;
exempting auxiliary equipment and associated protection(s) within a generating facility from the standard;
replacing the 0.1-second “minimum time (sec)” value in the frequency tables with “instantaneous,” and clarification regarding frequency calculation/measurement; and
the revised implementation plan, which would provide 24 months for applicable entities to evaluate settings, make changes for applicable equipment and purchase necessary equipment.
An additional 10-day ballot for the standard and a nonbinding poll of the violation risk factors and violation severity levels is expected Oct. 25 to Nov. 4.

NERC board adoption is targeted for February 2020.