Page 1069 – RTO Insider

March 3, 2019

MISO Reliability Subcommittee Briefs: Feb. 27, 2019

CARMEL, Ind. — In the wake of its January grid emergency, MISO has pledged to further study generation cutoffs in extreme temperatures and how it can best account for voluntary load curtailments in load forecasting.

MISO said its Jan. 30-31 emergency was in part triggered by a greater-than-expected drop in wind generation, with emergency demand difficult to predict as schools and businesses closed for the day and millions of energy consumers lowered their thermostats during the event in response to utility requests. (See MISO Details ‘Uncertainty ’ Behind Winter Max Gen Event.)

MISO said temperatures in its North region were more than 6 degrees Fahrenheit below those during the 2014 polar vortex. Forced outages surpassed 20 GW, while total outages and derates took more than 35 GW of generation offline. Although the RTO didn’t call on its neighbors for imports, its higher emergency prices attracted more than 5 GW of imports. Over the two days, the RTO exceeded $18 million in uplift charges, on par with other severe cold snaps. Load-modifying resource (LMR) use peaked at almost 3.9 GW on Jan. 30.

“Basically, it was unprecedently cold in MISO,” Director of Central Region Operations Ron Arness said during a Reliability Subcommittee meeting Wednesday. “Temperatures were colder than any since the existence of MISO, and we suspect that’s why wind generation was cutting off. … Even though the temperatures are abnormal, we should have this cutoff information so we can make good assessments about what generation is forecasted for the next day.”

IPL crews restoring power Jan. 31 | *Indianapolis Power and Light*

Arness said MISO will gather operating parameters to determine what generating resources must switch off in response to temperature thresholds and establish a load forecast variable that includes known voluntary load curtailment.

He added that quantifying voluntary curtailment is “a difficult thing to do, but one that MISO will look at nevertheless.”

Grid Strategies’ Michael Goggin, representing the American Wind Energy Association, said that while there were cold-weather wind cutoffs, large amounts of imported wind from PJM into MISO helped alleviate the emergency. He also said wind generation in Michigan helped to cover Consumers Energy’s gas supply issues following a fire at a compressor station.

Goggin also said it “makes perfect sense” for MISO to keep an account of the operating cutoffs across all classes of generation.

“I think once they do that, they won’t have an issue,” Goggin said in a telephone interview with RTO Insider.

He added that significant outages across all MISO resource types on Jan. 30 were a “much larger factor” than the missed wind forecast.

“There’s just a lot of equipment failures across all resources when you have temperatures this extreme,” he said.

As with past emergencies, some LMRs did not respond or verify availability in MISO’s communication system, Arness said. The RTO will hold training for LMR owners on how to navigate its system April 23-24 and again May 21-22 in anticipation of its summer peak.

As expected, MISO’s January operations report reflected the extreme cold and emergency declaration on the last two days of the month. The RTO’s peak load of 101 GW occurred on Jan. 30.

MISO also hit a new record wind output peak of 16.3 GW on Jan. 8, besting the previous record of 15.6 GW from March 31, 2018.

MISO to Work Through 2-Hour LMR Notification

MISO plans to work with stakeholders to determine how it will provide two-hour notice to LMRs called up to respond to emergency conditions.

MISO LMR Capacity Rules Get FERC Approval.)

Customized Energy Solutions’ Ted Kuhn asked how long LMRs are on the hook under the two-hour warning should MISO need to shift the emergency declaration to a later time.

“You just need to make sure it’s clear how long they have to be available. It’s not an indefinite; it needs to be [a fixed time period],” Kuhn said.

MISO staff said it was extremely unlikely that the RTO would continuously delay an emergency declaration over several hours, but it may need a little flexibility as it monitors possible maximum generation events.

“The timing of the peak is not a fixed thing. It could come earlier; it could come later,” said Dustin Grethen, MISO market design adviser.

“The two-hour notification is just that: making sure if they have someone drive out to flip the switch, they’re driving at the right time,” MISO Director of Resource Adequacy Coordination Laura Rauch said.

The RTO will discuss the filing amendment with stakeholders during this month’s Resource Adequacy Subcommittee meeting.

— Amanda Durish Cook

March 3, 2019

NYISO Commissions New Social Cost of Carbon Study

By Michael Kuser

RENSSELAER, N.Y. — NYISO on Thursday said it has commissioned Analysis Group to model the social cost of carbon in order to finalize a carbon pricing scheme for its wholesale electricity markets.

“In the last week we decided to have Analysis Group and Sue Tierney and Paul Hibbard do a fresh analysis,” Executive Vice President Rich Dewey told the Installed Capacity/Market Issues Working Group, referring to a senior adviser and principal, respectively, at the consulting firm.

“The scope of work for the Analysis Group is to build on the analysis previously done by [The] Brattle [Group] and (a) validate the findings, (b) extend the assessment based on the newly announced more aggressive policy goals and (c) identify any complementary benefits that might have been overlooked in the scope of the Brattle study,” Dewey said.

Dewey’s surprise announcement came near the end of a meeting devoted to new Tariff rules on carbon emissions and pricing. Stakeholders had begun to push ISO staffers to explain the timeline ahead of an anticipated vote on carbon pricing in the second quarter and describe exactly how the grid operator is learning whether the state supports their efforts.

“We all recognized when we started that this was new ground, uncharted territory,” Dewey said, indicating that the ISO would not present a carbon pricing package to FERC without state support. “We’re not going to take a vote and put forth a [Federal Power Act Section] 205 filing without state support. … We’re not going to ram through a vote by June without all on board.”

NYISO has commissioned Analysis Group to model the social cost of carbon in order to finalize a carbon pricing scheme for its wholesale electricity markets. The above graph is from an U.S. Interagency Working Group study in 2013. | *U.S. Government Interagency Working Group on Social Cost of Greenhouse Gases*

Howard Fromer, director of market policy for PSEG Power New York, said timing is critical.

“While we are figuring out how to price carbon, the state is moving forward with significant implementation of its policies,” Fromer said. “Renewables, a host of storage solicitations and draft air emission regulations were just issued for comment that impact over 3,000 MW of peakers in the New York City-Long Island area, all affecting how the market responds and thinks about what’s happening. We can’t wait too long to decide on how to act.”

Mark Reeder, representing the Alliance for Clean Energy New York, said, “The only thing we can affect is whether or not to have a carbon price, not whether or not the state’s environmental goals are admirable.”

Filling the Gaps

A task force created in October 2017 by NYISO and the New York Public Service Commission worked for more than a year developing a proposal to price carbon into wholesale markets. In December, it turned the proposal and final details over to the ISO’s stakeholder process. (See IPPTF Hands off Carbon Pricing Proposal to NYISO.)

“What we worked on in our stakeholder process is to get to a package that people are comfortable with, and at the end of March we’ll know what are the gaps,” Dewey said.

He added that the contract with Analysis Group is not meant to undermine the initial analysis done by Brattle, but “to look at unmonetized benefits,” whether in public health or other areas. The ISO will post details of the study as soon as possible, he said.

Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said he had no issues with the decision to conduct another study on the impacts of carbon pricing, but he was critical of the ISO’s decision to commission the study without even consulting stakeholders on the decision and, in particular, on the scope of the study.

Before Dewey’s announcement, Mager said, “It might be helpful to get a list of what the ISO considers to be open issues. Right now we have no clarity, and we want to understand the [carbon pricing] proposal on a comprehensive basis and go back to our clients.”

“We want more than silence from the state; we need a positive statement of support, at least when we go to FERC,” said Luthin Associates’ Aaron Breidenbaugh, representing Consumer Power Advocates, an unincorporated group of nonprofit institutional customers.

Rochester Energy Storage Hub | *NY-BEST*

Breidenbaugh said his clients already have uncertainties regarding subsidies, questioning how the state would structure thousands of megawatts of renewable energy contracts and whether the contracts will reflect carbon pricing effects or be layered atop them. He said they are “profoundly skeptical” about carbon pricing, especially in the context of a potential carbon tax being imposed by the state.

NYISO will discuss Tariff revisions and price calculation — specifically identifying marginal units — on March 18, and Tariff revisions again on March 28.

There will likely be at least one more meeting after that, said Nicole Bouchez, NYISO’s principal economist.

Tariff Terms, Penalties

NYISO on Thursday also prop o sed new Tariff sections to describe carbon charges, payments and residual allocation.

The ISO requires new Tariff definitions of carbon emissions and the cost of such emissions to effectuate carbon pricing, said Ethan D. Avallone, an ISO senior energy market design specialist. He also reviewed the work done so far on carbon residuals. (See NYISO Ponders Response to Carbon Charge Shortfalls.)

New sections of Rate Schedule 18 will include carbon charges and payments for import and export transactions, as well as for wheel-throughs and the carbon residual allocation, Avallone said. New sections of Rate Schedule 9 will include carbon charges for suppliers.

The Tariff language defines emissions as “point-of-production carbon dioxide emissions that result from energy injected, or start-up to inject energy, in connection with participation in the wholesale market.”

The ISO proposed a price on carbon emissions equal to the SCC — presumably as determined by the PSC — minus the value of any other state, multistate or federal charges for carbon emissions that a supplier must pay, including but not limited to emission allowance costs.

Penalties for failing to report or underreporting carbon emissions ramp up according to the severity of the lapse, from 0.5 times the applicable charge for failure to report emissions data by day 60, to 1.5 times the applicable invoice charge for failure to report by day 170, to double the charge for underreporting.

One stakeholder questioned the procedures for levying such penalties but was reassured that generators have a significant window in which to correct emissions data before being subject to penalties for underreporting or failing to report.

March 3, 2019

MISO, SPP Monitors to Conduct Seams Analysis

By Tom Kleckner

State regulators are bringing in the MISO and SPP market monitors to help solve seams issues between the two RTOs.

Potomac Economics’ Michael Wander | © *RTO Insider*

The Organization of MISO States and SPP’s Regional State Committee’s Liaison Committee has asked MISO’s Independent Market Monitor Potomac Economics and SPP’s Market Monitoring Unit to conduct a seams analysis and identify “specific seams issues from their perspective.”

Potomac’s Michael Wander and the MMU’s Keith Collins will provide a list of issues to Missouri Public Service Commissioner and OMS President Daniel Hall and Kansas Corporation Commissioner Shari Feist Albrecht, the committee’s chair and vice chair, respectively. Committee members are scheduled to hold a March 15 conference call to narrow the list for the monitors’ analysis.

“Hopefully, they will pick issues that can be monetized for ratepayers,” Hall said during a March 1 conference call.

Hall said he prefers a single report from the monitors but agreed two reports might be appropriate should their perspectives differ.

The Liaison Committee has been meeting since mid-2018 to help improve the grid operators’ interregional coordination, which has never produced a major project. That has frustrated some stakeholders and caused market inefficiencies.

Members met most recently in a closed session during the February National Association of Regulatory Utility Commissioners meeting. (See “OMS-RSC Talks Continue,” OMS Taps State Attorney for Leadership Role.)

Future meetings will be open to the public, Hall said then.

March 3, 2019

FERC: No Merit in MISO Deliverability Complaint

By Amanda Durish Cook

FERC has rejected a trade group’s complaint that MISO is improperly accounting for the deliverability of some capacity resources, saying it could find no Tariff language to support a violation.

The commission on Thursday said MISO isn’t in violation of its resource adequacy construct over capacity deliverability as the Coalition of Midwest Power Producers (COMPP) alleged late last year (EL19-28).

Rather than finding any Tariff provisions that evidenced violation, FERC said that MISO is “responsible for determining whether … capacity resources are deliverable to load.”

“Although power producers contend that ‘deliverable to load’ should be read to mean that capacity resources must have firm transmission service up to their full installed capacity levels, power producers fail to identify any Tariff provisions that support this assertion,” FERC said.

The commission also said COMPP didn’t demonstrate that MISO’s current practice jeopardizes reliability.

COMPP’s complaint alleged that MISO doesn’t properly account for capacity deliverability because its loss-of-load expectation (LOLE) study assumes that all capacity resources are fully deliverable on an installed capacity (ICAP) basis. However, the RTO allows resources to demonstrate deliverability only up to the unforced capacity (UCAP) levels, which tend to be about 5 to 10% below full ICAP levels. The group said MISO’s megawatt count from deliverable resources comes up short annually and drives down payments to capacity resources demonstrably positioned to deliver on their obligations. COMPP asked FERC to direct MISO to develop a solution to comply with its Tariff before the 2019/20 capacity auction. (See Trade Group Lodges Complaint over MISO Capacity Rules.)

MISO’s Tariff requires capacity resources to demonstrate deliverability either by having network resource interconnection service (NRIS), which stipulates that the entire ICAP of the resources must be deliverable, or by having energy resource interconnection service (ERIS) and procuring firm transmission service up its UCAP level.

No Discriminatory Treatment

In response to the complaint, MISO said it doesn’t hold capacity resources to different standards because it doesn’t require NRIS resources to perform to ICAP levels, instead requiring both to demonstrate deliverability up to their UCAP levels for the purposes of the capacity auction.

FERC agreed. “As described in its resource adequacy Business Practices Manual, MISO calculates the [UCAP] level of a resource by first determining its [ICAP] level. Once the [ICAP] value is determined, MISO applies the resource’s forced outage rate, thereby converting the [ICAP] level to a lower [UCAP] level. Next, MISO validates that the resource is deliverable by having the resource demonstrate deliverability up to its [UCAP] level,” FERC said.

The commission also said UCAP values are a vital part of MISO’s resource adequacy construct, with even the reserve margin formed as an “unforced capacity requirement.”

“Given the consistent use of unforced capacity values for purposes of resource adequacy in … its Tariff, we find that MISO reasonably implemented [its Tariff] by requiring capacity resources with ERIS to demonstrate deliverability up to their unforced capacity levels,” FERC said.

MISO said COMPP mischaracterized its Tariff “process improvements” discussions with the Independent Market Monitor as “admissions of Tariff violations.” The RTO has promised to have stakeholder discussions about resource deliverability and LOLE implications, with any potential fixes aimed at the 2020/21 capacity auction. (See “Capacity Auction Recommendations,” MISO Concurs with Monitor Ideas, Pledges More Study.) It said there was no evidence it violated Tariff provisions establishing a planning margin, the LOLE study methodology to create the planning margin or its duty to ensure the deliverability of capacity resources. MISO also said working on a rule change less than a month before the April capacity auction would seriously disrupt the auction.

At any rate, transmission deliverability is outside the scope of its LOLE analysis because the study assumes no internal transmission constraints, the RTO added.

However, the Monitor had asked FERC to side with COMPP, agreeing that “the terms of the Tariff result in a mismatch for some ERIS resources between the capacity assumed to be available in the LOLE studies and the capacity those suppliers can actually deliver.” But the Organization of MISO States urged FERC to hold off on ordering relief so the RTO could continue to address the issue through ongoing stakeholder discussions.

‘False Sense of Urgency’

MISO said the complaint created a “false sense of urgency” by implying that its recent emergency events had anything to do with capacity deliverability. To the contrary, the RTO said the events “have been driven largely by correlated planned outages and the use of emergency-only resources outside of the summer season.”

The RTO also argued that the power producers represented by COMPP are not prevented from auction participation nor are they suffering harm from MISO’s existing rules. It also said COMPP should have first sought dispute resolution with MISO. Finally, MISO alleged the complaint only sought to “disqualify 1,400 MW of generation owned by other auction participants to gain a competitive advantage.” The Monitor last year said as much as 1,400 MW worth of capacity resources needed to meet reserve requirements may not have been deliverable in the 2018/19 planning year.

March 3, 2019

FERC: Stability Deviation Method Best for Artificial Island

By Christen Smith

PJM’s “stability deviation” method best suits cost allocation for the Artificial Island project, FERC said Thursday, denying rehearing requests from transmission owners who favor the status quo.

The ruling comes eight months after the commission established a paper hearing to settle on the calculation for determining how PJM should distribute costs for grid stability projects, agreeing — in this case and for future stability upgrades — the existing solution-based distribution factor (DFAX) method doesn’t align allocations with benefits (E L 15-95).

“Based on the record developed through the additional hearing procedures, we find that the stability deviation method is a just and reasonable replacement rate for PJM to apply to all of the costs of lower-voltage facilities that address stability-related reliability issues and [to] 50% of the costs of regional facilities and necessary lower-voltage facilities that address stability-related reliability issues, including the Artificial Island project,” FERC concluded in its Feb. 28 ruling.

The Hope Creek and Salem nuclear units on Artificial Island in southern New Jersey | *BHI Energy*

Unjust and Unreasonable Status Quo

The debate stems from a yearslong discussion over who should pay for new transmission lines between New Jersey and Delaware to address stability limits on generation at the Salem and Hope Creek nuclear plants and transmission constraints that sometimes prevent the generators from exporting power at full capacity. Such a project is rare and doesn’t conform well to the DFAX method, PJM contends. (See DFAX: ‘Poison Pill’ or ‘Best Method’ of Cost Allocation?)

For reliability projects, PJM assigns 50% of the costs of regional facilities (500-kV lines or higher and double 345-kV lines) and “necessary” lower-voltage facilities required to support regional lines on a load-ratio share basis. The other 50% is allocated using DFAX. All costs of lower-voltage facilities not supporting regional lines are allocated via DFAX.

Using this methodology, 93% of the $280 million Artificial Island project cost would have fallen on Delmarva Power & Light — much to the dismay of Maryland and Delaware utility regulators who said the distribution disproportionately targeted their ratepayers.

In July, FERC agreed with the state commissions, noting that unlike thermal overloads, the parties that cause stability issues don’t necessarily have flows on the corresponding transmission facility. While Delmarva customers will use the new transmission lines from the Artificial Island project, the company neither caused the need for the lines nor does it benefit from those flows sufficiently because its transmission system already was adequate to serve its load, FERC found.

“While Delaware load will receive some increase in reliability from having a more robust transmission system, we find that the costs that would be allocated to the Delmarva parties under the solution-based DFAX method would not be at least roughly commensurate with the benefits received,” FERC concluded.

Stability Deviation Method

PJM long agreed it needed a different way of divvying costs for stability-related issues, noting those who cause these problems aren’t always the same ones who will benefit from it being repaired — such as in the cases of thermal violations, voltage/reactive issues, storm hardening, end-of-life/aging infrastructure or real-time operation concerns.

Staff crafted a few different possibilities, including the stability deviation method, which determines that a measurement of the change in the voltage angle is higher for substations that are more impacted by a disturbance or stability event, also referred to as the angular deviation. This change would identify the loads that would be most impacted by a stability disturbance and would benefit from transmission projects that address stability-related issues.

Under this calculation, costs of the Artificial Island project would fall 19% to the Public Service Electric and Gas, 15% to PECO Energy, 12.5% to PPL, 12.4% to Jersey Central Power & Light, 10.4% to Delmarva Power, 7.2% to Atlantic City Electric and about 5% to Metropolitan Edison. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)

TOs described the method as arbitrary, unexplained and unjustified, saying it amounts to the opposite of the basic underlying principle of PJM transmission cost allocation in the post-Order 1000 era. Instead, TOs pushed for a reversion back to the status quo — an idea FERC outright rejected.

“The PJM transmission owners have not demonstrated that, for transmission facilities addressing stability-related reliability issues, it would be just and reasonable to revert to the solution-based DFAX method to identify the beneficiaries of transmission facilities, once the stability-related reliability issue supporting the need for the transmission facility is resolved,” the commission said. “Further, while the PJM transmission owners’ reversion proposal identifies retirement of generating facilities as triggering the reversion, other system topology changes, such as transmission facility enhancements or expansion, may also affect the stability concern, but are not addressed by the reversion proposal.”

March 1, 2019

Wheeler Confirmed to EPA on 52-47 Vote

By Rich Heidorn Jr.

The Senate on Thursday confirmed former coal lobbyist Andrew Wheeler as EPA administrator on a 52-47 vote.

Acting EPA Administrator Andrew Wheeler waits to testify at his Senate confirmation hearing in January. | © *RTO Insider*

Wheeler, who has been serving as acting administrator since the July resignation of Scott Pruitt, was supported by all but one Republican, Susan Collins (Maine).

Collins criticized Wheeler’s efforts to replace the Obama administration’s Clean Power Plan and weaken air emission standards for vehicles.

“These efforts are of great importance to the state of Maine, which is located at the end of our nation’s ‘air pollution tailpipe’ and is on the receiving end of pollution generated by coal-fired power plants in other states,” Collins said in a statement. “Moreover, there is no doubt that the greenhouse gas emissions driving climate change pose a significant threat to our state’s economy and our natural resources, from our working forests, fishing and agricultural industries, to tourism and recreation.”

Collins also cited EPA’s determination that it is no longer “appropriate and necessary” to regulate mercury emissions from power plants. “Controls for mercury, one of the most persistent and dangerous pollutants, are especially important for children and pregnant women,” she said. “The agency’s recent efforts to halt progress in these critical areas takes us in the wrong direction.”

Other Republicans and business groups, however, praised Wheeler for continuing Pruitt’s work undoing regulations they contend were strangling industry.

“I believe he will do an excellent job leading the agency,” said Sen. John Barrasso (R-Wyo.), chair of the Environment and Public Works Committee. “As acting administrator of EPA, he has prioritized commonsense policies that protect our air and water, while allowing our economy to grow.”

Sen. Lisa Murkowski (R-Alaska), chair of the Energy and Natural Resources Committee, said she supported Wheeler because “he has proven himself during his tenure as acting EPA administrator as a leader who hears and takes seriously the concerns of Alaskans.”

“Regulatory certainty has been key to the historic manufacturing job growth we’ve seen under the current administration, and that would not have been possible without Andrew’s leadership at EPA,” said Jay Timmons, CEO of the National Association of Manufacturers.

Democrats and environmental groups blasted Wheeler’s appointment.

“At this moment of growing harm from climate change, appointing someone to lead the EPA who has vigorously opposed our efforts to reduce carbon pollution … would be like putting the Monopoly Man in charge of regulating big banks,” Sen. Chris Van Hollen (D-Md.) said.

“As a former fossil fuel lobbyist, he consistently worked against the public interest to advance an anti-environment agenda and dismantle many hard-won climate change programs,” Sen. Dianne Feinstein (D-Calif.) said.

“As administrator, we expect he will continue doing the bidding of the polluters he used to represent,” said John Bowman, senior director of federal affairs for the Natural Resources Defense Council. “And what he can expect from us, and many others, is a wall of opposition and legal challenges to stop this dangerous agenda.”

At his confirmation hearing before Murkowski’s committee on Jan. 16, Republicans praised Wheeler’s nearly two decades of experience at EPA and on the committee staff. Wheeler began his career at the agency during the George H.W. Bush administration and later served as staff director and chief counsel to Republicans on the committee.

Several Democrats credited him for being more responsive to their offices than Pruitt. But they were frustrated by his tepid comments on climate change. (See Dems Press EPA’s Wheeler on Climate at Confirmation Hearing.)

March 1, 2019

Calif. Needs far more Storage to Decarbonize, Panelists Say

By Hudson Sangree

SAN FRANCISCO — The explosive growth of solar power in California will require a huge amount of new electricity storage to allow the state to meet its ambitious green energy goals, panelists said Tuesday at this year’s Infocast Storage Week conference.

“What’s my vision for storage? Very quickly. We’re going to have to have a lot of it,” said Monterey Bay Community Power CEO Tom Habashi, who was part of a panel on storage and community choice aggregators (CCAs). “We are not even at a fraction of 1% of what we need to be at. I don’t see any other way of reaching decarbonization unless we have a lot of solar and a lot of storage to go with it so we can cover all the hours when the sun doesn’t shine.”

Last year’s SB 100 established a timeline for the state’s utilities and CCAs to get all their electricity from zero-carbon sources by 2045. But the state’s ample solar production peaks at a time when it’s least needed — during the lowest point of the so-called “duck curve” in the middle of the day. (See Can Calif. Go All Green Without a Western RTO?)

Larger batteries are just beginning to store a tiny portion of the electricity needed during the evening ramp, when the sun goes down and electricity demand soars as people arrive home on the West Coast. Doing away with natural gas peaker plants, as the state envisions, will require solar projects to be coupled with storage, speakers said.

The Monterey Bay CCA, for example, has 265 MW of solar energy plus 85 MW of storage. “We’re way, way ahead of what we are required to do,” Habashi said.

John Zahurancik, CEO of Fluence Energy and a 20-year veteran of large-scale storage projects, said larger and longer-duration battery projects are coming online all the time, but that it’s likely just the beginning.

“We’re in the early days of when this starts to scale,” Zahurancik said during a panel on standalone storage. “It’s just starting to pick up speed.”

Fluence is building a 100-MW standalone storage project, among the largest in the U.S., he said. More utilities are looking to lithium-ion batteries, in “increasingly large types of systems,” as a solution to the challenges of intermittent solar and wind power.

Asked whether any technologies would emerge to compete with lithium-ion batteries, Zhurancik said the batteries are a proven technology being built at volume with backing from deep-pocket investors. He said he expects to see improvements and changes but probably not a “wholly new” storage solution in the next five years.

Rooftop Solar ‘Underestimated’

In a panel on ISOs and storage moderated by RTO Insider Deputy Editor Robert Mullin, Clyde Loutan, CAISO’s principal planner for renewable energy integration, said the ISO hadn’t anticipated how fast rooftop solar would proliferate and create challenges for it.

RTO Insider’s Robert Mullin (right) moderated a panel on storage in ISOs/RTOs. On the panel (left to right) were: Kenneth Ragsdale, ERCOT; Clyde Loutan, CAISO; Mike DeSocio, NYISO; Eric Hsia, PJM and Kevin Vannoy, MISO. | © RTO InsiderInsider

“We completely underestimated the speed at which rooftop PV was going to come onto the grid,” Loutan said. There are 7,000 MW of rooftop solar in California, and planners expect to see as much as 13,000 MW by next year, he said.

Utility-scale solar projects supply another 12,000 MW of electricity in CAISO, he said.

With a variable resource like solar, output can suddenly drop by 1,000 MW, requiring battery storage that can come online quickly and make up for the shortfall, he said, and solar falls away each night.

“During the evening you got to meet that huge ramp when the solar drops off,” Loutan said.

On the other hand, there’s far too much solar power available on weekends. Oversupply and undersupply create challenges controlling the grid and maintaining the frequency at 60 Hz, Loutan said.

“You need a lot of stability,” he said. “You need a lot of fast-injecting capability. Storage can provide that.”

‘Best, Highest Use’

Mullin cited an RTO Insider story in which MISO CEO John Bear said RTO staff are working to determine the “best, highest use” for storage projects.

“We’ve almost internally forced ourselves as a company to calling them batteries, as opposed to storage, just because we don’t want to presuppose what the best use of them might be,” Bear said at the Gulf Coast Power Association’s MISO South Regional Conference in February. (See Overheard at GCPA MISO South Regional Conference.)

Batteries might be most valuable as quick-response resources to help balance the grid, he said.

Asked to elaborate, Kevin Vannoy, MISO’s director of market design, said, “What I think John was getting at there was it’s not about just storing energy for later injection.”

“I think we don’t want to limit ourselves to just a single product when it comes to storage or a single use or a single application because of the flexibility and the different products it can provide and the problems that it can solve.

“We don’t want to get stuck into just thinking of these as we have our traditional pumped hydro units,” Vannoy said. “We want to make sure we’re getting the full value … [and] capabilities that batteries and storage can bring.”

Loutan said the highest and best use for storage right now is to provide reliability and frequency response.

“We still need to explore the capabilities of storage,” he said. “How can we utilize the capabilities of storage to develop new products and help operate the grid differently?”

Challenges and Opportunities

Connecting storage to the grid isn’t as simple as plugging in a battery, panelists said. Challenges exist, with more to come, but batteries also present potential solutions to pressing needs, they said.

“One thing I would recommend is … making sure that the battery’s sized accordingly,” said Eric Hsia, liaison to the CEO at PJM. Oversizing or undersizing can cause trouble.

“If they do that and they do it wrong, it could potentially pose operational issues, which we did experience in the regulation market,” he said.

Kenneth Ragsdale, market design principal with ERCOT, said “I don’t want to sound like a Texan, but I think our challenges are a little harder than theirs.”

The Texas Interconnection is smaller than the Western or Eastern interconnections, “so the loss of our two largest units in the ERCOT system is a big hit in terms of trying to maintain the frequency. We’re very careful about making sure we have enough rotating mass, enough inertia, on the system.”

ERCOT adopted a “fast frequency response” protocol, he said. “Basically, you need a resource that can respond to a frequency deviation within 15 cycles,” he said. “We see a lot of hope for some batteries coming in and doing that.”

Batteries could also help alleviate five- to 15-minute price spikes and deal with the daily four-hour peak in the hot Texas summers, Ragsdale said.

In New York, “there’s tremendous opportunity for storage,” said Mike DeSocio, senior manager of market design with NYISO. The state mandated storage and has about 2,000 MW queued up, from 1.5- to 300-MW storage projects. “Storage is coming,” he said.

The state is looking to develop large quantities of offshore and onshore wind power along with rooftop solar. Batteries could help balance those variable resources with low-carbon electricity, he said.

Batteries could also buffer the state’s ample nuclear output (which is set to get financial support from zero-emission credits) — the same way pumped hydro did when the nuclear plants were first built, he said.

“I kinda feel like we’re going back to the future here a little bit,” DeSocio said.

March 1, 2019

NYISO Management Committee Briefs: Feb. 27, 2019

RENSSELAER, N.Y. — NYISO stakeholders on Wednesday concluded an unusually lengthy public policy transmission planning process and reviewed a revised report and new analysis for selection of two AC transmission projects to improve transfer capability into the New York City area.

The new analysis by ISO staff followed a December decision by the Board of Directors to decline the Management Committee’s recommendation to build Project T029 — a standard 345-kV line from Knickerbocker to Pleasant Valley — on Segment B, a section of the grid feeding the Upstate New York/Southeast New York (UPNY/SENY) electrical interface. (See NYISO Board Partially Reverses AC Tx Project Selection.)

ISO staff are now recommending Project T019, as is the board, saying it has the highest incremental UPNY/SENY transfer capability, which results in the lowest cost-per-megawatt ratio, highest production cost savings, greatest CO2 emissions savings and highest Installed Capacity (ICAP) savings of the Segment B projects, Zach Smith, vice president for system and resource planning, told the committee.

The board did not object to the committee’s selection of Project T027, a double-circuit 345-kV line from Edic to New Scotland for Segment A, which feeds the Central East interface.

Advised by consultant Substation Engineering Co., NYISO reviewed seven proposals for Segment A and six for Segment B before making their choices last June. (See NYISO MC Supports AC Transmission Projects.)

Project T019 was proposed by National Grid’s Niagara Mohawk Power and NY Transco, while North America Transmission (NAT) and the New York Power Authority together proposed both projects T027 and T029.

Cost estimates for both NAT/NYPA projects ranged from $900 million to $1.1 billion. The estimated capital costs for T027 and T019 are higher, at $1.2 billion, but the project is made more cost-effective by the up to 550 MW of additional N-1 emergency transfer capability provided on UPNY/SENY by T019, Smith said.

The ISO estimates the two AC transmission projects, if approved by the board in March, will be in service by December 2023.

Process Matters

NYISO Public Policy Tx Revisions Approved.)

Lawrence Willick of LS Power said the incremental benefits of T019 do not justify the incremental costs, but New York Transco General Counsel Kathleen Carrigan said the ISO on two occasions (including with the selection of T027 for Segment A in the AC Transmission PPTN and for the Western New York PPTN) has recommended projects with higher capital costs to be selected as the most efficient or cost-effective solution to satisfy a PPTN. In both cases, she said, the higher capital costs correlated to significantly greater benefits to the statewide electric system than the lower-cost alternative proposals. She contended that the ISO should take a similar approach in its recommendation for Segment B as well.

Several stakeholders requested an opportunity to address the board, and LS Power and NY Transco will make oral presentations on March 18, one day before the board meets, interim NYISO CEO Rob Fernandez said.

“We only wish to present if LS Power presents — if they don’t, we don’t,” Carrigan said. Fernandez responded that the ISO would work out the details soon. Comments on the PPTN review were due Friday.

The ISO estimates the two AC transmission projects, if approved by the board in March, to be in service by December 2023. | *NYISO*

Stakeholders in January informed the ISO of a modeling error in the analyses, specifically that the impedance data had been transposed for the New Scotland-Knickerbocker and Knickerbocker-Alps 345-kV projects.

“We corrected the impedance and confirmed it with the developers,” Smith said. “The ISO also revised its dispatch methodology after the board said it created a perception of a constraint. The board requested we dive a little deeper into operability analysis.”

Specifically, the impedance data correction impacted the UPNY/SENY limit, he said. For T019, the incremental UPNY‐SENY emergency transfer capability decreased from the previously calculated level of 2,100 MW to 1,850 MW. For T029, the data correction caused the incremental emergency transfer capability to increase from 1,150 MW to 1,300 MW.

Additional analysis also included a “sensitivity” in which the G‐J Locality is eliminated and a new H‐J Locality is created.

“The capacity scenario should be eliminated as being more misleading than useful,” said Mark Younger of Hudson Energy Economics, which helped the Independent Power Producers of New York submit comments on the analysis. IPPNY took no position on the board’s PPTN project selection.

Younger said it was unreasonable to assume capacity could be replaced in the more densely populated areas of Zones H and I for the same price as in the more rural Zone G, and that it was also impossible that the market would not respond to stopping payments to resources based on their locational value. He also noted that NYISO’s own analysis in the study showed that there continues to be a need for capacity in Zone G.

Entry and Exit Modeling

“One of the things that limits the benefits from the recommended projects is limited transfer capability south of the projects, so future increases in transfer capability south of these projects could lead to substantial additional benefits,” said Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit.

“At the same time, if the PSC relies more on offshore wind than upstate renewables to achieve the goals of the Clean Energy Standard, then it would tend to reduce the benefits,” so the location and amount of intermittent renewables is in flux, he said in summarizing his report’s conclusions.

NYISO’s public policy transmission planning process calls for the Monitor to review and consider the impacts on the ISO’s markets.

The Monitor made several recommendations for improvement, but LeeVanSchaick particularly highlighted one: to model entry and exit decisions for generators in a manner consistent with the expected competitive market outcomes.

“If the ISO could incorporate entry and exit scenarios into its modeling, that would be very useful for ensuring the scenarios provide a realistic picture of the future benefits of the projects,” he said.

Marc Montalvo of Daymark Energy Advisors, representing the New York Department of State’s Utility Intervention Unit, said the UIU was concerned, as were several other stakeholders, about the qualitative measures being applied and decisions being reached in a different way from the MC’s understanding during its serious deliberations.

“We ought to make sure we are not creating a process that gives developers pause,” Montalvo said. “Given how much time and energy on behalf of the developers goes into the process, the last thing we want to see is a lack of confidence … whereby developers might choose not to participate, reducing the efficiency of market outcomes and possibly harming consumers.”

— Michael Kuser

March 1, 2019

NEPOOL Seeks Rehearing on Press Ban Order

By Rich Heidorn Jr.

The New England Power Pool indicated Thursday it won’t let reporters into its meetings without a fight, asking FERC to reconsider its order rejecting the group’s press ban.

The commission ruled unanimously Jan. 29 that it had jurisdiction over NEPOOL’s membership rules and that barring journalists from joining was unduly discriminatory (ER18-2208-001). (See FERC Rejects NEPOOL Press Membership Ban.)

NEPOOL Participants Committee | *NEPOOL*

FERC said it would rule separately on RTO Insider’s complaint under Section 206 of the Federal Power Act 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.

The stakeholder group sought to amend the NEPOOL Agreement to bar members of the press from membership after RTO Insider reporter Michael Kuser, an electric ratepayer in Vermont, applied to join as an End User in March 2018.

In its request for rehearing or clarification, NEPOOL contended that “the commission’s jurisdictional determination not only lacks sufficient explanation, but its conclusion that the membership provisions are jurisdictional is potentially limitless in scope.

“Under these circumstances and given the issues pending before the commission in the complaint proceeding in Docket No. EL18-196, NEPOOL files this request to preserve its rights until the commission provides clarity and explanation for its decision to exercise jurisdiction over the membership arrangements of an entity that does not provide wholesale power or transmission service to any customer,” the organization continued.

The commission’s order rejected NEPOOL’s contention that its membership provisions were not FERC-jurisdictional, concluding that “they directly affect commission-jurisdictional rates.”

NEPOOL said FERC’s ruling cited as precedent only “one factually dissimilar case … and provides no explanation as to how the cited precedent supports the commission’s jurisdictional claims.”

The case cited was a 2016 ruling involving PJM in which the commission found that the RTO stakeholder process is “a practice that affects the setting of rates, terms and conditions of jurisdictional services.” The commission made the filing in rejecting rehearing of an order approving PJM’s funding of the Consumer Advocates of the PJM States. (See FERC Upholds PJM Advocates’ Funding.)

“Without an explanation of how and why PJM is relevant to the treatment of NEPOOL’s membership amendments, the January order fails to meet the commission’s obligation to carry out reasoned decision-making,” NEPOOL said. “NEPOOL requests that the commission further articulate the basis for its conclusion that the membership amendments are jurisdictional. As it stands, the January order could be read to sweep virtually any NEPOOL practice, procedure or protocol under commission jurisdiction, no matter how tangential to rates, terms or conditions of jurisdictional service.”

NEPOOL said the commission’s reasoning was “similar to the expansive view of its jurisdiction that was rejected” by the D.C. Circuit Court of Appeals in its 2004 CAISO ruling.

In that case, the court rejected FERC’s attempt to replace CAISO’s Board of Governors, ruling that the commission “does not have the authority to reform and regulate the governing body of a public utility under the theory that corporate governance constitutes a ‘practice’ for ratemaking authority purposes.”

Membership Pending

NEPOOL’s rehearing request comes two weeks after its Membership Committee recommended to the Participants Committee that Kuser be granted membership. The Participants Committee has listed the issue on the agenda for its next meeting, March 13.

In addition to seeking to change its Agreement to bar press from membership, NEPOOL last year also amended the Participants Committee bylaws to limit the ability of meeting participants to share what they’ve heard.

The new language — which was not submitted for FERC approval — 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.”

The commission’s January order left that prohibition intact.

March 1, 2019

MISO MEP Cost Allocation Plan Goes to FERC

By Amanda Durish Cook

MISO and a majority of its transmission owners on Monday filed a new cost allocation plan with FERC that would change the way the RTO allocates costs for its market efficiency projects (MEPs).

The proposal applies to MISO’s 2019 Transmission Expansion Plan and includes MISO South, which saw its five-year transmission cost-sharing moratorium expire at the end of 2018.

The 622-page filing includes proposals to lower the voltage threshold for MEPs from 345 kV to 230 kV and eliminate a 20% footprint-wide postage-stamp cost allocation method for projects. It will also create two new project benefit metrics: the value of deferred or avoided reliability transmission projects, and the value of reducing power flows on the contract path on shared transmission from MISO Midwest to South (ER19-1124 , ER19-1125).

The proposal additionally creates a new category for economic projects below 230 kV and above 100 kV where 100% of costs would be allocated to the local transmission pricing zone. Such projects were previously categorized as “other” transmission projects without clear allocation rules.

MISO said the proposal was “extensively vetted” through its stakeholder process for more than three years. It noted that the package creates “additional opportunities for the identification and approval of market efficiency projects and greater precision in cost allocation for such projects, and formalizes the process for development of locally based economically beneficial projects.”

The RTO told FERC that the lower voltage threshold will likely result in more MEPs and, by extension, more opportunities to bid projects under the competitive transmission process. Because of the expected uptick in activity, MISO also proposed a limited exception to the competitive selection process for MEPs that can also demonstrate an immediate reliability need. The exception would only apply when a lengthy bid selection process would push a project’s in-service date past the expected reliability need date, MISO said, urging the commission to accept the provision, because it had approved similar selection exceptions in three other RTOs.

More Benefit Metrics?

MISO last year opened the door to the two new benefit metrics on MEPs besides the usual adjusted production costs; earlier this month staff signaled willingness to add even more benefit metrics to the list this year.

At the February Planning Subcommittee meeting, MISO planning coordinator Adam Solomon said the RTO and stakeholders will likely begin with ideas that didn’t make the cut last year, including increased capacity import and export limits, reduced congestion from fewer transmission outages, reduced transmission losses and the ability of a project to boost grid resilience.

MISO will work with stakeholders to identify new benefit metrics to pursue during the first half of the year and then determine how to quantify them during the second half. The work could culminate in a FERC filing by the end of the 2019.