Page 1073 – RTO Insider

July 21, 2020

NE States Pursue Clean Energy, Despite COVID-19

Officials from New England’s six states on Friday described their efforts to advance renewable energy goals despite the coronavirus pandemic.

“We’re really lucky to live in this region where so many states are pushing for clean energy,” said Catherine Finneran, vice president for sustainability and environmental affairs at Eversource Energy, who introduced speakers at the webinar hosted by the Environmental Business Council of New England.

New England clean energy — The Environmental Business Council of New England hosted a gathering of state energy officials on July 17. | *EBCNE*

Following is some of what we heard at the meeting.

Room to Grow on the Grid

Eric Johnson, director of external affairs at ISO-NE, focused on the changing resource mix in the region.

“The region has room for about 6,000 MW of additional wind resources without the need for significant transmission upgrades,” Johnson said, referring to the RTO’s 2019 Economic Study Offshore Wind Transmission Interconnection Analysis, presented at last month’s Planning Advisory Committee meeting. (See ISO-NE Planning Advisory Committee Briefs: June 17, 2020.)

The analysis summarized findings from three studies requested last year by the New England States Committee on Electricity (NESCOE), Anbaric Development Partners and RENEW Northeast. (See related story, Panel: Much More Tx Needed for New England OSW.)

“While renewables are only about 9% of our resource mix in 2019, with what the states are looking to do with the renewable portfolio standard, those numbers will grow dramatically,” Johnson said.

Small States, Big Goals

Riley Allen, deputy commissioner of the Vermont Department of Public Service, said his state has about 720 MW of renewable energy resources meeting a peak load approaching 900 MW.

“In the past, the peak load used to be well above 1,000 MW, but Vermont is following the path of the region, and our loads have been declining, including peak loads,” Allen said.

Vermont’s RPS started at 55% in 2017 and will increase to 75% by 2032, Allen said. “There’s legislation that was moving forward to update that to 100% by 2030, but the COVID-19 pandemic intervened and that’s been pushed to a later session.”

The DPS is involved in a rate design initiative, an eight-month process sponsored by the Department of Energy to look at dynamic rates, flexible load management, subscription services and gaining adoption of more advanced rate designs.

“We focused on several areas of emerging technologies: the heat pump, electric vehicle load, customer-sited generation and energy storage,” Allen said. “These are broadly recognized as loads that are pretty impactful if they’re left unmanaged, but with management, there’s a great deal of potential to essentially mitigate their potential adverse effects on the system.”

He characterized Vermont as having a roughly $800 million electric system today, “and in the next 20 years, we can expect an additional bill of $500 million on top of that with the addition of these new technologies.”

Carrie Gill, chief of program development in the Rhode Island Office of Energy Resources, highlighted her state’s push to meet 100% of electricity needs with renewables by 2030 and decarbonize the heating sector, and its continued leadership in energy efficiency.

Rhode Island Gov. Gina Raimondo signed an executive order in January committing the state to be powered by 100% renewable electricity by the end of the decade and directing the OER to conduct economic and energy market analyses in order to develop workable policies and programs. (See RI Seeks to Lead with 100% Renewable Goal.)

“We recognize that we must keep energy supply and energy delivery rates affordable,” Gill said. “Fortunately, we’re seeing that many renewable energy resources are not only cost competitive, but sometimes represent the lowest-cost resources available.”

The heating sector is an important target because looking at decarbonization just in terms of electricity would be shortsighted, she said.

“We do not recommend that Rhode Island depend on one technology; [it should] look to multiple pathways. But either way, our fuel becomes decarbonized,” Gill said.

Rhode Island has been ranked among the top three states for energy efficiency for the past few years and is proud of it, she said.

“We lost 3,900 of 17,000 clean energy jobs in the state since March … but even though we have challenges related to COVID, we’re not going to take our foot off the gas pedal,” Gill said. “We see this as an opportunity to move forward and to advance the clean energy industry.”

Dale Raczynski of Epsilon Associates asked how the state will meet peak demand with a 100% renewable mix during periods of low wind or solar.

“We will see storage as a critical technology … so we’re working on understanding where the market barriers are and removing them,” Gill responded.

Hank Webster of Acadia Center asked if the state would offer incentives allowing gas heating customers to transition to heat pumps. “There are many benefits to getting off gas because methane is a very harmful climate pollutant and presents a public health and safety risk,” Webster said. “Recent reports about indoor cooking show terrible health impacts.”

“We are trying to look holistically across sectors. … We don’t want to foreclose any options to us,” Gill said. She also added that improving the energy efficiency of HVAC systems reduces the risk of spreading pathogens.

Gulf of Maine

Dan Burgess, director of the Maine Governor’s Energy Office, said that growing the clean energy economy is even more important now in the pandemic.

“Fortunately, the pandemic started during a shoulder season for heating … and Gov. Janet Mills has convened an Economic Recovery Council,” Burgess said. “There’s certainly some energy overlap, and we see an opportunity for clean energy and energy efficiency to play a role in the economic recovery.”

Mills signed an executive order last year setting a 2045 goal for achieving carbon neutrality and creating the state’s Climate Council to put it on a path for 45% emissions reduction by 2030 and 80% by 2050, he said.

“We’re on target to reaching those emissions goals,” Burgess said. “The electric power sector represents only 7% of emissions in the state, but we’ll have to keep working on that sector as we electrify transportation and heating in the state, where 60% of homes use heating oil.”

Burgess said heat pumps, which Efficiency Maine Trust has been promoting for 10 years, offer both environmental benefits and jobs, adding that “also there’s a huge opportunity in electric water heaters.”

He touted the first floating offshore wind turbine in the country, now under development by the University of Maine in the Gulf of Maine.

Matthew Mailloux, energy adviser in the New Hampshire Office of Strategic Initiatives (OSI), also serves as the state’s adviser to the Bureau of Ocean Energy Management for the tri-state offshore wind task force.

“We’re in the middle of a pandemic, and obviously some work has slowed down as a result, but OSI, especially in the early days of COVID, was working to understand what the landscape was for the energy sector broadly to make sure that critical infrastructure was still able to perform,” Mailloux said.

Gov. Chris Sununu declared a moratorium on evictions and utility shutoffs, which was done through the OSI, he said.

“The Gulf of Maine has some of the best offshore wind resources of anywhere in the world, not only some of the best wind speeds in the country,” Mailloux said. “New Hampshire is a relatively small piece of the pie when it comes to actual federal waters off our coast, but we also have some great transmission interconnection assets.”

One challenge is that northern New England is an export-constrained region for ISO-NE, he said.

“As we continue to inject more power into the grid at those locations, there [are challenges to] exporting that power to load centers in southern New England, such as Boston or Hartford,” Mailloux said.

New Hampshire also has seen “a contentious debate about net metering over the past year or so,” and “we won’t see much progress on net metering this year but will if Gov. Sununu is re-elected in November,” he said. (See related story, FERC Rejects Net Metering Challenge.)

Environmental Justice

Massachusetts Department of Energy Resources Commissioner Patrick Woodcock said 2020 is “an inflection year for” his state, which is attempting set an interim 2030 goal on the way to meeting Gov. Charlie Baker’s 2050 date for reaching net-zero greenhouse gas emissions. He referred to a decarbonization study being led by Undersecretary for Climate Change David Ismay to guide the state’s effort to meet the 2050 target. (See “Bay State Net-zero Overview,” NEPOOL Markets/Reliability Committee Briefs: July 1, 2020.)

Patrick Woodcock, Massachusetts DOER | *EBCNE*

Woodcock said the pandemic highlights the importance of a resilient electric system and the disparity of air quality across the state. “We are refocusing on how electrification may provide benefits for air quality and have started to contemplate either targeting incentives to environmental justice municipalities [or] targeting commercial medium- and heavy-duty vehicles, to ensure that our EV policies also have the co-benefits of improving air quality.”

The busy regulatory agenda included new regulations, which double the Solar Massachusetts Renewable Target program to 3,200 MW, and mandate that any solar installation over 500 kW needs to be paired with storage, he said.

“The policy does include some limitations on eligibility for land that has been identified as priority habitat … so that our solar policy has co-benefits of managing our open space,” Woodcock said.

Massachusetts also is finalizing its Clean Peak Standard. “We’re trying to harness storage and other resources to ensure that clean energy growth starts addressing the shifting peak that has been contributing to high electricity prices,” he said.

Implemented last year, the standard mandates that a minimum percentage of retail electricity sales be met with clean generation resources or load reductions during seasonal peak periods. (See Mass. Inaugurates Clean Peak Standard.)

Susannah Hatch of the Environmental League of Massachusetts asked about regional collaboration on offshore wind and transmission.

Victoria Hackett, Connecticut DEEP | *EBCNE*

Woodcock said officials are working on it and referred to a technical conference his agency held in March to explore whether the state should solicit proposals for a coordinated independent transmission network for offshore wind generation. (See Mass. DOER Explores Transmission for OSW.)

Victoria Hackett, deputy commissioner for energy in the Connecticut Department of Energy and Environmental Protection, agreed with Woodcock that environmental justice is important to protect those people most affected by polluting energy resources.

DEEP Commissioner Katie Dykes instituted a policy that all the agency’s work has to be viewed through the lens of environmental justice, Hackett said.

Last August, about 40 environmental activists marched in front of DEEP headquarters in Hartford to protest state regulators’ approval of a new 650-MW gas-fired power plant in the town of Killingly. (See Connecticut Activists Protest Gas-fired Plant.)

July 21, 2020

NYISO BSM Mitigation Ruling Sparks Glick Rebuke

FERC last week approved NYISO’s revised buyer-side market (BSM) power mitigation rules, prompting a warning from Commissioner Richard Glick that the commission had threatened the future of organized capacity markets by explicitly excluding state-supported resources from mitigation exemptions.

Thursday’s 3-1 ruling followed on a February order that partly approved NYISO’s proposal for implementing renewable resource and self-supply exemptions to the BSM rules in its capacity market and directed the ISO to submit a compliance filing revising some provisions (ER16-1404). (See FERC Narrows NYISO Mitigation Exemptions.) It also denied a request for rehearing of the February order by a handful of New York state agencies and the American Public Power Association.

Glick’s dissent aimed not so much at the exemption rules but at their selective application, arguing that FERC’s approach to BSM mitigation “has degenerated into a scheme for propping up prices, protecting incumbent generators and impeding state clean energy policies.” He warned that the commission’s efforts “to ‘save’ capacity markets are more likely to hasten their eventual demise.”

The commission on Thursday accepted nearly all the revisions in NYISO’s compliance filing, effective for new resources entering the Installed Capacity Market (ICAP) starting with interconnection Class Year 2019. Approvals covered:

NYISO’s proposal to use a “renewable exemption limit” formula to calculate a megawatt cap of renewable resources exempt from BSM mitigation specific to each mitigated zone.
Inclusion of an “incremental regulatory retirement” component in the renewable exemption limit, which will adjust the megawatt cap to reflect the retirement of resources that can be attributed to “direct” regulatory actions taking place since the prior ICAP study period. The feature is intended to address NYISO’s concern that state policies can create a supply of “out-of-market” resources that depress capacity prices.
Use of an unforced capacity reserve margin (URM) impact component in the renewable exemption limit formula, which is intended “to capture the change in the URM in a mitigated capacity zone that reflects how URM market requirements are expected to increase in response to renewable resource entry.”
Implementation of a “renewable exemption bank” through which unforced capacity megawatts not used in prior interconnection studies are “carried over” into subsequent studies, ensuring “that any UCAP megawatts derived from the other three factors — change in forecasted peak load, incremental regulatory retirements and the URM impact — remain available to qualified renewable exemption applicants in future buyer-side market power mitigation determinations, thereby keeping supply and demand in the capacity market in balance even where entry and exit are lumpy over time.”

The commission conditionally accepted NYISO’s proposed role for its Market Monitoring Unit in determining what resources qualify as incremental regulatory retirements. It directed NYISO to revise the proposal by removing the commission as the arbiter in the event of a disagreement between the ISO and the MMU and instead designate that the ISO’s decision would prevail.

“Thus, absent a Section 206 complaint, the commission will not have a prescribed role in such determinations,” FERC wrote. “We find that NYISO’s proposal invites delay to a time-sensitive process. In particular, we find that if the commission fails to act on a disagreement within 60 days, suspending the Class Year process could result in unacceptable delays to an already complex process that NYISO is working to streamline and for which developers need greater certainty.”

Rehearing Rejected

Thursday’s ruling also denied a rehearing request by the New York Public Service Commission, New York State Energy Research and Development Authority, New York Power Authority, Long Island Power Authority (referred to as the NY Parties) and APPA, which asked the commission to review its February finding that public power entities should not be eligible for NYISO’s self-supply exemption in the capacity market. The NY Parties also sought rehearing of FERC’s decision to reject a statewide 1,000-MW cap for the renewable resources exemption.

The commission disagreed with the contention by APPA and the NY Parties that the decision to exclude state resources from the self-supply is arbitrary and capricious and inconsistent with the 2015 complaint order that originally forced NYISO to alter its exemptions policy. It noted that the complaint order “expressed ‘concerns regarding the state’s ability to artificially suppress prices by channeling uneconomic entry through an exempted load-serving entity’ and directed NYISO to ‘consider the impacts of state decisions to subsidize resources that are owned or contracted for by a self-supplied load-serving entity.’”

The commission at the time had also required NYISO “to propose net-short and net-long thresholds ‘tight enough to prevent a load-serving entity from being able to deliberately overpay for a resource in an attempt to manipulate ICAP market prices in a way that benefits the load-serving entity’s other purchases from the ICAP market.’”

NYISO buyer-side market — St. Lawrence-Franklin D. Roosevelt Power Project on the St. Lawrence River | *NYPA*

The February 2020 order found that NYISO “had failed to comply with these directives because NYISO’s proposal to allow certain instrumentalities of the state to be eligible for the self-supply exemption did not account for the state’s ability to suppress ICAP market prices through self-supplied load serving entities.”

The commission noted that its February ruling found “the net-short threshold is premised on the assumption that a load-serving entity’s incentive is to minimize the costs of serving its customers, and that this assumption does not hold true for certain state entities, such as NYPA,” whose own mission statement “supports the conclusion that NYPA’s main focus is the welfare of New York state as a whole,” including supporting businesses and nonprofits that provide jobs and services to the state.

FERC found that the incentive of “certain instrumentalities of the state to act on behalf of the whole state” was critical in determining whether the proposed net-short and net-long thresholds would fulfill their purpose.”

In denying the request to rehear its rejection of NYISO’s statewide 1,000-MW renewable resources exemption cap, the commission contended that the cap was inconsistent with a previous order to “narrowly tailor” such caps to mitigated capacity zones. The commission said it disagreed with the NY Parties’ contention that FERC’s requirements will result in a more restrictive cap than that considered in the 2015 complaint order.

“We further disagree that the February 2020 order interferes with New York state’s authority to determine the mix of generation resources in [the New York Control Area]. The commission does not improperly intrude on the states’ authority to determine its energy resource mix and the development of new generation merely by implementing wholesale rules affecting matters within the states’ jurisdiction.”

‘Misguided Belief’

In his scathing dissent, Commissioner Glick contended that Thursday’s ruling “perverts buyer-side market power mitigation into a series of unnecessary and unreasoned obstacles to New York’s efforts to shape the resource mix.”

Glick said the application of BSM power mitigation to entities “that are not buyers or buyers that lack market power is nonsensical. Moreover, even when applied to buyers who may have market power, mitigation must reasonably address their potential to exercise that market power.”

He argued that the commission has “abandoned” the intended narrow focus of BSM mitigation rules by no longer requiring “a resource to be a buyer, much less a buyer with market power, before subjecting that resource to buyer-side market power mitigation.”

“Buyer-side market power rules — often referred to as minimum offer price rules, or MOPRs — that were once intended only as a means of preventing the exercise of market power have evolved into a scheme for propping up prices, freezing in place the current resource mix and blocking states’ exercise of their authority over resource decision-making,” Glick wrote. “The result is an ever-expanding system of administrative pricing that is, ironically enough, justified on the basis that it promotes competition. But, in reality, the commission is not promoting anything remotely resembling actual competition.”

The “administrative pricing regimes” instead “create a systemic bias in favor of existing resources and curtail resources’ incentive and ability to compete across all possible dimensions,” he wrote.

Glick also warned that FERC’s actions to support capacity prices are encroaching on the authority of states to shape their resource mix and compromising the integrity of capacity markets, putting the future of those markets at risk.

“We got to this point largely because of the commission’s misguided belief that it must ‘protect’ capacity markets from the influence of state public policies. However, as explained below, the commission’s efforts to prop up prices by mitigating the effects of state public policies upset the jurisdictional balance that is the heart of the [Federal Power Act] and interfere with capacity markets’ ability to produce efficient market outcomes,” he said.

“The more the commission interferes with state public policies under the pretext of mitigating buyer-side market power, the more it will force states to choose between their public policy priorities and the benefits of the wholesale markets that the commission has spent the last two decades fostering,” Glick said. “Although that should be a false choice, the commission is increasingly making it into a real one.”

July 21, 2020

California Looks to EVs for Grid Resilience

The California Energy Commission asked panelists last week if electric vehicles could help in “compound catastrophes,” such as the combination of wildfires and COVID-19 outbreaks that many fear will occur this fall.

Commissioners asked: Will EVs become an effective tool to store renewable power and to discharge it to the grid when needed? Could battery-powered cars be a backup for homeowners who lose electricity during public safety power shutoffs (PSPS), the intentional blackouts now commonly used by investor-owned utilities to prevent wildfires?

The general answer was “maybe,” but only if policymakers and car buyers can be convinced to see EVs as more than just clean transportation.

“There’s a lot that can be done with EVs,” said Ryan Harty, head of connected and environmental business development at American Honda Motor Co. “It’s a very large energy storage resource that’s frankly sitting there for most of the time. If we look at where cars are parked, about half the cars don’t even leave the home in a typical day — so it’s an incredible energy storage resource that’s just waiting to be exploited for the purpose.”

The problem is, EVs aren’t legally allowed, anywhere in the U.S., to connect and discharge to the grid. That will have to change for vehicles to reach their full potential, he said. “The bidirectional capability of EVs opens up the ecosystem of possibilities.”

Customers asked to pay a premium for EVs must understand the cars’ potential to power their homes or perhaps eventually send energy to the grid in exchange for payments or credits, he said.

The discussion of EVs’ role in grid resilience took place in the first of three CEC workshops on the electrification of the transportation sector on Wednesday and Thursday. Two other workshops dealt with topics such as the role of ride hailing and self-driving big rigs in the state’s push toward 100% clean energy by 2045.

The workshops are part of the CEC’s 2020 update to its Integrated Energy Policy Report.

As with a CEC microgrid workshop July 7-9, the EV resilience session was timely because the state’s annual wildfire season is approaching. (See Fearing Wildfires, PG&E to Cut Power to 800,000.)

Microgrids for resilience are taking hold, but the use of EVs to help in disasters and blackouts remains a more remote solution.

‘100% Energy Security’

At the University of California, Davis, Honda built an experimental “smart home” in 2014 and has been using it to test the capabilities of EVs. In 2016, it began using a vehicle to provide power to the home (vehicle to home, or V2H) and, in 2018, installed technology that allowed an EV to charge and discharge to the local grid (vehicle to grid, or V2G).

A Honda report showed cars are typically parked at home or work, serving little purpose 96% of the time. The automaker intends to change that, Harty said.

“We want to improve the value of this product, not just to the customer but to society, by taking advantage of the fact that it’s there for the purpose of doing other things,” he said.

California EVs — Researchers have been testing V2H and V2G technologies at Honda’s smart home at the University of California, Davis, since 2016. | *Honda Motor Co.*

At the experimental house in Davis, the Honda EV stores 20 kWh of electricity from the home’s rooftop solar array to help power heating and cooling, cooking and hot water heating, he said. A stationary battery provides 10 kWh of additional storage.

“The home can completely isolate from the grid in the case of [an outage],” Harty said. It is “still able to charge the car … and balance itself as a microgrid, providing 100% energy security both for living and for transportation to the customer.”

He said the UC Davis research builds on resilience efforts in Japan after the 2011 earthquake and tsunami that caused three reactors to melt down at the Fukushima Daiichi nuclear power plant.

Battery Degradation

A main argument against using EVs to power homes or the grid is that repeated charging and discharging of batteries causes them to degrade more quickly. Commissioner Patty Monahan asked the resilience panel about that objection.

“Part of the reason that the automakers are not investing in this technology is … the degradation,” Monahan said. “The battery is the most expensive part of the vehicle. This is going to cause some degradation.”

Harty and others said their experiences have shown that degradation wasn’t as serious as critics suggested and could be minimized.

“We’ve studied it in depth,” Harty said. “We’ve published a couple of papers in Society of Automotive Engineers journals on the modes of battery degradation and how it relates to V2G usage.

“A couple of things the battery really hates: It really hates sitting at a very high state of charge for a long time. The battery really hates being cycled from high state of charge to low state of charge, and it hates high temperatures.”

Avoiding cycling the battery “top to bottom” repeatedly is especially important, he said.

“If you just pick a nice healthy window that you’ve established through testing of the middle of the [state-of-charge] range of the battery, and you cycle within that range, then you essentially don’t affect the long-term degradation of the battery,” Harty said.

Occasionally running a car battery to zero to power a home — for instance, to preserve food during a blackout — is OK, he said.

“It’s just like customers driving to zero range on the car,” he said. “The car’s designed to do that a certain number of times in its life.”

Panelist Bjoern Christensen, who heads Northern California advisory firm next-dimension, was formerly chief strategy officer with Nuvve, a leader in V2G technology.

Nuvve has used 10 Nissan Leaf EVs for frequency regulation in Denmark since 2016, with 240,000 hours of vehicle operation in a “very demanding application,” Christensen said. Frequency regulation in Scandinavia is relatively inflexible and must be constantly monitored and adjusted, he said.

The EV batteries have handled the task without undue damage, he said.

“We’ve been measuring the battery state of health over those four years now, and we have found no degradation that is not in line with what Nissan research has predicted,” he said. “We were very surprised that we didn’t see a lot of battery degradation. It’s something … we don’t have any problems with right now for a practical application.”

July 21, 2020October 21, 2025

Counterflow: Thank Our Heroes and Save Our Customers

Coming out of semi-retirement for two reasons.

First, to thank all our front-line utility folks who have kept electricity and all other vital utility services running through the pandemic. You’ve received little recognition, but where would we be without you?

Thanking not only everyone on the lines — our front lines — but everyone working at our generating facilities and our distribution and transmission centers to keep electricity flowing continuously 24/7. True heroes.

Con Ed workers wearing face masks | *Con Edison*

Second, every utility (and other energy provider) has an obligation to use its standard communications to customers — covering everyone in this country — to encourage the use of face masks. This is public-purpose space that costs a utility nothing to contribute to a critical public health good. And that is to encourage everyone to wear face masks.

Let’s thank our heroes and save our customers. It’s not politics. It’s the right thing to do.

July 21, 2020

FERC OKs 2 Changes from SPP’s HITT Work

FERC last week accepted SPP Tariff revisions implementing recommendations from the RTO’s stakeholders on fast-start resources and ramping products.

The commission accepted SPP’s compliance filing on fast-start pricing but directed a further compliance filing (ER20-644). It also accepted Tariff revisions creating two new ramp capability products for both ramping up and down (ER20-1617).

The proposed Tariff revisions were both included in the Holistic Integrated Tariff Team’s 21 recommendations last year. The HITT reviewed SPP’s models, processes and operations as part of its effort to integrate the expansion of renewable energy, boost reliability, and improve transmission planning and the wholesale market. (See SPP Board Approves HITT’s Recommendations.)

FERC found SPP’s fast-start pricing practices to still be unjust and unreasonable and directed another compliance filing, saying they again do not allow prices to reflect the marginal cost of serving load. The commission last year wrapped up investigations of several RTOs under Federal Power Act Section 206 and ordered SPP to eliminate inflexible operating limits and other rules that it said were preventing prices from reflecting the marginal cost. (See FERC Orders Fast-start Rules for SPP.)

SPP HITT — Fast-start units at Oklahoma Gas & Electric’s Mustang Energy Center | *OG&E*

The commission said two aspects of SPP’s proposal required further revisions. It directed the RTO to provide that, for pricing purposes, fast-start resources’ composite offers be calculated with as-committed commitment costs, regardless of the current offer.

It also ordered SPP to revise its Tariff to provide that a fast-start resource’s commitment costs will be amortized over its economic maximum operating limit and its minimum run time, striking the RTO’s use of the phrase “over an hour.” It said the revisions should provide that the grid operator will calculate the no-load cost added to each breakpoint of a fast-start resource’s energy offer curve by dividing the resource’s no-load offer by its economic maximum operating limit and by the ratio of the number of intervals needed to meet the resource’s minimum run time to the number of intervals in an hour.

FERC rejected the SPP Market Monitoring Unit’s contention that the RTO’s proposal could lead to “unmitigated economic withholding in the dispatch run, potentially resulting in unrelieved congestion and reduced reliability.” The commission found insufficient evidence in the record that the instances of economic withholding contemplated by the MMU would occur frequently enough under SPP’s proposal “to warrant additional mitigation in the dispatch run.”

The commission did agree with the MMU that SPP’s proposal presents a gaming opportunity for fast-start resources because a resource “will have the unique ability to hold its energy offer constant while changing its start-up and no-load offers, and … its composite offer.”

It found that, “on balance, eliminating this potential gaming opportunity outweighs the smaller potential for improved price formation associated with allowing fast-start resources to update their commitment offers after being committed by the market and set price for legitimate reasons in order to recover costs not otherwise recoverable in incremental energy offers.”

FERC said several other issues raised by the MMU and Golden Spread Electric Cooperative were beyond the proceeding’s scope.

SPP has 60 days to reply and must include an effective date that reflects its estimate of when development, testing and software system changes are complete.

Ramp Capability Given Go-ahead

In accepting SPP’s ramp up and down products, FERC ordered the RTO to submit an informational filing notifying the commission of the actual effective date at least 30 days before the Tariff revisions are added to the system software.

Golden Spread protested SPP’s filing, contending that it did not allow offline fast-start resources to participate in the products. The co-op also said the products would reduce the instantaneous load capacity by the amount of cleared ramp capability in a given operating interval. With the reduction, the co-op said, the instantaneous load capacity could be over-procured, leading to price distortion.

FERC agreed with the MMU, which supported SPP’s filing and said that offline resource participation would be impractical under the proposed construct. “As designed, the market clearing engine would be unable to properly evaluate or efficiently dispatch these resources,” the commission said.

Noting the MMU “commits to tracking potential issues with the demand curves going forward and recommending improvements if appropriate,” FERC encouraged SPP “to remain engaged” with the MMU and stakeholders as it gains experience with the ramp products.

Exit Fee Compliance Filing Accepted

The commission also accepted SPP’s compliance filing in a docket related to the elimination of the RTO’s exit fee for non-transmission owners (ER19-2522).

FERC in December rejected a rehearing request from SPP and its load-serving entities. It directed a compliance filing revising the RTO’s Tariff to ensure that a withdrawing non-TO is only exempt from paying a share of SPP’s long-term financial obligations and not all existing obligations associated with the member’s withdrawal. (See FERC Denies Rehearing of SPP Exit Fee Decision.)

In fully accepting SPP’s compliance, FERC rejected protests by renewable energy interests, who argued that the revisions to the grid operator’s membership agreement created “ambiguity” as to which costs would be borne by withdrawing non-TOs. EDF Renewables, RWE Renewables Americas and Savion also contended that the agreement’s provisions could be interpreted to say that withdrawing non-TOs are subject to a share of SPP’s long-term financial obligations.

The commission found that the proposed phrase “incurred by SPP directly due to the termination” requires a direct connection between the costs that SPP may recover and the membership’s termination. It said it is “reasonable” for the grid operator to recover costs it incurs directly because of a member’s termination of its membership.

FERC said the requirement that departing members pay a share of SPP’s long-term debts in the event of a partial termination does not apply to non-TO members because they “do not have load, as reflected by SPP’s proposed ‘if applicable’ language.”

The proceeding stems from a 2018 complaint by the American Wind Energy Association and the Advanced Power Alliance, which have long argued against the exit fee. (See Wind Groups Challenge SPP Exit Fee.)

July 19, 2020

RTOs Move Closer to Full Order 841 Implementation

PJM, CAISO and SPP took a step closer Thursday to the full implementation of Order 841 with FERC’s partial acceptance of their Tariff revisions.

Order 841, issued in February 2018, directed RTOs and ISOs to remove barriers to the participation of energy storage resources (ESRs) in their wholesale electric markets.

The commission accepted PJM’s compliance filing — its third in response to the order — subject to yet another revision, calling for the Tariff to state that the RTO will not charge a distribution-connected ESR for charging energy if the distributor is unwilling or unable to net out any retail energy purchases associated with the ESR’s wholesale charging activities from the host customer’s retail bill (ER19-469).

FERC said PJM did not follow the proposed language in its second order on compliance, instead filing Tariff language specifying that the provision only applies to an ESR that is “co-located with end-use load.”

“We are concerned that this language could exclude a distribution-connected energy storage resource that is not directly on the site of end-use load but nonetheless receives a retail bill because it is located behind a distribution utility meter,” the commission wrote.

The commission directed PJM to submit a further compliance filing to either clarify how its proposed Tariff provisions prevent all distribution connected ESRs from paying twice for the same charging energy or propose Tariff revisions to ensure the outcome. The RTO has 90 days to make the filing.

FERC did accept PJM’s proposal to modify its participation model to more appropriately account for an ESR’s state of charge, maximum state of charge and minimum state of charge by using bidding parameters incorporated into its day-ahead and real-time market clearing engines. It also accepted the RTO’s proposal to add Tariff definitions of bidding parameters that include: minimum and maximum charge limit; minimum and maximum discharge limit; and charge and discharge ramp rate.

The provisions in the compliance filing are effective retroactively to Dec. 3, 2019, with a limited number of revisions to become effective March 31, 2024, subject to the further compliance filing.

CAISO Compliance

CAISO also edged closer to full acceptance of its energy storage market participation rules when FERC approved nearly all the provisions included in the ISO’s second Order 841 compliance filing (ER19-468).

The commission approved CAISO’s energy storage participation model last November (becoming effective Dec. 3, 2019) but directed the ISO to:

revise its Tariff to include a “basic description” of its metering methodology and accounting practices for storage resources;
explain how the metering and accounting practices allow storage resources to participate in both wholesale and retail markets, or revise its Tariff to allow storage resources that provide retail services to also participate in CAISO’s wholesale market; and
revise its Tariff to explain that if an ESR’s host utility is unwilling or unable to net out any energy purchases associated with the resource’s wholesale charging activities from the resource’s retail bill, then CAISO would be prevented from charging wholesale rates for charging energy for which the resource is already paying retail rates.

FERC on Thursday approved of CAISO’s proposal to address the first shortcoming by creating a new Tariff section, 10.1.3.4, which describes the metering and accounting for storage resources, including provisions meant to ensure that resources avoid double-billing for retail and wholesale participation.

The section also contains an explanation that resources can elect to become either: “metered entities,” which pay higher upfront costs for a more complex certification process that helps resources avoid ongoing costs related to meter data validation and avoid certain penalties because they are being instantaneously metered by CAISO; or “scheduling coordinator metered entities,” which must comply with several initial and ongoing requirements to meet Tariff requirements but can avoid some upfront costs and are allowed to propose “unique, complex metering configurations” for ISO approval.

FERC Order 841 Implementation — Invenergy’s Grand Ridge Battery Storage Facility in Illinois | *BYD*

The commission also accepted related Tariff provisions giving both types of metered entities flexibility in how they configure their metering systems to avoid “commingling” of retail and wholesale meter data.

“CAISO states that electric storage resources — especially those that may participate in retail and wholesale markets simultaneously — have highly variable metering needs, local regulatory requirements and configurations,” FERC wrote. “CAISO states that by including simple, flexible Tariff provisions, CAISO will avoid a one-size-fits-few approach and instead be able to review each storage resource’s proposal to ensure CAISO receives settlement quality meter data for wholesale charges only.”

The only sticking point in the compliance filing: CAISO’s solution for resources unable to net out wholesale energy purchases from their retail bills. While FERC approved a proposed requirement that a host utility distribution company or retail utility verify in writing to the ISO when it is unable or unwilling to net out from its retail billing any wholesale energy purchases, the commission pointed out that the provision applies only to a “non-generating resource” (NGR), a resource type created by CAISO to accommodate market participation by resources that can both inject or withdraw energy from the grid.

“We note that this provision only applies to NGRs, and therefore does not apply to all electric storage resources, as required by the commission’s directive in the first compliance order,” FERC wrote, directing CAISO to submit a third compliance filing that clarifies the rule will apply to storage resources participating in the market as other resource types.

SPP Compliance

FERC accepted and rejected in part SPP’s second attempt to comply with Order 841, requiring yet another compliance filing within 90 days (ER19-460).

The commission found that the RTO’s proposed Tariff revisions partially complied with the order’s requirements on registering ESRs. It said it was “concerned” that SPP’s provisions requiring ESRs certify that their wholesale market participation “is not precluded under the laws or regulations of the relevant electric retail regulatory authority” could be interpreted “to include an opt-out that the commission declined to provide, which would be inconsistent with Order Nos. 841 and 841-A.”

Other than that, FERC said, SPP’s revisions describing ESRs’ metering methodology and accounting practices “provide additional guidance to market participants and appropriately reference additional documents that provide implementation details.”

SPP made its first compliance filing in December 2018. FERC last October accepted and rejected it in part, ordering a second compliance filing. (See FERC Partially OKs PJM, SPP Order 841 Filings.)

The grid operator in December asked to delay the Tariff revisions’ effective date, citing issues with software implementation and its settlement management system. The commission set an effective date of Aug. 5, 2021. It rejected a subsequent SPP request to set another date.

July 19, 2020

CAISO Edges Closer to Order 845 Compliance

CAISO moved a step closer to meeting Order 845 requirements last week when FERC accepted most Tariff revisions included in a second compliance filing after the ISO’s first attempt met a raft of rejections in February (ER19-1950).

Two inland West utilities, Public Service Company of Colorado (PSCo) and Deseret Generation & Transmission Cooperative, also nearly reached compliance with the order, which FERC issued in 2018 to amend its pro forma large generator interconnection agreement and large generator interconnection procedures to increase the transparency and speed of the interconnection process.

RTOs, ISOs and utilities have struggled to fully comply with the order, with most facing FERC directives to submit second — and even third — compliance filings. (See CAISO, NYISO, Companies Win Partial OK on Order 845.)

The commission on Thursday approved the majority of CAISO’s proposed revisions in the second round, including those dealing with:

transparency around study models and assumptions, with CAISO planning to maintain an Open Access Same-Time Information System link to a secured section of its website containing interconnection base case data;
interconnection study deadlines, with CAISO incorporating FERC’s pro forma language into its Tariff to describe how the ISO will provide summary statistics on the processing of interconnection studies;
provisional interconnection service, with the ISO removing language restricting the use of limited operation studies to instances when a transmission owner is unable to complete facilities by the interconnection customer’s commercial operation date; and
surplus interconnection service, with FERC agreeing to CAISO’s plan to rely on existing Tariff provisions to memorialize the transfer of such service.

But FERC only partially accepted a proposal outlining the ISO’s planned response to an interconnection customer’s request to incorporate a technological advancement into a project after that project has entered the queue, which could trigger the need for additional studies ahead of a final interconnection study.

While CAISO’s second compliance filing offered no revisions to the plan FERC originally rejected in February, the filing did provide additional details explaining the ISO’s approach. CAISO explained that its “material modification assessment process” enables interconnection customers to make modifications to their projects without losing their place in the queue. Additionally, the ISO offers a “permissible technological advancement process” as a faster, cheaper alternative for “simple” modifications.

“Rather than create a limited, rigid list of permissible technological advancements, CAISO created a list of known permissible advancements and allowed for any other advancements that meet CAISO’s definition of permissible technological advancement,” FERC noted.

CAISO FERC Order 845 — Wind farm near Palm Springs, Calif. | © *RTO Insider*

Under the proposed Tariff provision, customers seeking to make technological changes to their projects would need to advance CAISO a flat $2,500 fee to cover the costs of studying the impacts of the changes. The commission accepted the fee but found that the ISO had not complied with Order 845 requirements and the compliance directives in the February 2020 order “with respect to the requirement that CAISO provide a more detailed explanation of the studies that CAISO will conduct to determine whether the technological advancement request will result in a material modification and determine whether or not a technological advancement is a material modification within 30 calendar days of receipt of the initial request.”

FERC also found that the CAISO Tariff’s use of the terms “conditionally assigned network upgrades” and “precursor network upgrades” — instead of the term “contingent facilities” — does not comply with Order 845 and the February compliance directive with respect to interconnection facilities.

“While CAISO states that it will apply the terms ‘conditionally assigned network upgrades’ and ‘precursor network upgrades’ to all facilities identified in the interconnection customer’s study reports, it is unclear how these terms, which by their own names and definitions relate to network upgrades, address interconnection facilities that may also be contingent facilities pursuant to the pro forma LGIP definition of ‘contingent facilities,’” FERC wrote.

The commission directed the ISO to submit a further compliance filing within 120 days addressing the technological changes issue and how it will identify interconnection facilities that are contingent facilities “in light of the fact that the two terms with which CAISO proposes to replace the term ‘contingent facilities’ do not by definition include interconnection facilities.”

Utilities Near Compliance

The commission on Thursday accepted nearly every provision of PSCo’s Order 845 compliance filing but ordered the utility to revise its tariff to explicitly state that it will take no more than 30 days to determine whether an interconnection’s technological change request actually qualifies as a “material modification” requiring additional study (ER19-1864).

Utah-based Deseret similarly came within a hair’s breadth of compliance, with the commission ordering the co-op to specify the deposit that interconnection customers must provide to cover additional studies when submitting a technological change request (ER19-902).

July 19, 2020

FERC Tweaks Orders on Mystic Contract

FERC clarified some aspects of its orders approving ISO-NE’s cost-of-service contract with Exelon’s Mystic Generating Station and ordered the company to make additional compliance filings in three rulings Thursday.

The RTO signed the two-year, $400 million contract to preserve the region’s reliability after Exelon announced plans to shutter the plant when its existing capacity supply obligations expire in 2022.

The commission on Thursday granted limited clarifications on its July 2018 (ER18-1639-001) and December 2018 orders (ER18-1639-002) approving ISO-NE’s agreement for Mystic Units 8 and 9, including payments to the company’s Everett LNG facility. (See FERC Approves Mystic Cost-of-Service Agreement.)

Supporting the rulings were Chairman Neil Chatterjee and Commissioners Bernard McNamee and James Danly. Commissioner Richard Glick, who had opposed the 2018 orders, dissented.

In ruling on rehearing requests on the July order, the commission granted the Massachusetts attorney general’s request for clarification that Mystic must prove its capital expenditures are just and reasonable to recover their costs.

Authority over LNG Terminal Challenged

But the commission majority disagreed with contentions by the AG and New Hampshire Public Utilities Commission that FERC had asserted jurisdiction over Exelon’s Everett LNG facility — the sole source of Mystic’s fuel — by approving the power plant’s fuel costs.

“Review and approval of the fuel supply charge … can include consideration of whether it is just and reasonable for Mystic to include in its rates charges traceable to specific costs that Everett incurred and that are included in the fuel supply charge. The commission’s findings may affect or have implications for Everett but do not constitute an assertion of jurisdiction over (i.e., regulation of) Everett or Everett’s incurrence of costs,” the commissioners said. “We thus disagree with the New Hampshire PUC that the commission is proposing to regulate the rates of an LNG import terminal.”

Mystic Generating Station contract — Exelon’s Mystic Generating Station, on the Mystic River in Everett, Mass. A wind turbine owned by the local water authority to power a pumping station is on the right.

In his dissent, Glick said, “I do not believe that the commission can or should use its authority over wholesale sales of electricity to bail out a liquefied natural gas import facility. …

“Because Everett does not rely on the interstate pipeline grid to acquire natural gas (instead receiving it via ship), it can provide another source of natural gas for the region when the pipeline system becomes constrained, as may happen during stretches of cold weather when heating needs cause demand for natural gas to surge. But Everett apparently depends on its sales to Mystic to remain financially solvent, and letting Mystic retire could indirectly lead Everett to close,” Glick wrote. “It is Everett, not Mystic, that, in fact, provides the purported fuel security benefit underlying this proceeding. Accordingly, the commission has chosen to use its authority under the [Federal Power Act] to retain Mystic in order to keep Everett from going under.”

December 2018 Order

In ruling on challenges to the December 2018 order, the commission rejected concerns regarding anticompetitive behavior as beyond the scope of the proceeding.

“For similar reasons, we find that the issues raised on rehearing about market manipulation and the general functioning of natural gas and electric markets also are beyond the scope of this proceeding. Thus, the commission did not err in failing to take into account potential market manipulation as it relates to the Mystic agreement because sufficient protections exist to protect against this behavior. We reiterate that the commission will continue to monitor, as always, the New England natural gas and electricity markets during the term of the Mystic agreement for anticompetitive behavior and market manipulation.”

The commission rejected Mystic’s claim that a true-up mechanism was unnecessary to protect consumers. “We continue to find that the true-up requirement is not administratively inefficient; rather, it is appropriately transparent to render the rate just and reasonable,” FERC said.

But the commission granted Mystic’s request for clarification regarding the timing of capital expenditure projects.

Clawback Mechanism

In a third order, the commission accepted in part Mystic’s compliance filing on true-up and clawback mechanisms but required the company to make an additional filing regarding the accounting for its purchase price of the plant (ER18-1639-003). The clawback mechanism would require Mystic to refund capital expenditures if the generator chooses to continue participating in ISO-NE’s markets after the termination of the cost-of-service contract.

In a bid to extend Mystic’s contract for an additional year, Exelon last month accused ISO-NE of violating its Tariff by prematurely culling bids received in response to its Boston competitive transmission solicitation. (See Exelon Challenges ISO-NE RFP in Bid to Extend Mystic.)

July 19, 2020

OMS Continues to Press for MISO Dynamic Line Ratings

The Organization of MISO States continues to signal its grid operator that regulators are ready for dynamic transmission line ratings in the footprint.

OMS invited an ERCOT executive to explain the benefits of dynamic line ratings (DLRs) at its board of directors meeting Thursday.

ERCOT Senior Director of System Planning Warren Lasher said DLRs provide value, “especially in off-peak conditions like spring and fall, when you’re likely to see more wind on the system.”

The Texas grid operator now uses dynamic ratings in 60 to 70% of its circuits, Lasher said. He said it uses data lookup tables from transmission owners coupled with local weather data to assign ratings.

“We’ve seen a significant amount of benefits, in two ways really. … We’ve seen reduced congestion, and we’re able to get more lost cost power to our customers. But we also see in our reliability studies that we can schedule more maintenance outages in the spring and fall,” Lasher told regulators.

OMS has recently been in discussions with MISO Independent Market Monitor David Patton about implementing DLRs. OMS President and Minnesota Public Utilities Commissioner Matt Schuerger said in June that the RTO’s ratings are overly conservative, inconsistent and not transparently formed.

MISO Dynamic Line Ratings — | © *RTO Insider*

MISO TOs have also been meeting with Monitor staff to discuss dynamic and ambient temperature-adjusted line ratings, Otter Tail Power’s Stacie Hebert said last month.

The Monitor made implementing DLRs one of five new recommendations late last month in its annual State of the Market report. (See IMM Issues 5 Recs in MISO State of the Market Report.)

During this month’s Market Subcommittee meeting, Patton said the annual value of MISO’s real-time congestion routinely exceeds $1 billion, due in part to “very conservative, static ratings by most transmission operators.”

“I think more are becoming aware of this problem,” Patton said, citing last year’s FERC technical conference and OMS’ interest.

Patton said a “broad adoption” of ambient-adjusted ratings could have reduced congestion costs by as much as $150 million in 2018 and 2019. Over those two same years, had TOs just provided short-term emergency ratings, an additional $114 million could have been saved in congestion, he said.

However, Patton said he’s had little luck so far trying to convince individual TOs to use the technology.

OMS Executive Director Marcus Hawkins said the group will present a position statement in August on the subject. He said he believes MISO’s systems are advanced enough to accommodate the technology.

July 19, 2020

FERC OKs COVID-19 Waiver for MISO LMRs

FERC on Thursday approved MISO’s request for a one-time waiver giving market participants the opportunity to replace load-modifying resources affected by the coronavirus pandemic.

The waiver will permit market participants that manage an affected LMR to register new resources with MISO to fulfill capacity obligations. FERC said the temporary measure will help ensure reliability during the pandemic (ER20-2156).

“We find that the requested waiver addresses a concrete problem because, absent this waiver, market participants whose accredited LMRs will otherwise be unable to meet their performance requirements for the 2020/21 auction,” FERC said.

MISO requested the waiver in late June, saying that some LMRs that cleared the 2020/21 Planning Resource Auction may not be able to perform because of closures of businesses that would otherwise be used to control load. (See MISO Drafts COVID-19 Waiver for LMRs.) The waiver is considered effective July 15, and market participants have 90 days to register replacement LMRs.

FERC said MISO’s plan is reasonable and doesn’t carry unintended consequences for third parties. No parties protested the RTO’s request.

“The waiver will provide certain market participants affected by the COVID-19 pandemic additional flexibility to satisfy their LMR performance requirements; market participants who have registered planning resources that are not affected by the COVID-19 pandemic will not be impacted by this waiver,” the commission said.

This is MISO’s second filing for a waiver of Tariff requirements as the pandemic plays out. Some interconnection queue customers now have longer to secure proof-of-land use for their proposed generation projects. FERC granted MISO’s request for a 60-day extension of its June 25 site control demonstration deadline in May, when the pandemic locked up government offices and held up construction plans (ER20-1794).