Page 1023 – RTO Insider

November 1, 2020

Study: Western RTO Could Yield $1.2B in Yearly Savings

The creation of a single RTO covering the entire U.S. portion of the Western Interconnection could save the region more than $1.2 billion annually in electricity costs, according to the findings of a state-led study funded by the U.S. Department of Energy.

The study, an ongoing two-year effort, was initiated by the Utah Governor’s Office of Energy Development in partnership with state energy offices in Colorado, Idaho and Montana.

“The project is unique in that it provides Western states with a neutral forum and neutral analysis to independently and jointly evaluate the options and impacts associated with various market options in the West,” Brooke Tucker, deputy director of the Utah energy office, said Friday during a virtual meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Board (CREPC-WIRAB).

The study attempts to identify state-by-state savings in capacity and adjusted production costs (the net cost to serve load) under various market scenarios, including a full RTO for the West.

“From a load diversity standpoint, nobody loses” from membership in a West-wide RTO, Keegan Moyer, principal with study author Energy Strategies, said in presenting the findings to CRECPC-WIRAB stakeholders. “There’s some larger winners than others, and that’s simply due to the nature of the system and the coincident or noncoincident nature of the peaks, but we really walked away with the observation that the entire West has a lot to gain from a load diversity standpoint.”

The findings Moyer presented Friday focused on two different market constructs.

The first was the existing Western Energy Imbalance Market (EIM), with its centrally optimized real-time dispatch; separate balancing authority areas and transmission tariffs; limited transmission dedicated to market transfers; and continued operational control by transmission providers.

The second market construct was a full RTO, with consolidated BAAs and the transfer of transmission operations to a central operator; a centralized real-time and day-ahead market; joint transmission tariffs for all members within a given footprint; transmission available up to reliability limits; and joint transmission planning and cost-sharing.

The study also looked at the impacts of a third construct — the EIM with the inclusion of a day-ahead market — but that option didn’t figure heavily into Moyer’s presentation. “The day-ahead market really is an expansion on a real-time-only market, where we’re simply introducing a day-ahead optimization time frame into this market, whereas pretty much everything else remains the same. The big shift comes with the RTO framework,” he said.

The study authors then overlaid the market constructs over two different footprints to evaluate potential “market configurations”:

a “status quo” scenario consisting of an EIM that includes both existing members and those entities that had committed to joining the market by the end of 2019;
a “one market” EIM expanded to include the entire U.S. footprint of the Western Interconnection; and
a West-wide RTO covering the same footprint.

The analysis examines the market configurations from the perspective of both capacity and production cost savings based on 2020 resource portfolios. Moyer noted the analysis did not attempt to capture other potential benefits. “There are some efficiencies from competition that we’re not really getting at,” he said.

Load Diversity is Key

Moyer explained that capacity benefits in the full RTO scenario flow from “load diversity” — the notion that different areas of the Western system peak at different times, “whether that be an hour or two apart or perhaps seasons apart.”

“In the absence of any kind of coordination, we assume each balancing area will require sufficient capacity to meet its peak plus some amount above that, roughly commensurate with a reserve margin,” he said. “However, the coincident peak demand for a combined footprint of those same balancing areas would typically be less than the sum of the individual peaks.”

The overall reduction in peak load counted across the interconnection would allow load-serving entities in an RTO to build or contract for less capacity to meet resource adequacy requirements, the study assumes.

Those reduced needs add up. The study found that under the status quo, the region can expect to realize up to $25.2 million in annual capacity savings, while a “one market” EIM could yield up to $47.8 million in savings. An RTO boosts the potential capacity savings tenfold to up to $478 million.

But the biggest economic gains from an RTO flow from adjusted production cost (APC) savings, according to the study. Moyer called APC the “primary metric for determining state benefits” because it captures the benefits and costs of both net sales and purchases within an area, whereas a simple production cost figure can “mask some of the benefits” for high-export areas that ring up higher production costs that are also offset by sales into the market, reducing net costs to serve native load.

“It’s important to consider this metric instead of others that we have available to us,” Moyer said.

Based on that metric, an expanded EIM would yield about $105 million to $127 million in annual APC savings — on top of the existing EIM benefits of more than $300 million a year — compared with the status quo scenario. Arizona, Washington and California lead in absolute benefits under that scenario, while four states — Oregon, Nevada, Montana and Utah — actually lose out (see graphic below).

Western RTO — Arizona, Washington and California would gain the most from an expansion of the EIM into the entire U.S. portion of the Western Interconnection, according to the study. | *Energy Strategies*

By comparison, a full RTO would produce APC savings of $811 million, bringing the estimated total savings from an RTO to more than $1.2 billion (see graphic below). Washington would be the biggest winner at $324 million, followed by California ($303 million), Arizona ($209 million), Oregon ($106 million), Colorado ($95 million), Idaho ($53 million), New Mexico ($52 million) and Utah ($48 million). Fewer benefits would flow to Wyoming ($29 million), Nevada ($23 million) and Montana ($21 million).

Moyer attributed part of Washington’s large benefit figure to an increased value of the Pacific Northwest hydroelectric system, “just from a simplified energy revenue standpoint.”

He also pointed out that the state would shift from a winter to a summer peak under a consolidated RTO scenario, “so there’s a savings really kind of embedded in that shift” because of the load diversity effect, he said. The study found that Washington would realize more than 4,000 MW in capacity savings from its load diversity relative to the rest of the footprint. Meanwhile, its summer-peaking neighbor to the south, Oregon, would see a capacity benefit of slightly more than 1,000 MW.

Adoption of either market configuration would result in only minor reductions in Western CO2 emissions: 0.1% for the expanded EIM and 0.7% for the RTO. The study’s findings also indicate only slight changes in the types of resources being dispatched under both configurations, at least based on current generation fleets.

“Overall, the big finding here is that, at least in 2020, we don’t believe that market constructs or these incremental constructs that we’re modeling cause major shifts between generation types,” Moyer said. Instead of a major shift from coal to gas, the study finds shifts within each class of generator, with the most efficient being dispatched.

“And [in the RTO scenario], we’re doing a little better job of integrating renewables, and on aggregate, those efficiencies are causing emissions to decrease somewhat, but not a significant amount,” Moyer said. He added that renewable curtailments are low under either scenario but were “already low to begin with.”

The study showed a shift in transmission flows, Moyer said, “but not significant enough to cause congestion.”

By the States, for the States

“I think the state-specific results are really helpful,” said Oregon Public Utility Commissioner Letha Tawney, who is also the chair of the EIM’s Body of State Regulators (BOSR). “We often see results that are for a particular utility, or a particular balancing area, or across all of the WECC … and we’re left with making assumptions about what that means for our consumers in our states.”

The state-by-state breakdown of benefits gives each state a “fact set” for approaching increased regionalization, with the states enjoying more obvious benefits being less concerned about the costs of joining an RTO.

“We all care about costs — don’t get me wrong — but there’s more room for a cost-effectiveness test if the benefits are clearly demonstrated in a single direction, where a state that’s running a little closer to a cost-benefit analysis break-even point might be more conservative,” Tawney said.

Washington would earn the greatest capacity benefit from membership in an RTO because of the fact that it would move from being a winter-peaking system to being a member of a summer-peaking system. | *Energy Strategies*

As chair of the BOSR, Tawney said, she seeks to identify a consensus view around CAISO processes, “and this sort of study that’s so neutral and sort of lays out the state perspective … is really enormously helpful in understanding how differently states are experiencing the market today and what value their consumers can really find in it.”

Tawney noted the study’s finding that the market is not “inherently” changing the resource mix in the West.

“It’s being driven, as far as the models demonstrate, far more by customer choices, and those customer choices might be demonstrated to the market through either voluntary commitments or through legislative actions or in-state carbon prices,” she said.

Tawney said she looked forward to the findings of the next iteration of the study, which will examine 2030 projections that “layer in the customer choices that have been expressed.”

“What I think this [study] clarifies is that the market makes reaching state clean energy goals more efficient, particularly less costly, rather than explicitly reshuffling the deck automatically,” she said.

Keith Hay, director of utility policy for the Colorado Energy Office, said the study comes at an “interesting time” when his state is undergoing an energy transition and its public health authority is calling for an 80% reduction of carbon emissions below 1990 levels by 2030, compared with the current 70% goal.

“I think for us as a state, it’s helpful that one of the outcomes of this work will be a set of factors that states might want to consider as they look at their market orientation,” Hay said. He noted that previous discussions at the Colorado Public Utilities Commission about whether to join an organized market prompted questions about how to make the decision, given the different factors stakeholders asked the state to consider.

“I think it’s important as this study comes forward, we’ll learn a lot from the perspective of the state and the state commissions, so it’s not being driven by a utility or a particular set of stakeholders who may have an interest in the outcome,” Hay said.

November 1, 2020

Overheard at ACE NY Fall Conference 2020

Actor and anti-fracking activist Mark Ruffalo and former EPA Administrator Gina McCarthy, now CEO of the Natural Resources Defense Council, headlined the Alliance for Clean Energy New York’s (ACE NY) annual Fall Conference Wednesday. Here are some highlights of what we heard.

Taking Action

In her keynote address, McCarthy said the climate battle being waged in the country is “a fight for our lives” and the future of the planet. She said people concerned with the environment need to raise their voices together to demand action.

The good news, McCarthy said, is that solutions exist to deal with climate issues, and one of the biggest answers to the problem is clean energy. She said the conversation around clean energy needs to continue and expand because initiatives are taking off at a greater pace at the state and local level because of the economic, health and quality of life benefits they provide.

McCarthy said she is particularly excited by the opportunities for the development of offshore wind on the East Coast, and a next step in the green energy revolution is to have federal leadership that will act on a national level.

“We need to turbo-charge the transition to clean energy nationwide,” McCarthy said. “And while there’s no substitute for federal leadership, there is no way that any of us are going to wait for Washington to wake up.”

ACE NY — Gina McCarthy, NRDC | © *RTO Insider*

With the current political climate, McCarthy said now is not the time to be “morose” or to sit and wait for things to happen regarding clean energy. She said there needs to be a “doubling-down effort” on building local and grassroots momentum across the country to “tip the scales” away from fossil fuels.

McCarthy said what has made New York a leader on climate initiatives was the passage of the Climate Leadership and Community Preservation Act (CLCPA) in July 2019. The CLCPA requires that 70% of electricity come from renewable resources by 2030 and that electricity generation be 100% carbon-free by 2040. Clean energy targets include deploying at least 9 GW of offshore wind energy by 2035, doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025. (See Cuomo Sets New York’s Green Goals for 2020.)

The time for action and implementation of the CLCPA is now, putting it to work to transform the transportation sector and the power sector and modernize the electric grid, McCarthy said, adding that action on clean energy means many well paying jobs will be created.

“Progress is happening here, and if you can do it and show the way, then progress will happen all across the nation,” McCarthy said. “And it won’t matter if it’s red or purple or blue. Every state will want a piece of the action.”

Hulk Talk Green New York

Ruffalo, the award-winning actor and a resident of New York, said he’s been a longtime advocate for clean energy and addressing climate change as he spoke in a short video presented at the conference. He said ACE NY has been hard at work for years, helping the state adopt one of the most aggressive climate acts in the country.

The actor said ACE NY has embarked on an “ambitious” study of the transmission system to make sure it can handle all the renewable energy set to come online. He said the organization has played a leading role in making a clean energy future possible in the state and helping to reach the renewable energy generation goals laid out in the CLCPA.

New York has the chance to be “the greenest state in the nation,” Ruffalo said.

“Trust me, I know a little bit about going green — dad joke,” Ruffalo said, referencing his role as the Hulk in the Marvel Cinematic Universe franchise of superhero movies.

Building the Offshore Wind Industry in NY

In a discussion on building New York’s offshore wind industry, Nathanael Greene, senior renewable energy advocate for NRDC, called for “rigorous pre- and post-construction monitoring” to protect wildlife and fish habitats, which he said the Department of the Interior’s Bureau of Ocean Energy Management is not requiring.

“The data from good monitoring will tell us what needs to be protected and if the companies’ mitigation measures are working. Ultimately, it makes protections more cost effective,” he said. “But we can’t do pre-construction monitoring and develop baselines after the fact. We need developers to step up and include detailed monitoring plans in their [construction and operations plans] until BOEM starts requiring them.”

Greene also criticized FERC’s buyer-side mitigation requirements, saying they are undermining New York’s clean energy efforts. “And now some want to expand buyer-side management so that it’s statewide, which would make a bad policy terrible,” he said. “It’s time we took seriously the alternatives to the capacity market and take steps necessary so that New York voters, our elected and appointed officials determine our resource adequacy, not the fossil fuel agenda of ideologues at FERC. The makeup of FERC may change following the election, but until the feds catch up with New York’s climate leadership, we may have no choice but to take charge of our own power mix planning.”

Adrienne Downey, principal engineer for offshore wind for the New York State Energy Research and Development Authority, said New York’s pledge to build 9 GW of OSW, as well as the targets by neighboring states, have gotten the attention of Asian and European investors.

“We are seeding an incredible opportunity here. Right now, [for] the earliest projects, the lion’s share of jobs are clearly in the construction and installation phase [and] in the operations and maintenance phase, which is 25 years.

“We want to expand that to see manufacturing start to happen. So, what we would anticipate is we’ll start to see the components that are probably the most logistically flexible … so we might see towers [and] foundations. We’re anxious to start seeing deeper manufacturing come as we advance our target deeper toward 9 GW to things like blades. The holy grail would be full turbine assembly.”

Dominik Schwegmann, head of offshore development for RWE Renewables Americas, said manufacturing will only come to the U.S. “if the offtake for these components is there; if the market has the size; if the project pipeline … is predictable and reliable for the manufacturers to say, ‘Yes, I [will] invest [a] couple hundred million dollars and do investments in the training of the workforce. … The [U.S.] market has enough … potential to justify that, just as in Europe.”

Joe Martens, director of the New York Offshore Wind Alliance, noted that the U.S. hasn’t completed the permitting for any commercial-scale OSW yet.

“I think that once there is a clear signal from Washington, then I think we will see some significant investment in other components that right now are not manufactured in the U.S. come to the U.S. And that will be an exciting moment.”

YIMBYs

ACE NY named Win With Wind, a group of private citizens on the South Fork of Long Island, winner of its 2020 Clean Energy Advocate award.

Martens said the group, which seeks to generate grassroots support for and combat misinformation against offshore wind, is “motivated by their simple and sincere desire to see their communities in the forefront of clean energy leadership.”

“There is no place more vulnerable to climate change than Long Island,” he added. “Rising sea levels and ocean acidification, in particular, are a direct and immediate threat.”

Cate Rogers, a member of the group’s steering committee, accepted the award. Rogers said she and another activist, Judith Hope, started the group in 2018 to counter disinformation on the South Fork Wind Farm, a 15-turbine project that Ørsted will build wind 35 miles off Montauk.

After organizing the group, Rogers said, she learned “that an overwhelming majority of people in our community supported the project and the transition to renewable energy. They just needed to be given the facts, have some questions answered and understand that we have shovel-ready solutions at hand. … But without a place to gather, a group with which to connect, they could remain the silent majority and, even worse, fall victim to misinformation and scare tactics and take up the mantra we often hear: ‘I support renewable energy, but not this project.’”

After the award presentation, ACE heard from Betta Broad, director of New Yorkers for Clean Power, which supports electrification and renewable generation. Broad said the group’s goal is “creating more YIMBYs — that’s ‘Yes, in my backyard.’”

November 1, 2020

Study: Storage Can Replace 53% of LIPA Peakers by 2030

The Long Island Power Authority (LIPA) could replace more than half of its aging and rarely used fossil-fueled peaker plants with energy storage by 2030, saving ratepayers almost $400 million, according to a study released last week.

The report by consulting firm Strategen, prepared for the New York Battery and Energy Storage Technology Consortium (NY-BEST), said “it is feasible and cost-effective” to replace 1,116 MW of peakers by 2023 and more than 2,300 MW by 2030. It said LIPA frequently dispatches the 4,357 MW of peaker units on the island uneconomically and for reasons other than meeting peak-load needs.

In addition to saving customers more than $390 million in net present value over the next 10 years — about $360 per household — the study says swapping peakers with batteries would significantly reduce harmful air pollutants.

“The whole framing of this is that New York has the goal of getting to zero emissions by 2040 … so we need to start on that path with what we can do now,” Edward Burgess, lead author of the study and a senior director at Strategen, told RTO Insider.

Strategen, based in Berkeley, Calif., estimates that the peaker fleet is costing Long Island ratepayers approximately $473 million annually just for capacity — three times the market rate for capacity resources cleared through NYISO’s competitive markets — and that if it is not replaced, the cost could increase to $716 million by 2030. (The study identifies as peakers those plants with an annual capacity factor of 15% or less; it says about 3,053 MW of the capacity operated 10% or less of the time, while 36 units (1,249 MW) ran less than 1% of the time in 2019.)

A 15-year power service agreement (PSA) between LIPA and National Grid that runs to 2028 accounts for the bulk of these costs. The PSA is for 3,634 MW, 90% of which are for peaking plants.

LIPA spokeswoman Jen Hayen told RTO Insider that LIPA will be issuing a request for storage proposals in the next several months that may result in the replacement of certain Long Island peaker or steam plants and will evaluate the proposals it receives compared to the costs of the existing units.

“LIPA has already announced the retirement of 68 MW of peaker plants in 2020 and 2021 and has an ongoing study for the retirement of an additional 400 to 600 MW of steam and peaker plants in 2022. We anticipate additional retirements in 2024 and beyond,” Hayen said.

She challenged the study’s savings estimates, saying they “are higher than we have experienced in either deploying storage or retiring existing plants.”

“In classifying low-usage steam plants as ‘peaking plants,’ the study overstates the potential savings in fixed costs, much of which are prior capital costs that must be paid to the plant owner at the time of retirement,” Hayen said. “Moreover, the study assumes that future storage discharge requirements can be determined from past peaker operation, which does not reflect the significant system changes that will be occurring.”

Uneconomic Dispatch?

The study’s claim that the peakers are frequently dispatched when they are not economic is based on the 2019 NYISO State of the Market report by the ISO’s Market Monitoring Unit, Potomac Economics. It said out-of-merit “dispatch was frequently used to manage 69-kV constraints and voltage constraints (i.e., transient voltage recovery requirement on the East End of Long Island).”

In addition to using peakers to resolve local transmission problems, LIPA generally does not coordinate their dispatch with NYISO, so the actions are not optimized through the ISO’s day-ahead and real-time market software, the study said. The result is often depressed locational-based marginal prices that send inaccurate price signals for potential future investment and require millions of dollars in uplift charges.

“The proportion of hours where out-of-merit actions were taken to resolve congestion issues (versus times when the market was used to resolve these) were quite significant throughout Long Island and are more pronounced in certain locations,” the study said. “For example, in the Brentwood area, 99% of congested hours in 2019 were managed through out-of-merit actions rather than through the [day-ahead] and [real time] markets.”

The MMU’s 2019 report also noted that NYISO has said that issues frequently arise because of lack of coordination between the ISO and LIPA regarding the scheduling of phase angle regulators to manage congestion. Under state law, LIPA is generally exempt from the New York Public Service Commission’s jurisdiction.

An Evolving Grid

The study notes that the percentage of the peaker fleet on Long Island (Zone K) needed to meet peaking needs has declined in recent years, from 71% in 2016, to 67% in 2017 and 64% in 2018. Whether that decline continues, Burgess said, will depend not only on the peakers, “but also [on] what’s happening on the load side.”

“On the one hand, maybe we have increasing demand from electrification, but on the other hand, maybe there’s more distributed solar or energy efficiency,” he said.

Other generation on the system is also a factor, he continued. “Are we using more of the recently installed combined cycle units because gas is cheap? That certainly would be an interesting thing to look into further and see how those trends have gone over a longer period of time,” Burgess said.

The state’s Climate Leadership and Community Protection Act (CLCPA) calls for at least 9 GW of offshore wind energy by 2035, and 6 GW of that will likely interconnect onto Long Island by 2030. The CLCPA also targets 6 GW of distributed solar generation by 2025, 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025.

The study mentions that the iconic Ravenswood peaker plant on the East River in New York City is being converted to a 318-MW energy storage facility.

Asked why such conversions aren’t happening on Long Island, Burgess said, “Definitely there’s a need for local generation capacity in New York City [Zone J]. There’s also a need for generation on Long Island too. I believe part of the rationale for that is that [at Ravenswood], we have a site with an interconnection and it’s all ready to go, and New York City is even more constrained in that sense than Long Island is.”

One of the values of storage is its ability to perform functions in addition to substituting for generation, he noted. “Storage can also be a load; it can absorb energy,” Burgess said. “Perhaps down the road when we have a lot more renewables on the system that’s going to be a necessary function too, if you have oversupply of wind or solar at a certain time. And there’s all the different ancillary services it could provide too: balancing functions [and] ramping up and down in very quick succession.”

Of the 2,300 MW of fossil peaker plant replacements, 334 MW could be retired and replaced immediately, and in the East End of Long Island, there is a near-term opportunity for up to 90 MW of fossil peakers to be displaced with storage, the study said.

Burgess said some peakers will likely retire because of the state Department of Environmental Conservation’s (DEC) regulation limiting nitrogen oxides (NOx) emissions from simple cycle combustion turbines. The department required all impacted plant owners to file compliance plans by March 2, 2020. The phased approach goes into effect May 1, 2023, and limits emissions to 100 ppm, dropping two years later to 25 ppm for units using gaseous fuels and 42 ppm for units burning liquid fuels. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)

Because of “the NOx regulations that the DEC put out … some of these plants without the pollution controls will have to either be making retrofits or retiring,” Burgess said. “We’ve also got decisions that LIPA is going to have to make around contracts and the current power supply agreement that they have with National Grid. … There are provisions that would allow them to ramp down a portion of that.

“And there are a lot of inefficiencies that we’re seeing here in how some of these plants are being operated. There are some economic benefits to be gained, so that’s another driving factor, along with the environmental,” he said.

Replacing peakers with storage will eliminate 2.65 million metric tons of CO2, 1,910 tons of NOx and 639 tons of SO2 of emissions annually, resulting in societal benefits of $163 million annually through fewer pollution-related deaths and hospital visits, according to the study.

November 1, 2020February 12, 2025

NYISO Reviews Fuel Security, Mitigation Project

NYISO told stakeholders last week that its fuel and energy security (FES) metrics remain “well aligned” with the assumptions of Analysis Group’s November 2019 study, which concluded that the state’s grid is “currently well equipped to maintain reliability in the winter, even under adverse winter system conditions.”

Although the report concluded “only fairly severe and relatively low probability conditions or events would create meaningful reliability challenges,” it said the ISO should continue monitoring because of the transition of its resource fleet and the increasing reliance on natural gas and renewables.

In April, NYISO pledged to update the metrics at least twice a year and said the study will be “refreshed” if the ISO observes large deviations between actual conditions and the conditions assessed in the study. A refresh also could result from large differences between the study’s assumptions and actual conditions that could adversely affect reliability. (See NYISO Launches Fuel Security Effort.)

An example of enhanced monitoring tools shows stored energy and required storage draw and margin (MWh). | NYISO

The ISO uses 23 metrics to monitor fuel security, including the deployment of new renewable and clean energy resources; the impact of the state Department of Environmental Conservation peaker rule; gas-only generator outages because of lack of fuel; and the status of transmission upgrades such as the AC Transmission Projects and Western NY Public Policy Transmission Need.

“We were aiming to enhance monitoring by adding some elements related to fuel security to both the Winter Capacity Assessment and the cold-weather operations presentations, those occurring in the fall and the spring,” market design specialist Amanda Myott told the Installed Capacity/Market Issues Working Group.

The ISO also is working to improve the accuracy of its generator fuel and emissions reporting (GFER) surveys, which inform internal FES assessments.

The fuel security monitoring “is focused on severe cold-weather conditions and being able to meet winter peaks in those conditions,” Vice President of Operations Wes Yeomans said.

On compensating for the intermittency of renewable resources, Yeomans said, “At other times of the year, we might have a duration of low wind or clouds; we are certainly aware of that and have other processes we’re trying to enhance with market designs and even some good work setting up the [installed reserve margin] with” the New York State Reliability Council.

In response to a recommendation that the ISO consider comparing actual conditions and operating experience to the conditions assumed in the FES study, Yeomans noted that winter 2019/20 was “extremely mild.”

“But if there is a cold snap this upcoming winter, it will be very important to look at what we assumed about gas availability for the generator fleet and the actual availability experienced,” he added.

CMR Project Treads Water

NYISO is pausing its Comprehensive Mitigation Review (CMR) project until it receives further clarity from FERC, which rejected the ISO’s proposal to make it easier for public policy resources to clear its capacity market, Michael DeSocio, director for market design, said in an update.

The project’s objective is to modify the capacity market framework while preserving competitive signals and facilitating the state’s ambitious clean energy goals. CMR efforts this year included the ISO’s proposed renewable exemption limit and changes to the Part A test for exempting resources from market mitigation.

In July, FERC approved the renewable exemption limit formula for calculating a megawatt cap of renewable resources exempt from buyer-side market power mitigation (BSM) specific to each mitigated zone. (See NYISO BSM Mitigation Ruling Sparks Glick Rebuke.)

NYISO’s buyer-side mitigation rules cover New York City and zones G-I. | NYISO

But the commission rejected the Part A changes on Sept. 4, prompting a dissent from Commissioner Richard Glick and an Oct. 5 rehearing request by the ISO (ER20-1718-002). (See FERC Rejects NYISO Bid to Aid Public Policy Resources.) Rehearing requests were also filed by Equinox, New York Transmission Owners and jointly by the New York State Energy Research and Development Authority and Public Service Commission.

“The ISO still thinks that the proposal is an excellent one that makes a whole lot of sense,” DeSocio said. “FERC unfortunately didn’t see it exactly the same way.”

The ISO’s BSM rules require new ICAP resources in New York City and zones G-I to offer at or above the default offer floor. To win an exemption from mitigation, a new entrant must pass one of two exemption tests. Part A allows exemptions if the forecast of capacity prices in the first year of a new entrant’s operation is higher than the default offer floor. Part B permits exemptions if the forecast of capacity prices in the first three years of a new entrant’s operation is higher than its net cost of new entry (CONE).

DeSocio said ISO officials are considering a suite of options, the first being contractual models such as CAISO’s, with an energy-only market and fixed resource requirement.

The second option is enhancements to the capacity market such as to BSM, available capacity transfers and a future clean capacity requirement. The third option is a redesign of the capacity market, with possibilities such as a “multiple value pricing” model that co-optimizes over several variables (e.g. specific to resource type, zero-carbon resources, etc.) and a Forward Clean Energy Market to procure a certain percentage of generation from qualifying renewable resources.

The combination of the renewable exemption limit and the BSM proposals addressed many of the concepts being considered in the proposal for available capacity transfer (ACT) — expanding the use of the renewable exemption bank — and CRIS+, the pairing of transferable capacity resource interconnection service (CRIS) rights with an existing resource’s BSM exemption.

“We’re recommending to put [ACT and CRIS+] on the shelf until we get clarity on the Part A revisions that we filed earlier this year,” DeSocio said.

In the meantime, the ISO wants stakeholder feedback on capacity market changes and any other ideas before moving into 2021, he said.

“As we add more renewable resources and more limited-duration resources in the future, that will change how we approach reliability, and that does have an impact on the role of the capacity market,” DeSocio said.

The ISO will likely be more focused on BSM and how that impacts state policies and the design of the capacity market, and how the capacity market supports resource adequacy, he said.

“It’s a broad conversation, and if folks have ideas on how to structure that, I would certainly be willing to listen, because these markets are pretty complex, and as you tug on one area, it affects another area,” DeSocio said.

November 1, 2020

FERC OKs More Rigorous MISO Capacity Requirements

Conventional capacity resources in MISO will now have to prove full deliverability before collecting maximum capacity credits, FERC said last week.

The commission on Oct. 27 approved the RTO’s proposal to require capacity resources to demonstrate deliverability through firm transmission service up to installed capacity (ICAP) levels before they can convert their entire unforced capacity (UCAP) into zonal resource credits (ER20-1942).

MISO said procuring firm transmission remains optional for capacity resources, provided that they are comfortable with settling for fewer capacity credits based on their partial ability to deliver. The RTO said it plans to prorate credits. Staff have previously acknowledged that it may be expensive for some resources to secure firm transmission service up to their installed capacity levels.

The RTO used to allow capacity resources to demonstrate full deliverability based on UCAP levels — something its Independent Market Monitor has long called inconsistent with the assumptions used in the grid operator’s loss-of-load expectation (LOLE) study, which assumes that all capacity resources are fully deliverable.

Before, MISO’s Tariff required capacity resources to demonstrate capacity deliverability by having network resource interconnection service, which stipulates that the entire ICAP of the resources must be deliverable. However, the Tariff also allowed resources to demonstrate deliverability by securing energy resource interconnection service and procuring firm transmission service up to their UCAP levels, which tend to be about 5 to 10% below full ICAP levels.

FERC agreed that the second option needed to be eliminated for the sake of reliability and accurate reserve margins.

“MISO has demonstrated a disparity between its LOLE study assumptions and the deliverability requirements associated with conventional capacity resources used to satisfy MISO’s reserve requirements,” the commission said. “As MISO explains, the LOLE analysis, and therefore the resultant reserve margin and reserve requirements, assumes that a conventional capacity resource can deliver its full installed capacity level of output when it is online. Therefore, we find reasonable MISO’s proposal to require all conventional capacity resources that seek to participate in MISO’s resource adequacy construct at their full unforced capacity levels to demonstrate deliverability up to their installed capacity levels. In doing so, MISO’s proposal will provide certainty that MISO’s reserve requirements are satisfied by fully deliverable planning resources, thereby ensuring that MISO meets its reliability needs.”

November 1, 2020

NYISO Management Committee Briefs: Oct. 28, 2020

The NYISO Management Committee on Wednesday endorsed a technical fix to the 2017-2021 capacity demand curve reset (DCR) to address an error in the model used to estimate net energy and ancillary services (EAS) revenues for the hypothetical peaking plant.

The problem resulted from a misalignment of natural gas prices. The model assumed that index prices published by S&P Global represented the “trade day” — the day before generators take delivery and use the gas to produce electricity. In fact, the data actually represent the “flow day” prices.

The error was discovered during work on the net EAS model for the 2021-2025 DCR, and the change will apply to that period as well. (See NYISO Management Committee Briefs: Sept. 23, 2020.)

NYISO already submitted the change to FERC, which approved it on Oct. 22 (ER21-130). “We have implemented the revised reference prices into the capacity market [and] spot market auctions,” Vice President of Market Operations Robb Pike said.

Pike said the ISO would submit an informational filing to FERC to provide notice of the MC’s concurrence with the previously filed revisions.

The 2017-2021 DCR includes the capacity demand curves for the 2017/18 through 2020/21 capability years (May 1, 2017, through April 30, 2021).

2020 Reliability Needs Assessment OK’d

The MC unanimously approved the 2020 Reliability Needs Assessment (RNA), which cut the peak load forecasts for 2020-2028 by as much as 467 MW from the 2018 RNA. If the Board of Directors approves the revisions in November, NYISO will file the changes with FERC.

Laura Popa, manager of resource planning, presented the 2020 RNA, which examines needs over the coming 10 years. The presentation included a transmission analysis supplied by Keith Burrell, manager of transmission studies.

Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit, presented comments on the RNA and said the MMU found a number of areas where the reliability needs identified by the RNA are in part driven by gaps in the market design, where it fails to provide incentives for resources.

Some key findings that the MMU focused on included a number of base case transmission violations from 2024 to 2030 in New York City driven by impending peaker retirements and load growth, he said. The state Department of Environmental Conservation last year adopted a regulation to limit nitrogen oxides (NOx) emissions from simple cycle combustion turbines, or peaking units, and required all impacted plant owners to file compliance plans by March 2. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)

The RNA found transmission security violations on Consolidated Edison’s non-bulk power transmission facilities system in the Astoria East/Corona as well as Greenwood/Fox Hills load pockets, rising to 180 MW in 2030 for the former and 370 MW for the latter.

It “also found transmission security violations on Con Edison’s bulk system, and the deficiency there rises to 1,075 MW by 2030,” LeeVanSchaick said. “[The RNA] also found resource adequacy violations beginning in 2027, but it’s notable that the compensatory megawatts needed to resolve those are much lower than for the transmission security violations … being only 350 MW by 2030.”

The two significant takeaways are Astoria East/Corona and Greenwood/Fox Hills, as well as the “big difference” between the compensatory megawatts needed in the transmission security analysis versus those in the resource adequacy analysis, he said.

“This RNA reveals a number of ways in which the NYISO market design fails to reflect the value of resources that help satisfy transmission security needs, which may lead to [reliability-must-run] contracts and other regulated transmission investment. The first recommendation that would help to align market signals with the reliability value of resources is better reserve market pricing in New York City,” LeeVanSchaick said.

The second issue is lining up the capacity accreditation with the reliability value of resources in NYISO planning studies, particularly for the large units and special-case resources, LeeVanSchaick said. Finally, the RNA is another piece of information that supports enhancing locational capacity pricing with the “C-LMP” framework, which would allow the ISO to set different prices for different areas and, in turn, for more cost-effective capacity to meet reliability needs, he said.

“If you do those things, it’s much less likely that you’d have to make any further out-of-market investment,” LeeVanSchaick said.

NYISO will seek updates to local transmission owner plans and other resource and load changes in December and determine in January whether the needs should be adjusted and solutions solicited to the remaining needs.

2021 Budget Approved

The MC also approved a draft budget for 2021, which will go before the board for final approval in November.

Alan Ackerman of Customized Energy Solutions, chair of the Budget and Priorities Working Group, presented the draft budget, which was unchanged from the draft stakeholders reviewed last month.

For the second year in a row, NYISO is proposing a decrease to the budgeted revenue requirement, with the draft budget allocating $167.4 million across a forecast of 147.3 million MWh, for a Rate Schedule 1 charge of $1.137/MWh, down from the 2020 budget of $168 million allocated across 154.3 million MWh ($1.089/MWh).

Wentlent Elected 2021 Vice Chair

The MC elected Christ Wentlent to serve as its vice chair for 2021, beginning in December.

Wentlent represents the Municipal Electric Utilities Association and New York Municipal Power Agency as liaison to both NYISO and the New York State Reliability Council.

He was unable to attend the meeting, but he sent a message read by Chair Jane Quin. “We all know our energy market is at a major transition point, and I would be honored to assist the NYISO and its stakeholders with that transition,” he said.

November 1, 2020

MISO, SPP Heads Present Unified Front on Seams

The heads of MISO and SPP stood on common ground to discuss seams issues during last week’s Organization of MISO States’ annual meeting.

The CEOs’ unified front during the virtual conference Thursday was a striking change from the executives’ past reticence on seams matters.

MISO CEO John Bear acknowledged that both RTOs are “struggling” with their renewables-packed interconnection queues.

“We’ve really built our systems out from our footprint perspective,” he said, explaining that MISO and SPP have developed renewable generation near the seams, sometimes disregarding the congestion the projects can cause on each other’s systems. He said in some cases, seams congestion has been neglected to the point that an interconnecting generator is “looking over a cliff” of interconnection expenses.

Bear said he and SPP CEO Barbara Sugg agreed that they needed to perform studies on the most congested areas.

The RTOs announced in September that they will partner on a special study focused on transmission projects that can bring more of the interconnection queues’ renewable generation online. (See MISO, SPP to Conduct Targeted Transmission Study.)

“Look, we’re fighting the same battles,” Sugg said. “And I think the only way you’re going to get a little is to give a little. We’re 100% confident we’re going to produce some really good results. We do share some of the very same pain points.”

MISO SPP seams — MISO CEO John Bear | *OMS*

Sugg said cost-allocation discussions are not atop the agenda as the RTOs probe possible cross-border interconnection solutions.

“If somebody wants to talk to us about cost allocation in April, we won’t talk about it,” Sugg said, noting that it’s important to keep potential bickering over costs out of an initial search for helpful projects.

“Look, we’re going to have our differences in the future, but I think we’ll be able to keep it out of FERC. I’m optimistic,” she said.

Bear said that MISO-SPP relations have improved by “assuming noble intent on the other side” and having empathy for each other’s challenges.

“At the end of the day, we are businesses competing with each other, but there’s value in being partners,” Sugg said.

Bear said seams management has long been MISO’s modus operandi. When it began its energy market in 2004, MISO had to accommodate PJM member Commonwealth Edison in Chicago, which became an island within MISO’s footprint.

“We’ve had to learn about seams very fast and furiously,” he said.

Sugg said that as the two RTOs expand their footprints, seams arrangements must adjust with every new membership.

“Growth is a fantastic thing … but it definitely makes the seams discussions continue to evolve. It definitely is an ongoing challenge, but one that is worth every minute of effort,” she said. There’s a better appreciation today among regulators of the energy markets’ complexity, she continued.

Sugg said wind is poised to beat out coal this year as SPP’s most used fuel source, a milestone that will come earlier than expected.

“There are so many wind-rich areas in SPP and such clamoring … for energy produced from a renewable source,” she said, noting a “robust transmission system” will be necessary to support the demand for renewables.

Bear said MISO’s own ballooning renewable portfolio has prompted a rethink of its current resource adequacy construct that focuses on a summer peak. Bear said the RTO has a significant loss-of-load risk in some hours in shoulder periods.

“[It’s] so we don’t kid ourselves that we’re reliable in every season, even though some hours might go unserved,” he said.

Sugg predicted FERC Order 2222 — which directs RTOs and ISOs to develop participation models for distributed energy resource aggregations — will have a “humungous” effect on grid operators. (See FERC Opens RTO Markets to DER Aggregation.)

“It’s going to have tremendous impact on us and change what enters the market,” she said.

November 1, 2020

DTE Energy to Cleave Pipeline Business

DTE Energy backed away from its pipeline business last week, announcing that it will spin off its non-utility natural gas pipeline, gathering and storage business.

The transaction will have the company shedding DTE Midstream and becoming a pure-play electric and natural gas utility. Midstream is set to carve out its own Detroit headquarters and become an independent and publicly traded company by mid-2021. DTE shareholders will retain their shares and receive pro rata shares of the new Midstream company.

DTE said the move will not negatively affect rates, customers or utility operations. CEO Jerry Norcia said the Midstream spinoff announcement “follows a thorough review with our board to identify opportunities to optimize our portfolio and maximize shareholder value.”

“We recognize that this comes not long after our significant acquisition of assets in the Haynesville [Shale] basin,” Norcia said during the company’s third-quarter earnings call Oct. 27. “Through 2019, while business mix discussions were still ongoing, we continued to pursue an aggressive value creation agenda for Midstream, which yielded the Haynesville acquisition. … Because this acquisition and the balance of the Midstream portfolio continues to perform exceedingly well … and thrive on its own, it crystallized our path to pivot to a high growth pure-play utility with the spin of a well run Midstream company. We believe this strategy will unlock significant value for our shareholders.”

Current Midstream President and COO David Slater is set to become CEO of the standalone company.

After the Midstream transaction, DTE will receive about 90% of its operating earnings from its core utility business versus the 70% it receives today.

Midstream owns approximately 2,350 miles of pipeline and operates 91 Bcf of gas storage capacity. DTE acquired most of the network in $1.3 billion and $2.5 billion transactions in 2016 and 2019 respectively. When the deal is complete DTE estimates it will generate 90% of its operating earnings from its utility business versus the current 70% operating earnings from its core utility.

“As most of you know, my background includes a substantial amount of time in the gas industry, including my involvement in development of our Midstream business. The team and I have dedicated a significant amount of time and energy creating a Midstream business at DTE that is recognized as one of the best in the country. So, you can imagine how important this decision is to our team and me. After careful consideration and review with our board, I am confident that the separation is the best way to allow the Midstream business and its team to achieve their full potential and to enhance overall value for our shareholders,” Norcia said.

DTE estimates Midstream will earn $700 million before taxes in 2020.

The company reported third-quarter earnings of $476 million ($2.46/share), compared with $319 million ($1.73/share) in 2019. It said earnings were up because of higher year-over-year residential sales, higher rates and warmer weather. The earnings report represents a turnaround from first-quarter earnings, when DTE contemplated shaving millions from operations and maintenance expenses to offset drooping sales. (See DTE to Cut Spending in Response to Pandemic.)

“I want to thank all the leaders and our 10,000 employees of DTE for creating this tremendous success in a year of great turmoil and uncertainty,” Norcia said. “We are firing on all cylinders, keeping our people safe and delivering for our customers, communities and investors. It is truly remarkable and certainly a reflection of the grit and determination of the great people of DTE.”

Norcia said DTE plans to invest about $14 billion in its electric utility over the next five years, some of that in renewable generation. He noted DTE’s goal of achieving net-zero carbon emissions by 2050. For that to happen, he said DTE needs to double renewable capacity by 2024 and quadruple it by 2040.

November 1, 2020

Transource Tapped for SPP’s 2nd Competitive Tx Project

SPP last week awarded its second competitive transmission project under FERC Order 1000, hopeful that it will succeed where the first one failed.

The Board of Directors on Oct. 27 approved an industry expert panel’s (IEP) recommendation to issue a notification to construct (NTC) to Transource Missouri, the panel’s “designated transmission owner,” for a 75-mile, 345-kV line in Oklahoma. The Sooner-Wekiwa project has a $66 million revenue requirement and an expected completion date of 2026.

The board approved Xcel Energy Southwest Transmission as the alternate builder.

The IEP evaluated 10 project bids under SPP’s competitive transmission owner selection process. Three of those bids came from Transource and occupied the top three spots in the panel’s intricate scoring matrix. The Transource bids were also the three most expensive, coming in between $66 million and $69 million. Projects submitted by other bidders ranged from $52.2 million to $64 million.

SPP awarded its first competitive project in 2016 to Mid-Kansas Electric, but the project was later canceled after load projections dropped. One stakeholder said at the time, “We went hunting for the project, we found it, we caged it — and we shot it.” (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

As was the case four years ago, the competitive project’s NTC went to an incumbent transmission provider, despite Order 1000’s requirement removing federal rights of first refusal. Transource Missouri is one of several subsidiaries of Transource Energy, a competitive transmission joint partnership between American Electric Power and Evergy. AEP’s Public Service Company of Oklahoma owns the Wekiwa substation’s end point west of Tulsa.

Oklahoma Gas & Electric owns the Sooner Power Plant at the other end of the project. In years past, the two utilities would likely have negotiated construction responsibilities.

The five-person IEP determined Transource’s winning proposal “best addressed a significant risk” to the project’s success, that being “the timely acquisition of rights of way.”

“This proposal also demonstrated significant capabilities and historical success in construction management and in the ability to operate and maintain a 345-kV transmission line,” the panel said in its final report.

Transource has completed three projects, in Missouri, Nebraska and West Virginia, and has a fourth under development, the Independence Energy Connection in Pennsylvania and Maryland.

SPP’s 2019 Integrated Transmission Planning assessment identified the Sooner-Wekiwa project as a potential competitive upgrade from among more than 1,600 proposed solutions submitted during the ITP process.

It estimated it would produce a 4.29 benefit-cost ratio under the Future 2 “emerging technologies” scenario, which assumed that electric vehicles, distributed generation, demand response and energy efficiency would increase energy growth rates, and that all coal and gas-fired generators over the age of 60 would retire. The assessment said the project will provide an alternate path for bulk power transfers to flow east to major SPP load centers, preventing flows from being diverted to the 138-kV system at Cleveland, Okla.

Requests for proposals were issued in early December 2019, requiring the IEP to be seated. The five-person panel, selected for its expertise in engineering design, project management construction, operations, rate analysis and finance, evaluated the project proposals in those categories. Five of the 10 proposals were submitted as detailed project proposals (DPPs), qualifying them for 100 incentive points each in the scoring. The other five were less detailed and did not qualify for the bonus points.

The winning proposal won a score of 877.9, topping the categories of Project Management and Operations and receiving the third highest point allocation for Engineering Design and fourth highest for Finance. Other projects scored from 517.8 to 871.9.

“I am very favorably impressed with the quality and thoroughness of the analysis of the submitted proposals,” Board Chair Larry Altenbaumer said.

Xcel’s Southwestern Public Service and Oklahoma cooperative Tri-County Electric were the only Members Committee representatives to vote against the recommendation.

“If you climb up to 35,000 feet, the present value revenue requirement for [Transource’s proposal] is 20% higher than the alternative proposal,” SPS President David Hudson said. “This is sort of showing the FERC 1000 process is actually costing SPP ratepayers more money. That isn’t even considering the cost of staff administering the 1,500 DPPs. What is this FERC Order 1000 process costing customers versus what it is saving them?”

The Advanced Power Alliance’s Steve Gaw agreed, saying a FERC 1000 policy discussion is “ripe.”

“It’s clear there are some issues in SPP’s Tariff that need to be thought through,” he said.

Golden Spread Electric Cooperative’s Michael Wise pointed out that the Strategic Planning Committee reviewed SPP’s competitive process following the Walkemeyer project’s selection four years ago. He said several improvements were made to the process.

“It might be necessary for the SPC to once again take up these issues,” he said.

“We would welcome a stakeholder process to look at improvements,” said IEP Chair Steve Strickland, a 35-year veteran of Entergy Arkansas. “This is only the second time we completed the process, and each time, we learned something new.”

October 31, 2020February 12, 2025

FERC Rejects ESI Proposal from ISO-NE

FERC ruled Friday that ISO-NE’s proposed Energy Security Improvements (ESI) market design is “unjust and unreasonable” because it would add substantial costs “without meaningfully improving fuel security” (ER20-1567).

ESI would have allowed the RTO to procure energy call options for three new day-ahead ancillary service products to improve the region’s energy security, particularly in winter when natural gas shortages can leave generators without fuel. Option awards would have been co-optimized with all energy supply offers and demand bids in the day-ahead market.

FERC found that the RTO’s proposed day-ahead ESI products “do not provide enough time for resources to take the steps necessary to perform during stressed conditions if they have not already taken them” as arranged fuel, for example. The proposed market design would have allowed resources that have not made advance arrangements to not participate because of its voluntary nature, undermining its ability to address fuel security. The commission noted that the impact assessment produced for the RTO by Analysis Group said ESI “would not materially reduce reserve shortages or the potential for loss of load, but nevertheless, forecasts increased costs of $20 million to $257 million per year.”

| National Grid

FERC also rejected an alternative proposed by NEPOOL that would have resulted in lower costs to ratepayers than the RTO’s proposal, saying it contains the same deficiencies.

FERC said that although it “does not generally require the mathematical specificity of a cost-benefit analysis to render a proposal just and reasonable … the commission must protect consumers from excessive rates and charges. In light of our finding above that ISO-NE fails to demonstrate that ESI will materially improve fuel security, we find that ESI does not strike an appropriate balance between addressing fuel security in New England while protecting consumers from the significant cost of those fuel security benefits.”

The commission said the RTO’s proposal also does not adequately address the misaligned incentives problem: fuel-secure resources may not be sufficiently motivated to make additional investments in energy supply arrangements. ISO-NE currently relies on resources that might not be available during stressed conditions because it did not procure the necessary fuel or resources with energy storage capabilities and did not take the steps needed to produce energy during stressed conditions.

“We find that, while the procurement of day-ahead reserves or call options allows ISO-NE to procure additional resource capability one day prior to real time, the record in this proceeding demonstrates that one day is not a sufficient time frame for resources to take the steps necessary to perform during stressed conditions,” the commission wrote.

The RTO pointed to the results of the impact assessment to claim that ESI would create strong financial incentives for resources “to maintain more secure energy supplies without an associated forward market.” According to FERC, ISO-NE failed to demonstrate how such incentives would be meaningful to resources that are unable to adjust energy supply arrangements in the day-ahead time frame.

NEPOOL Proposal

The RTO’s proposal had failed to win NEPOOL stakeholders’ endorsement, garnering only 39.6% support at a Participants Committee vote in April. Although Generators, Suppliers and Alternative Resources generally approved the plan, the other sectors were unanimous in opposition.

The committee endorsed a proposal by the New England States Committee on Electricity by a 61.7% sector-weighted vote, with unanimous support from the Transmission, Publicly Owned Entity and End User sectors and unanimous opposition from Generators. (See ISO-NE Sending 2 Energy Security Plans to FERC.)

But FERC said the NEPOOL’s alternative “fails to sufficiently align the timing of reserve procurement with that of fuel procurement and maintains the voluntary nature. … Furthermore, the impact assessment demonstrates that the NEPOOL alternative would not materially reduce reserve shortages or the potential for loss of load.”

The result of more than a year of stakeholder meetings, the ESI proposal was prompted by FERC’s July 2018 finding that ISO-NE’s Tariff is not just and reasonable because the RTO lacks a way to address fuel security concerns that it said could result in reliability violations as soon as 2022. The Tariff currently allows cost-of-service agreements only to respond to local transmission security issues. (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)

But FERC said Friday it made no finding on whether the RTO faces fuel security or energy security problem.

“We recognize that ISO-NE has concerns about its current and future ability to reliably serve load given its growing reliance on ‘just-in-time’ resources such as pipeline-fed natural gas and renewable generation, which could have efficiency and reliability consequences,” the commission wrote. “If ISO-NE decides to pursue a solution to address these concerns, we encourage it to explore a market-based reserve product that provides resources sufficient lead time and ability to acquire fuel or take other steps necessary to be able to deliver energy when needed.”

FERC added that it expected a market design would coordinate procurement of forward reserves and incentivize resources to offer into the forward, day-ahead and real-time energy and reserves markets based on their actual costs. It should also prevent the exercise of market power, including through potential mitigation measures and include financial obligations or incentives sufficient to ensure resources can deliver energy or reserves in real time.

“We are not, however, directing ISO-NE to pursue any particular approach,” the commission wrote. “We further note that nothing in this order prohibits ISO-NE from proposing a day-ahead reserves market independent of any proposal to address the concerns at issue here.”

The ruling also rejected ISO-NE’s proposal to sunset the interim fuel security retention mechanism and the inventories energy program one year earlier than currently set in the Tariff.

“We’re reviewing the decision and will discuss next steps with stakeholders,” ISO-NE spokesman Matt Kakley said. “We remain committed to finding market-based solutions to solving the region’s energy security challenges.”

Attorneys for Day Pitney said they “are continuing to digest the implications of the order, including potential next steps for NEPOOL and ISO-NE, and will provide additional information if and as appropriate.”