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November 14, 2024

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FERC Rejects Niagara Mohawk Tx Cost Formula, ROE Adders

FERC on Friday rejected Niagara Mohawk Power’s proposed cost allocation and recovery for the utility’s share in the Smart Path Connect transmission project in upstate New York, including its request to increase its base return on equity (ROE) from 10.3% to 10.5% (ER22-1201-001).

The commission also denied the utility’s requests for a 50-basis-point adder to account for risks and incentives based on performance.

Niagara Mohawk is seeking to recover the $535 million in costs on the Smart Path Connect project, being built with the New York Power Authority (NYPA). The utilities estimate the total capital cost of the project at $1.2 billion, with an anticipated in-service date of December 2025. It would consist of rebuilding approximately 100 miles of 230-kV transmission lines to either 230 kV or 345 kV, along with associated substation construction and upgrades that, together with other projects currently under construction in New York, would establish a continuous 345-kV transmission path from northern New York to the downstate region to mitigate current and projected congestion.

FERC rejected the proposal as conflicting with a commission-approved 2015 transmission service charge (TSC) settlement with the New York Association of Public Power that set the utility’s ROE at 10.3% (EL14-29).

“Niagara Mohawk voluntarily entered into the 2015 TSC ROE settlement, in which it agreed to a 10.3% ROE for all of its transmission facilities, inclusive of any incentive adders,” FERC said. “Niagara Mohawk points to nothing in the [settlement] to suggest that the ROE established there applies only to either then-existing transmission facilities or transmission facilities that primarily have certain types of benefits. We find that, in the absence of any such language, the ROE established in the [settlement] should apply to all of Niagara Mohawk’s transmission facilities, including its going-forward investments.”

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PJM Challenged on Interconnection Rule Transition

Stakeholders last week welcomed proposed changes to PJM’s interconnection procedures as long overdue but challenged the RTO’s timeline and transition plans.

PJM last month proposed to switch from a “first-come, first-served” approach to a “first-ready, first-served” cycle, with individual serial studies replaced with cluster studies (ER22-2110). (See PJM Files Interconnection Proposal with FERC.)

More than 30 companies and groups filed comments by the July 14 deadline in response to the RTO’s proposal, the result of 18 months of stakeholder talks.

The American Council on Renewable Energy said that while PJM’s proposal “does not address the full range of needed interconnection reforms, the reforms proposed are an important first step and will likely mitigate several causes of queue backlogs.”

The Organization of PJM States Inc. (OPSI) urged FERC to approval the proposal promptly but complained that PJM’s proposed four-year transition and two-year default processing timelines are too long. It noted that 11 of the 14 jurisdictions in PJM have renewable portfolio standards, but they rely heavily on imports for compliance because of insufficient renewable generation within their borders.

“Despite the fact that interconnecting new generation is a critical component of open-access transmission service and should be one of PJM’s core competencies, PJM’s generator interconnection queue has been inefficiently processing interconnection requests,” OPSI said. “PJM has been aware of state public policy goals for a number of years, but PJM continues to make little progress with the queue backlog. As a result, the current queue delays put some states in jeopardy of not meeting their near-term public policy goals as target dates inch ever closer.”

It said PJM reported completing only 13 facilities studies in April and May, versus a backlog of 1,585. “This slow pace will not clear the backlog and illustrates the urgent need to immediately reform the broken interconnection process,” the group said, adding that it will look to FERC’s interconnection Notice of Proposed Rulemaking (RM22-14) for additional improvements. (See FERC Proposes Interconnection Process Overhaul.)

OPSI said PJM’s proposals are similar to changes approved in other RTOs and proposed in FERC’s rulemaking. “However, the length of the proposed process does not live up to the standards set by other RTOs,” it said.

“OPSI is deeply concerned that, even under PJM’s proposed reforms, a project entering the queue today may not be able to achieve commercial operation until nearly 2030. This is because PJM proposes to not process any new interconnection applications until as late as 2026, at which point projects would then have to undergo a two-year interconnection process. The prospect of such a lengthy timeline is troubling. It is important that PJM’s proposed four-year pause on reviewing new applications be an absolute upper limit and that PJM invest the time and resources to substantially reduce this transition period.”

$5 Million Threshold Challenged

Numerous stakeholders also criticized the RTO’s transition plan to bar projects from remaining in the serial process “fast lane” — rather than starting over in a transition cluster study — if it contributes to the need for a network upgrade that exceeds $5 million.

“PJM has not demonstrated that this threshold has any correlation to whether a project in the queue is commercially ready,” the PJM Power Providers Group said. “Instead, this arbitrary threshold will upend many projects that are fully permitted, have made significant investments based on the study results to date and are ready to move forward with construction and interconnection. … While a transition mechanism is needed to get to PJM’s new proposed interconnection process, one that is based on actual demonstrations of commercial readiness would be far superior and less disruptive than what PJM has proposed.”

Hecate Energy also challenged the $5 million cutoff saying FERC should “allow ‘ready to go’ projects (that are willing to post security and meet certain other milestones) to participate in the ‘expedited process’ during the transition, and to receive accelerated treatment after the transition, regardless of the cost of identified network upgrades.”

Hecate also joined in a separate protest with six other developers, including Acciona Energy and Leeward Renewable Energy in challenging the threshold. “The PJM stakeholder process was selective, controlled by PJM, overlooked key proposals to address PJM’s backlogged queue and cannot be relied upon as justification for PJM’s queue reform filing,” they said.

Competitive Power Ventures said “the proposal ignores late‐stage projects … that have made substantial strides in development and can prove their readiness in objective and substantial ways, and that may have been delayed only as a result of PJM study delays. Such projects will be catapulted back in time, erasing all of the study work completed and proceeding under a completely new paradigm, while a project that may be later in the queue and may not be as far along in their development progress can leap frog over them simply because their projected network upgrade costs are $5 million or less.”

But Pine Gate Renewables and Cypress Creek Renewables insisted in a joint filing that the $5 million threshold is “rooted in PJM’s current tariff provisions, which establish $5 million as the minimum threshold for inter-queue cost allocation. Moreover, it is a carefully negotiated term that active PJM stakeholders debated extensively.”

“PJM stakeholders and staff collectively and collaboratively developed and adopted the eligibility criteria and $5 million threshold to facilitate PJM’s clearing of the existing backlog, while also allowing mature projects with little or no network upgrade responsibility to complete the interconnection process in a timely manner,” they said.

The two companies asked FERC to approve the filing quickly, saying it was the result of “a robust, inclusive and consensus-driven stakeholder process.”

‘Awkward Position’

The Sierra Club, Natural Resources Defense Council and the Sustainable FERC Project said that PJM’s filing restates existing tariff provisions that may be unjust and unreasonable under FERC’s interconnection NOPR, including the lack of firm deadlines for its transition cycles and new rules.

“This puts FERC in the awkward position of being asked to rule that a Section 205 filing is just and reasonable at the same time it investigates if portions of that filing are unjust or unreasonable through a rulemaking,” the groups said. “It is essential that FERC action in this docket does not prejudice the outcomes of the interconnection NOPR.”

They also asked FERC to reduce PJM’s proposed requirement that project developers provide proof of 100% site control to 90% and to add language “allowing flexibility when site control cannot be demonstrated because of regulatory requirements or obligations.”

Uncertainty

The Solar Energy Industries Association called the proposal a “significant improvement” that “ensures efficient processing of interconnection requests that will allow lower-cost resources to come online faster.”

But it said the proposed four-year delay in reviewing new applications will “create uncertainty for potential development in PJM once PJM begins reviewing new applications, as some developers will shift their efforts to other regions.”

It said FERC should require PJM to submit biannual reports on its progress in reducing its queue backlog and a breakdown of the interconnection delays by transmission zone, to determine whether individual transmission owners are to blame.

For their part, PJM’s TOs said in a joint filing that they “fully recognize that this reform is just an initial step that provides a flexible framework capable of accommodating future changes spurred by either PJM stakeholders or commission action.” They noted that PJM stakeholders intend to consider additional improvements through the new Interconnection Planning Subcommittee reporting to the Planning Committee.

Also filing a protest was the developer of the proposed 2,100-MW SOO Green HVDC Link ProjectCo, which said the proposal is unfair to merchant transmission facilities, “which are unjustly included in the new services queue and will be forced into even longer interconnection delays.”

Queue Groupings

National Grid Renewables Development, NextEra Energy Resources and RWE Renewables Americas said FERC should reject PJM’s proposal to include projects in queue groupings AG2 (cutoff date March 31, 2021) and AH1 (Sept. 30, 2021) in the transition along with projects in group AG1 (Sept. 30, 2020).

PJM’s initial transition proposal, presented to stakeholders in November 2021, included only group AG1.

“This decision respected projects that had some study work done and were thus entitled to rely on a continuation of the process they had embarked upon,” the companies said. By contrast, “most, if not all, AG2 and AH1 projects entered the queue knowing or on notice that PJM had already began with its stakeholders an initiative to make sweeping changes to its queue rules.”

PJM agreed to include AG2 and AH1 in the transition following lobbying by stakeholders holding positions in those groups, the three companies said.

The companies said including AG2 and AH1 would add 1,358 projects. Based on prior queues, only about 40 (3%) of those projects will be completed, they said.

‘Adjacent’ Parcels

Tenaska protested as arbitrary PJM’s proposal to allow a project developer to make changes to the project site at its first two decision points as long as the new site and the initial site are “adjacent parcels.” The company said PJM did not define “adjacent parcels” and provided no rationale for the requirement.

“A showing of ‘adjacency’ for a proposed site change is unnecessary for PJM in performing its function — assessing and studying a new project’s impact on the network transmission system — if the proposed site change does not result in a material modification,” it said.

Tenaska said solar project developers often file for a queue position after obtaining site control over a parcel of land but before conducting soil and geotech studies that could detect high levels of mercury or other elements that make the parcel undesirable. “Project developers then find nearby parcels of land, free from such environmental issues, and ‘perfect’ the site accordingly,” Tenaska said. “While these parcels sometimes are adjoining, sometimes they are nearby but not directly adjoining.”

The PJM study process examines the effect of new generation at a given point of interconnection to evaluate the effect of additional generation on reliability. “The real property status of the ground on which a project will be sited is wholly irrelevant to that analysis,” Tenaska said.

The company said site control requirements are intended to prevent speculative proposals from entering the queue.

Thus, it said, PJM should allow developers to change their sites unless they cause “a material adverse effect on the cost or timing” of interconnection studies related to system upgrades, “consistent with” the policies in MISO and SPP.

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PJM Planning Committee Briefs: July 12, 2022

Consumers’ Consultant Says PJM Load Model Based on ‘Fiction’

VALLEY FORGE, Pa. —  A consultant representing consumer advocates criticized PJM’s proposed load model for the 2022 Reserve Requirement Study, telling the RTO’s Planning Committee on July 12 that it would result in the over-procurement of about 1,000 MW.

Economist James Wilson — who represents advocates in New Jersey, Pennsylvania, Maryland, Delaware and D.C. — said that PJM is underestimating the assistance it could expect from its neighbors during peak loads because it models MISO, NYISO, the Tennessee Valley Authority and SERC Reliability’s VACAR subregion as a single entity it terms the “World.”

“The ‘World’ is a fiction,” Wilson said. “No other RTO aggregates regions as diverse as New York and VACAR and MISO and TVA.”

Wilson leveled his criticism after PJM’s Patricio Rocha Garrido presented the RTO’s proposal to use a load model from 2000-2010 for the capacity auction for delivery year 2026/27. The PC will be asked to endorse the selection at its August meeting.

Rocha Garrido said PJM considered 136 load models in its analysis, which he said is necessary because the coincident peak distributions from the RTO’s load forecast cannot be used directly in PRISM, the loss-of-load-expectation software.

Under a method approved by the PC in 2016, PJM seeks to match its forecasted peak day distribution with the historical diversity from the World’s peak.

In this year’s analysis, PJM switched the World peak to the fourth week in July so that the RTO — projected to peak in the third week of the month — tops out in the same month but not the same week as the World. The switch was made to match the historical diversity between PJM and World peaks, Rocha Garrido said.

Wilson said PJM made “very arbitrary” load choices in deciding on a model that has a 99% match between PJM’s and the World’s “per-unitized” peaks. “In previous years it’s always been 97% or 95%,” he said, noting that TVA peaked in the same day as PJM in only four out of the 23 last years, while NY, MISO and VACAR peaked in the same day as PJM in only seven or eight.

The four neighbors averaged more than 7,000 MW below their peaks at the time of the PJM peak — 3.9% of the PJM peak — over the 23 years, Wilson said. He said the choice would result in about a 1,000-MW increase in the reliability requirement. By combining the four neighboring regions, PJM is “pretending they would help each other rather than PJM,” Wilson said.

Michael Cocco, of Old Dominion Electric Cooperative (ODEC), asked PJM to provide a comparison of the individual regions’ peaks against its peaks.

Rocha Garrido said the RTO had conducted analyses that looked at the neighboring reasons separately and got “similar results.”

“The data supports 99% rather than 97%,” he said.

PJM’s Tom Falin, chair of the Resource Adequacy Analysis Subcommittee (RAAS), also defended the choice, saying the diversity between PJM and the World was less than 3% in 20 of the last 23 years.

“This is largely a judgment call in the end,” he acknowledged, saying there was no formula for determining the capacity benefit of PJM’s ties with its neighbors.

Falin also said not all of PJM’s assumptions were conservative, noting that PRISM assumes no transmission constraints within any of the regions. He also questioned whether other regions would call on demand response — which figures into their capacity calculations — to help PJM.

Wilson said he will make a presentation on his proposed changes to the load model at the next meeting of the RAAS on Aug. 3.

‘Time to Get Involved’ in Capacity Interconnection Rights for ELCC Resources

PJM’s Brian Chmielewski provided an update on the PC’s special session on capacity interconnection rights (CIRs) for effective load-carrying capability (ELCC) resources such as renewables, which cannot run at their maximum output for more than 24 hours.

CIRs set an upper bound on the amount of installed capacity attributed to a generation capacity resource.

At the June 24 meeting, stakeholders discussed competing proposals from PJM, LS Power, Global Infrastructure Partners’ Eolian and economist Paul Sotkiewicz of E-Cubed Policy Associates.

The group originally planned a final review of the proposals for this Wednesday, followed by a nonbinding poll. But the meeting was postponed until late August to allow for more offline discussions to forge compromises, Chmielewski said.

A first read is expected no sooner than the September PC meeting, with the new rules implemented for the 2025/26 Base Residual Auction.

“Now is the time to get involved before we get into polling,” Chmielewski said.

Informational Update on NOPRs

Members received updates on FERC’s Notices of Proposed Rulemaking on generator interconnection procedures (RM22-14), transmission system planning performance requirements for extreme weather (RM22-10) and a requirement that transmission providers submit one-time informational reports on extreme weather vulnerability assessments, climate change and electric system reliability (RM22-16).

PJM has planned two workshops on the extreme weather planning NOPR: one on July 21 to provide an update on its preliminary plans for its response and to solicit input from stakeholders, and one Aug. 12 to discuss the final draft response.

The RTO has previously recommended that FERC address resilience concerns by requiring a new transmission driver covering gas-electric vulnerabilities, reducing the number of critical grid facilities and strengthening infrastructure through storm hardening, winterizing generation resources and infrastructure redundancy.

ODEC’s Cocco said he hoped PJM would offer comments supporting its role as a “thought leader on gas-electric coordination.”

Generator Deliverability Education

PJM transmission planning engineer Jonathan Kern gave an update on the RTO’s proposed changes to generation deliverability testing.

Kern said the testing procedures “have been relatively unchanged for many years” despite the increased variability in dispatches because of the spread of renewables.

Among the changes is the grouping of resource types into three “block dispatches” based on their economics, with block 1 containing the units with the lowest offer prices (nuclear, wind, solar, hydro, pumped storage and other renewables); the more expensive block 2 (coal and combined cycle gas); and the most expensive, block 3 (IC/CT/ST oil and gas). “It better describes how PJM operates,” Kern said.

PJM also plans to redefine the “light load” period to include 10 a.m.-3 p.m. where the coincident peak load is between 40 and 60% of the annual peak for historical generation data necessary to represent the 50% load level.

“Solar is putting out large amounts of energy during the daytime. That’s completely unaccounted for” in PJM’s current modeling, Kern said.

Percentile Example (PJM) Content.jpgPercentiles represent the share of hours with output below a particular level. This example shows that onshore wind is generating 40% or less of nameplate capacity in 90% of the hours. | PJM

PJM is also introducing the concept  of “helpers” (generation with a negative DFAX, for which a decrease in the generation output increases the loading on a flowgate under study) and “harmers” (those with a positive DFAX, meaning a boost in generation would increase loading on the flowgate).

The new rules also will include more wind and solar in base case dispatches, with fixed solar rising from 38% to 47 to 55% of nameplate capacity in summer. Onshore wind would increase from 13% to 16 to 20%, and offshore wind would jump from 30% to 33 to 38%.

The RTO also plans to consider the impact of wind sited in MISO in both its light-load and winter tests. “Essentially, we’re looking at: What are the loopflows that would result from those wind units being dispatched at higher levels in MISO?” Kern explained.

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Biden: ‘I Will not Back Down’ on Climate Action

With Sen. Joe Manchin (D-W.Va.) once again shutting down negotiations over a budget reconciliation package that includes clean energy incentives, a range of voices and views have emerged to answer the crucial question of what comes next.

President Biden and Energy Secretary Jennifer Granholm both struck a note of defiance. In a statement released by the White House on Friday, the president said the need for climate action remained as urgent as ever, and he vowed not to back down.

“If the Senate will not move to tackle the climate crisis and strengthen our domestic clean energy industry, I will take strong executive action to meet this moment,” Biden said. “My actions will create jobs, improve our energy security, bolster domestic manufacturing and supply chains, protect us from oil and gas price hikes in the future, and address climate change.”

Granholm took to Twitter with a thread acknowledging her frustration while calling for broad action at all levels. “We will fight like hell with the tools we have to build a clean energy future and move forward on climate action,” she said. “This moment calls [for] every city, state, tribe, business, community and organization to get in the fight if you’re not already. We have to leave it all on the field.”

In an interview on West Virginia MetroNews radio on Friday, Manchin maintained that he wants action on climate, but in the wake of June’s 9.1% consumer price index — up 1.3% from May — fighting inflation and reducing the federal deficit have to come first.

Manchin in December gave similar reasons for pulling out of negotiations over the original Build Back Better Act. The bill was passed by the House of Representatives, but all 50 Republicans in the Senate are opposed. Democrats want to use the reconciliation process, which would only require a simple majority vote (with Vice President Kamala Harris breaking the tie) if Manchin joined in support, to bypass a filibuster.

“We’ve had good negotiations. … Our staffs have been working diligently for the last two to three months,” Manchin told Hoppy Kercheval, host of “MetroNews Talkline.” But he also said he had been clear with Senate Majority Leader Chuck Schumer (D-N.Y.) and other Senate staffers that his support would depend on the June inflation figures that were released on Wednesday.

“They knew exactly where I stood,” he said. “When we saw 9.1%, that was an alarming figure to me … so I said, ‘Oh my goodness, let’s wait; this is a whole new page.’”

With the war in Ukraine, and Europe looking to the U.S. to replace Russian fossil fuels, Manchin argued that the U.S. can decarbonize while continuing to “produce more fossil [fuel] cleaner than anyone in the world and replace that dirty fossil going into the atmosphere.”

“Also, what you can do is invest in the cleaner technologies that we know that will work,” he said. “We know hydrogen is going to work; we know we need storage for batteries, and battery storage takes care of wind and solar; we know that. New transmission — we know all these things. Geothermal and small nuclear reactors, I’m for all these things.”

Manchin said he is also consulting economic experts to ensure that any tax increases that would be used to fund clean energy incentives don’t cause further inflation or cause companies to cut back production or lay off employees. A budget reconciliation package, with or without energy incentives, could still be passed when Congress returns from its August recess in September, he said, “if it’s a good piece of legislation.”

Post-election Green Pivot?

Biden’s statement did not detail the specific executive actions he might take to provide momentum for his stalled vision for an aggressive climate agenda. Manchin’s latest defection comes two weeks after the U.S. Supreme Court’s decision in West Virginia v. EPA undercut EPA’s ability to cut emissions at existing power plants through generation shifting — changing out dirtier fossil fuels for cleaner low- or no-carbon generation. (See Supreme Court Rejects EPA Generation Shifting.)

Biden has already used executive orders to set the U.S. on a path to a 100% carbon-free electric system by 2035 and a net-zero economy by 2050. More recently, he invoked the Defense Production Act to ramp up clean energy manufacturing and ordered a two-year suspension of potential tariffs on solar cells and panels from Cambodia, Malaysia, Thailand and Vietnam in the face of a pending Commerce Department investigation. (See Biden Waives Tariffs on Key Solar Imports for 2 Years.)

Meanwhile, the Department of Energy is continuing to distribute new funding, much of it from the Infrastructure Investment and Jobs Act, for clean energy initiatives.

If fully funded, the law will continue to pump out funds for clean energy through 2026. For example, on Thursday, the DOE announced $29 million in funding, about a third from the IIJA, to increase the reuse and recycling of solar technologies and develop solar panel designs that reduce the cost of manufacturing.

In the wake of West Virginia v. EPA, California Gov. Gavin Newsom (D) and Washington Gov. Jay Inslee (D) both vowed to step up their efforts to cut carbon emissions. More recently, the D.C. Council passed legislation, pending before Mayor Muriel Bowser, that would ban natural gas hookups in new construction and require all new construction and major renovations in the district to be net-zero by 2026.

But, in its analysis of the post-Manchin state of play, industry analysts ClearView Energy Partners suggest that if the Republicans do gain majorities in the House and Senate in the midterms, Biden might “pursue muscular intervention into energy markets and capital formation … potentially including ‘a climate emergency’ declaration.”

“If the White House was also modulating its oil and gas policy in recent months to woo [Sen.] Manchin’s support for clean energy incentives, then Manchin’s latest defection could bring an even bigger post-election green pivot,” ClearView said.

In the absence of a “mini-BBB” budget reconciliation deal, ClearView also sees the potential for a congressional pivot toward passing a package of clean energy tax credit extenders in the lame-duck session between the midterm elections and the opening of the next Congress in January. Although the option of tax extenders has not been discussed thus far, “we would not be surprised to see extenders text proposed (or at least mooted) by the House Ways and Means and Senate Finance Committees before lawmakers leave for their August recess,” ClearView said.

Some Republicans might support extender legislation for two reasons, ClearView said. First, even if the GOP takes both houses of Congress, Biden will still have veto power, and second, a growing number of red states are now generating about half of the country’s onshore renewable and other clean forms of energy.

Underway and Unstoppable

Perhaps with such tax extender legislation in mind, clean energy advocates and business groups continued to call for congressional action on federal tax credits and other incentives, echoing administration arguments that they will help fight inflation, spur economic growth and protect energy security.

Clean energy tax credits “would deliver much needed relief, helping to cut energy prices and reduce U.S. dependence on price-volatile fossil fuels, by spurring the domestic manufacturing and deployment of clean, affordable and reliable advanced energy technologies,” said Heather O’Neill, president of Advanced Energy Economy. “Failing to use this opportunity to boost the domestic advanced energy manufacturing industry would mean American workers get less benefit from the world’s transition to clean energy, and would all but assure that our economic competitors, particularly China, reap the economic rewards instead.”

O’Neill and others also pushed hard on the business case for clean energy. The transition is “underway, and it is unstoppable,” O’Neill said. “We see it in corporate procurements driving clean energy investment across the country. We see it in consumer demand for electric vehicles as drivers seek to free themselves and their pocketbooks from the volatility of gasoline prices.”

“The private sector is making record-level investments in the clean energy transition, but a predictable and long-term national tax and policy framework is needed to support accelerated and expanded deployment,” said Lisa Jacobson, president of the Business Council for Sustainable Energy.

Any effort to find common ground on tax credits might begin with carbon-capture technologies and that industry’s 45Q tax credit, both of which have had strong support from Manchin, whose family still operates the coal company he started.

“While there is uncertainty about next steps with the reconciliation process, it remains clear that there is broad, bipartisan support for Congress to provide robust investments in carbon-management policies,” said Madelyn Morrison, external affairs manager for the Carbon Capture Coalition. “To achieve carbon capture and removal at climate scale, Congress must deliver the full portfolio of federal policy support for carbon management in any moving legislative vehicle, including a direct-pay option for the 45Q tax credit.” Manchin has recently opposed any direct-pay options for clean energy tax credits.

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MISO Promises Stakeholder Discussions on Capacity Auction Reform

MISO leadership last week committed to holding future talks with stakeholders on how to retool its capacity auction to stimulate more supply.

Scott Wright, the RTO’s executive director of market strategy, said the growing reliability risk will require staff and stakeholders to discuss modifications to price signals and how to value resources’ different attributes in the capacity market.

The discussions will be held in the Resource Adequacy (RASC) and Market subcommittees during the next few months, Wright said. He added that the conversations will likely include potentially adding a sloped demand curve in the capacity auction. (See MISO Warming to Patton’s Sloped Demand Curve.)

“MISO is committed to coordinated action and is developing plans for near-term evaluation and stakeholder engagement,” Wright told stakeholders during a Resource Adequacy Subcommittee meeting Wednesday. “We’re not deferring this to next year; we want to get going this year.”

The vow was repeated the next day during a Market Subcommittee meeting.

“We’re looking through what the plan is and will return to these forums,” MISO Senior Director of Transmission Planning Laura Rauch said.

Independent Market Monitor David Patton said after speaking with state regulators following the April planning resource auction (PRA), he’s “cautiously optimistic” that MISO will be on a path to applying a sloped demand curve within six months

“The best time to implement a sloped demand would have been when you’re not in shortage,” he said.

MISO Midwest is grappling with a 1.2-GW capacity shortage following the 2022-23 PRA. The shortfall triggered a $236.66/MW-day cost-of-new-generation-entry clearing-price for the Midwestern subregion. MISO has said the deficit might force it to order temporary, controlled load sheds this summer and next as it is not expecting sufficient firm resources to handle summer peak forecasts under typical demand. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

Though members approached this year’s auction with more capacity year-over-year, staff said the resource additions were mostly intermittent and generally less available than retiring thermal generators.

Stakeholders Ask for Data Improvements

Constellation Energy’s John Orr said staff’s posting of preliminary supply and demand data for the PRA could use some improvements and more regular updating.

Orr suggested MISO implement a standardized timeline for posting forecasted capacity positions by local resource zone, perhaps releasing the data in January and updating it on a weekly basis as market participants update capacity values. He said MISO should periodically update how much capacity has been converted to zonal resource credits. He said if a particular zone returns a zero value ahead of the auction, that could spur members into making arrangements to avoid another capacity shortfall.

Orr said a weakness of MISO’s 2022-23 preliminary data was that it was never updated beyond a singular release.

“We all knew those numbers are incomplete, but they gave us an idea of what to expect, especially in zones that are predicted to be tight,” Orr said. He, like other stakeholders, questioned why they failed to warn of a potential shortage.

Orr said he thinks “it’s time for stakeholders to ask MISO what they want to see” and asked stakeholders to work together to develop recommendations to MISO.

He said market participants need a better idea of what resources are expected to be unavailable, either due to retirements or auction exemptions and exclusions approved by the IMM.

“The exemptions and retirements that are protected by confidentially can really kind of can throw you off when you’re going to be very tight, as it appears we’re going to be for the next several PRA cycles. And the seasonal auctions could throw another wrinkle in that,” Orr said.

WEC Energy Group’s Chris Plante said his utility is having “a lot of difficulty” preparing quadrupled data for a yet-uncertain seasonal capacity auction. FERC has yet to approve MISO’s request to conduct four seasonal auctions per year.

In the meantime, MISO leadership continues to issue grim warnings over its forecasted capacity supplies.  

During a July 7 meeting with Kentucky lawmakers, Melissa Seymour, vice president of external affairs, said that part of the state might face controlled load shedding next year.  

Seymour delivered a similar message in front of the Illinois Commerce Commission in May. (See MISO Exec, IMM Debate Next Steps After Capacity Auction Shortfall.)

“Unless more capacity is built or bought, especially capacity able to reliably generate during tight system conditions, the shortfalls we experience this year will continue and get worse going forward,” she said.

MISO’s wholesale footprint affects just 14% of Kentucky’s retail power sales.

Seymour’s comments led Kentucky lawmakers to suggest ramping up coal production, delaying coal plant retirements, and even bringing some nonoperational coal plants out of retirement.

According to its pending 2021 integrated resource plan, Louisville Gas and Electric and Kentucky Utilities intend to retire a dozen aging coal and gas-fired units from 2024 to 2036.

“As a generation unit ages, the economics of retrofitting the unit to comply with new environmental regulations become less favorable,” LGE and KU explained in the filing. However, the utilities still plan to burn coal into 2066.

New Accreditation for Renewables in the Works

MISO continues to evaluate new capacity accreditation designs with stakeholders for the footprint’s renewable resources and load-modifying resources.

During the July RASC meeting, the RTO’s director of policy studies, Jordan Bakke, said staff and stakeholders are “learning together” about accreditation options for non-thermal generation. He said MISO is still in an evaluation stage and hasn’t internally settled on an option.

Patton said once MISO more accurately accredits intermittent resources, it should send economic signals to developers to pair their renewable energy with battery storage. He said co-located renewable and storage hybrid resources will likely have a much higher capacity credit.

MISO laid out three potential options this spring to accredit renewable resources: expand its effective load carrying capability (ELCC) calculation to include solar as well as wind; use the same performance-based accreditation design that it proposed for its thermal generation and currently pending before FERC; or use a blend of ELCC and performance-driven accreditation. 

Some stakeholders expressed confusion with how the blended option would be handled. Staff said they would use its projected loss-of-load risk hours and MISO’s new concept of “resource adequacy hours” — the historical tight margin and emergency periods defined for the performance-based accreditation design — as possible inputs for the new accreditation method. (See MISO Stakeholders Insist on Consistency in Capacity Accreditations.)

The RTO filed with FERC late last year to change its accreditation for conventional resources to a seasonal value based on a unit’s past performance during resource adequacy hours. The new accreditation is contained in a larger filing to create four seasonal capacity auctions. (See Deficiency Notices for MISO’s Seasonal Capacity Auctions Bid.)

The grid operator said the blended approach for renewables has the potential to encompass a “broader range of planning and operational considerations.” Staff said loss-of-load hours and resource adequacy hours don’t necessarily occur on the same days.

MISO plans to discuss a new accreditation method for its non-thermal resources in RASC meetings and special workshops through the end of the year.

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NV Energy Surpasses 2021 RPS Requirement

NV Energy exceeded Nevada’s renewable portfolio standard requirement of 24% in 2021, with nearly 31% of its retail energy sales coming from renewable resources and related credits, according to a report approved by state regulators last week.

NV Energy subsidiary Sierra Pacific Power, which serves northern Nevada, achieved 31.9% renewable energy last year. Southern Nevada subsidiary Nevada Power reached 30.1% renewable energy. The statewide weighted average was 30.7%, according to the report filed by the utility in April.

Last year’s adjusted retail sales were 8,728,248 MWh for Sierra Pacific and 20,712,404 MWh for Nevada Power.

The Public Utilities Commission of Nevada (PUCN) voted 3-0 on Tuesday to approve the report and confirm that NV Energy complied with the 2021 renewable portfolio standard.

50% by 2030

Nevada’s RPS was 24% last year, an increase from 22% in 2020. The RPS grows to 29% in 2022 and 2023; 34% in 2024 through 2026; 42% in 2027 through 2029; and 50% in 2030. NV Energy said it is “well on its way” to meeting the 50% renewable requirement by 2030.

“Our commitment to evolving our generation mix is one of many ways we are helping meet our state’s sustainability goals,” Dave Ulozas, NV Energy’s senior vice president of energy supply, renewables and origination, said in a release shortly after the utility filed its report with PUCN.

Last year was the 12th year in a row that the company surpassed the state’s renewable energy requirement, the release said.

DSM, Carryovers

Under Nevada statute, energy efficiency measures may count toward up to 10% of the annual RPS requirement, through 2024. After that, energy efficiency measures — included within demand side management (DSM) — can’t be used toward meeting the standard.

NV Energy used energy savings from DSM to satisfy 10% of its RPS requirements last year.

In addition, the utility used excess portfolio credits carried over from 2020 to help meet last year’s RPS requirement. And surplus credits from last year will be carried over to this year.

State law allows a utility to sell excess portfolio credits when the surplus is more than 10% of the required amount. If the surplus is more than 25% of the amount needed to meet the RPS, the utility is directed to “use reasonable efforts to sell” credits in excess of 25%.

Sierra Pacific went over the 25% threshold with its surplus portfolio credits and solicited offers to buy them. Although the utility received seven offers, it ultimately decided to keep the credits in case it needs them later, according to the report.

Nevada Power had surplus portfolio credits in the 10% to 25% range. NV Energy said it would consider selling the credits “if the circumstances are favorable and the sale benefits our customers.”

New Solar Projects

At the end of 2021, Nevada Power had about 1,570 MW of renewable generation capacity in service, according to NV Energy’s filing. Nevada Power added one utility-scale renewable project last year, Copper Mountain 5, a 250 MW solar facility in Boulder City.

In addition, Nevada Power had nine solar projects totaling 2,044 MW in development at the end of last year. Eight of those projects include battery storage.

Sierra Pacific finished the year with about 692 MW of renewable capacity in operation. During 2021, one new project was added: the 101 MW Battle Mountain solar facility, which includes 25 MW of storage.

The utility also had six solar projects with a combined total of 824 MW in development at the end of the year. All the projects include battery storage.

NV Energy’s filing described a “positive” outlook for both of its subsidiaries to comply with the RPS and other future credit commitments.

However, the utility noted some risks. In particular, delays in receiving solar panels and other project components are causing project completion dates to be pushed back and could result in project cancellations, the RPS report said.

“Delays and shortages can drive up costs to a point where a project that was previously economical becomes uneconomical,” NV Energy said.

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Residents Voice Opposition to Upstate NY Wind Project Before PSC

Residents opposed to the Heritage Wind project planned for western New York spoke before the Public Service Commission on Thursday, citing human health concerns, danger to migratory birds in nearby game refuges and a lack of transmission capacity (22-E-0204 and 16-F-0546).

The developers “maintain that there will be no change in property value in our area. We would have six of the wind turbines almost 600 feet tall within 1 mile of our home and the fact that they tried to maintain that there would be no effect on our property value or anyone else’s property value in this area I think is considerably a falsehood,” Iva McKenna — a resident of Barre, where the project is to be located — told the PSC.

While only five people spoke at the hearing, all against the project, the initial proceeding drew 452 written comments, which were overwhelmingly opposed to the project, though about two-thirds of the total was form letters.

Only three of the 17 written comments submitted for the public hearing were in support. Austin Kuntz, union representative for Rochester-based Laborers’ Local 435, said the project will bring hundreds of prevailing-wage jobs to local residents, provide them and their families with health care benefits and a suitable retirement, and fund schools, public services and infrastructure without the need to raise local taxes.

Heritage Wind southwest section (Heritage Wind) Content.jpgThe southwestern section of the Heritage Wind project lies within a mile or two of national and state wildlife areas. | Heritage Wind

The Office of Renewable Energy Siting (ORES) in January granted a construction permit for the project in Barre, between Rochester and Niagara Falls, contingent on securing a certificate of public convenience and necessity from the PSC. The project is owned by Virginia-based Apex Clean Energy, which manages 2 GW of renewable energy.

Barre resident Adrienne Daniels commented on July 1 that her seizure disorder “very likely will be further affected by the towers’ flicker effects. … The proposed heights of the towers are ludicrous. It has to cause problems with airspace for the small airport nearby, bird populations, migration routes, etc. An eagle has nested on my property; I strongly doubt we’ll have any other large birds establishing nests in this area.”

With 4,607 gravel truck trips projected, resident Georgette Stockman said that if “they plan to use Route 77, will the movement of equipment and components pass the new Western New York Veterans Cemetery, where two people have already lost their lives trying to negotiate their way onto Route 77? Will the equipment go through the Iroquois Wildlife Refuge and disturb the very nature of a refuge?”

Barre resident George McKenna reiterated his written concerns that the $198 million to be paid by NYSERDA for the project was “a wash” and that it would take at least 20 years to get that sum back in electrical energy value.

He also said Barre citizens have never had their opinions or concerns listened to.

“Surveys have shown approximately 70% of the population in opposition, and when the town board was in the process of changing the town’s wind ordinance to accommodate Heritage Wind, 87% of the population was opposed,” McKenna said.

Resident Kerri Richardson spoke of the inability of the transmission system to deliver increasing amounts of upstate renewables to downstate consumers and how that situation jeopardizes achieving the state’s public policy goals.

“The NYISO 2019 Power Trends report identifies that it is not actually in the public interest or public need to move forward with this project in particular,” Richardson said. Quoting from the report, she said, ‘Even with the Western New York and AC transmission projects already selected by the NYISO, congestion on the system will persist, complicating the state’s ability to meet its renewable energy goals.’”

In its January 2019 award of renewable energy credit (REC) contracts, the New York Energy Research and Development Authority (NYSERDA) noted that it was supporting 20 large-scale renewable projects, including Heritage, and that 93% of the awarded capacity would be located upstate (in zones A-E), where clean energy resources are already abundant and access to load centers in southeastern New York is heavily constrained, bottled in so-called generation pockets.

In its 2022 Power Trends report issued last month, NYISO projected that “transmission constraints in these pockets will likely result in curtailment of 11% of the total potential renewable energy production across New York, with curtailment levels in some individual pockets as high as 63%. As more renewables are added to the bulk electric system without additional transmission expansion, greater congestion and curtailment levels will occur.”

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MISO Predicts Easier Operations in Fall

As it navigates a tough summer, MISO is more optimistic about successfully managing operations this fall.

The grid operator on Thursday released a fall resource adequacy outlook, where it said it shouldn’t encounter trouble if demand and generation outages remain at normal levels throughout autumn.

Using a probable peak load forecast, MISO expects to have 114 GW of firm resources on hand to cover a projected 111-GW peak in September; 100 GW available to manage a 92-GW peak in October; and 104 GW by the time November’s expected peak demand of 91 GW rolls around.

Still, September’s skimpy surplus means the RTO is not ruling out the possibility of emergency actions. The National Oceanic and Atmospheric Administration has said almost the entire MISO footprint should see a warmer-than-normal fall.

The grid operator said a high-outage scenario in September could possibly completely exhaust the 10.3 GW cushion of emergency operating reserves and load reduction. MISO said a higher-than-expected load of 117.5 GW could outstrip its fleet if only 104.3-GW of firm resources are available.

The RTO also said it might declare an emergency to dip into load-modifying resources in a worst-case scenario in October, when high outage rates could make only 95.3 GW of non-emergency resources available and demand surges to 97.5 GW.

MISO typically experiences 34.5 GW worth of generation outages in the fall, with about 11 GW of that forced. The RTO’s all-time fall peak load of 115 GW occurred in September 2017.

Summer Woes Still Top of Mind 

Most of the MISO community’s attention remains on the summer heat and how much worse it could be this time next year.

During a Market Subcommittee meeting Thursday, Independent Market Monitor David Patton said there may be cause for “heightened concern” next summer. He said he anticipates about 1.4 GW of generation heading into retirement between now and next year.  

Patton continues to insist MISO isn’t communicating all risk in its pre-season summer assessments, failing to account for generation derates during heat waves.

“As temperatures get hotter and hotter, the generating capacity of our thermal generation tends to go down,” he said.

Stakeholders asked how MISO can avoid ERCOT’s fate of never-ending warnings of summertime energy conservation. (See ERCOT Dances with Danger Again.)

“You don’t want to be ERCOT,” Patton said before adding, “Not to put too fine a point on it, but I’ve been telling MISO for ten years now that you’re going to have a resource adequacy problem.”

Patton said MISO needs a sloped demand curve in its capacity auction to produce “reasonable” and not “close to zero” prices, allowing some resource owners to make enough money to stave off retirement.

“We haven’t done it, and we’ve needed it. And now I think we’ll do it,” he said of the demand curve changes. “It’s not rocket science.”

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DC Circuit Court Backs FERC over MISO Interregional Cost Allocation

The D.C. Circuit Court of Appeals on Friday sided with FERC over Entergy Arkansas in a disagreement concerning MISO’s cost allocation for interregional transmission projects with other RTOs.

The court rejected Entergy’s appeal and kept the current cost allocation in place for MISO’s share of interregional projects rated from 100 to 345 kV. The ruling supports FERC’s decisions to allow cost recovery of lower voltage transmission projects beyond the pricing zone in which they are located (20-1262).

MISO’s portion of its interregional market efficiency projects (MEPs) with PJM and SPP are divvied up based on an adjusted production cost savings calculation that finds benefits beyond a project’s own zonal borders. MISO and SPP have never approved an interregional MEP, but MISO and PJM have.

Entergy argued that power flows are different between lower and higher voltage projects, making the benefits of lower-voltage projects limited and locally concentrated.

Entergy also argued the commission was incorrect to refuse a 2019 MISO proposal that limited the cost recovery of projects under 230 kV to the transmission pricing zone they are located in. It said FERC’s substitute solution based on adjusted production costs savings was inadequate.

But the court, quoting a previous return-on-equity case, noted that “FERC is not required to choose the best solution, only a reasonable one.”

“It is not our job to determine that ‘FERC made the better call,’ rather, our ‘important but limited role is to ensure that the Commission engaged in reasoned decision-making — that it weighed competing views, selected a … formula with adequate support in the record and intelligibly explained the reasons for making that choice,’” the court wrote, citing 2016’s FERC v. Electric Power Supply Ass’n Supreme Court ruling.

The court also pointed out that MISO is still free to propose a different cost allocation for FERC’s review.

The commission twice rejected MISO’s cost-sharing design for interregional MEPs before directing the grid operator in 2019 to use a design based on adjusted production costs savings for economic interregional projects 100 kV and above. (See Another Rejection for MISO Cost Allocation Plan.)

The back-and-forth at the time was because of MISO and PJM approving their first major interregional transmission project. MISO said that because a $22 million reconstruction of the Michigan City-Trail Creek-Bosserman line in Indiana was only a 138-kV project, it could not allocate costs beyond the transmission pricing zone where the grid operator’s share of the project was located.

MISO currently has a FERC-sanctioned mismatch between the voltage thresholds it uses for its regional and interregional MEPs. The RTO uses a 230-kV threshold for MEPS in its footprint and relegates lower voltage projects to an “other” category, where they’re ineligible for cost recovery from multiple pricing zones. (See MISO Cost Allocation Plan Wins OK on 3rd Round.)

In 2016, FERC lowered MISO’s interregional economic project voltage threshold from 345 kV to 100 kV after a 2013 complaint before the commission by Northern Indiana Public Service Co. over the MISO-PJM interregional planning process.

The Circuit Court’s agreement that lower-voltage transmission projects can deliver benefits regionally might have implications for other past cost-allocation decisions on MISO MEPs.

The commission has repeatedly refused to entertain competitive developer LS Power’s argument for a lower voltage threshold on economic transmission projects in the MISO footprint (EL19-79; ER20-1723-001). (See FERC Spurns LS Power’s Voltage Threshold Argument.)

LS Power has tried for two years to persuade FERC that the RTO should use a 100-kV threshold for market efficiency projects instead of the 230-kV cutoff the RTO was cleared to use in mid-2020. The company has contended that MISO’s 230-kV threshold is arbitrary because projects with voltages down to 100 kV can deliver significant regional benefits.

FERC has held firm that small, regionally beneficial projects are the exception, not the rule, and do not justify opening more projects to competitive bidding.

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California PUC Opens ‘Critical’ Demand Flexibility Proceeding

The California Public Utilities Commission launched a proceeding Thursday aimed at shoring up grid reliability and soaking up more electricity from renewable resources by using real-time rates to influence customer demand.

The new order instituting rulemaking (OIR) is intended to “enable widespread demand flexibility through electric rates,” the commission said in a news release. “The concept of demand flexibility allows consumers to play a key role in the operation of the state’s electric grid by reducing or shifting their electricity use during peak-use periods in response to a price signal or other incentive.”

A major goal is reducing solar curtailment by increasing electricity use during the day, when solar power is abundant and demand low, including by charging electric vehicles during those times.

“I want to highlight the importance this rulemaking is going to be and the critical role it’s going to play in designing our future grid,” Commissioner Darcie Houck said. “It’s probably one of if not the most, important rulemakings we’re going to do during my term here as a commissioner.

“Our electric grid was originally designed with the assumption that customer demand for electricity was inflexible, and during the majority of the last 140 years, that was the correct assumption,” Houck said. “Customer demand was indeed inflexible. We did not have the tools or the technologies to manage demand, nor did we necessarily need to do so because we relied on energy supply being flexible.”

“As we move toward a very different energy landscape … we need to make adjustments,” she said.

California has experienced reliability crises in recent years as it attempts to reach its 100% clean energy goal by 2045 as extreme weather, prolonged drought and massive wildfires plague the West. The retirement of fossil fuel plants and their replacement with weather-dependent variable resources has exacerbated the problem.

Energy emergencies occurred the past two summers in California during heat waves, when solar ramped down in the evening and demand from air conditioning remained high. In one instance last July, a wildfire shut down major transmission lines from the Pacific Northwest, exacerbating tight supply.

In August 2020, CAISO was forced to order rolling blackouts during a severe heat wave, when imported electricity from the Desert Southwest dwindled and triple-digit temperatures continued after dusk.

In response, the CPUC issued expedited decisions last year to try to bolster reliability in the next three summers.

One of those decisions expanded existing demand-reduction efforts, and another created new ones, including two pilot programs to test the effects of dynamic rates that change rapidly based on grid conditions, including energy emergencies. (See CPUC Proposes Summer Reliability Measures.)

The new demand flexibility proceeding is connected with a June 22 white paper by the CPUC’s Energy Division that examines using advanced technologies and real-time price signals to encourage consumers to cut back on energy use when supply is tight and prices high, and to charge EVs or run their dishwashers when prices are lower, such as during the day when solar power is plentiful and cheap.

The white paper addresses the challenges the state faces while transitioning to clean energy and electrifying transportation and buildings. Scaling up demand response programs to cut energy consumption at key times is among its priorities.

The state’s current patchwork of DR programs, which pay customers to reduce consumption, is insufficient, it says. The white paper identifies strategies for broadening demand-side efforts, including by introducing dynamic energy prices based on real-time wholesale energy costs and localized marginal costs and making sure consumers have easy access to those prices online.

A workshop on the white paper is scheduled for this Thursday.

The demand flexibility rulemaking will address issues, outlined in the order, such as how the CPUC should “update its rate design principles to enable widespread demand flexibility to improve system reliability and advance the state’s climate goals in an affordable and equitable way.”

Two or more working groups will develop proposals for the proceeding. The CPUC expects to issue a scoping memo this fall followed by a proposed decision, with a commission vote in the first half of next year.