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September 5, 2024

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DC Circuit Upholds FERC on Transmission Cost Allocation in PJM

The D.C. Circuit Court of Appeals on Friday denied Linden VFT’s and the Long Island Power Authority’s (LIPA) petitions for review of a settlement that allocated transmission costs in PJM.

But the court did agree with Linden’s argument that FERC “erroneously” assigned costs based on a “flawed interpretation” of the settlement, remanding the commission’s decision for further proceedings.

The dispute was over a settlement the commission approved between PJM and members in May 2018 regarding how the RTO would allocate the costs of transmission projects above 500 kV approved between April 19, 2007 — when FERC determined the RTO’s existing violation-based distribution factor (DFAX) or “postage stamp” method was unjust and unreasonable, requiring a new load-ratio share method — and Feb. 1, 2013, when FERC approved PJM’s new hybrid method, combining both the DFAX and load-ratio methods. (See FERC Rebuffs Challenges to PJM Tx Cost Allocation.)

FERC approved the settlement over the objection of Linden and LIPA, both of which export electricity from PJM to New York; they argued they would pay about $30 million more for the “vintage projects” approved between 2007 and 2013 than under a pure DFAX method.

After the commission denied rehearing of the settlement orders, Linden and LIPA petitioned for judicial review.

“The question is difficult because high-voltage projects afford two different kinds of benefits — local benefits that accrue primarily to utilities close to the project at issue, and regional benefits that accrue throughout the grid,” the court said in its ruling. “The 7th Circuit has twice set aside cost allocations that ignored the local benefits, and we have set aside cost allocations that ignored the regional benefits.”

Arguments

Linden and LIPA contended that FERC’s approval of the settlement, and the allocations it implemented, were arbitrary, but the court disagreed, saying that the commission can approve an agreement when the “overall result of the settlement is just and reasonable,” even if “individual aspects” of it “may be problematic.”

“FERC adequately justified its approval of each formula,” the court said. “Start with the going-forward formula, which allocates costs through a mix of the postage-stamp and flow-based methods. FERC approved the formula based on reasoning in its 2013 compliance order, which had approved the same formula for future high-voltage transmission projects. Doing so was not arbitrary.”

Linden and LIPA also contended that the settlement violated a requirement of a cost-benefit analysis to quantify the benefits of a project, citing the 7th Circuit Court of Appeals’ rejection of the postage-stamp methodology in 2014. But the D.C. Circuit said that ruling was narrow, in that it found FERC weighed regional benefits over local benefits. “‘Nothing in those decisions casts doubt on’ FERC’s view that high-voltage projects have substantial regionwide benefits,” it said, quoting itself from a previous ruling.

The court also said FERC “reasonably concluded” in its orders that Linden or LIPA would not have found a more favorable decision on the settlements by going through litigation in the courts.

“The challengers do their best to obscure this point, but what they seek is application of a pure postage-stamp method — or at least a hybrid formula with a more heavily weighted postage-stamp component,” the court said. “The 7th Circuit has twice set aside a pure postage-stamp formula for the vintage projects. We have little doubt that, if faced once again with a pure or almost pure postage-stamp formula, it would call strike three.”

TEC Adjustments

The 2018 settlement made a series of adjustments for the “vintage project” costs incurred before 2016, which PJM previously had allocated under the DFAX method. FERC said the adjustments were made to bring the allocations in line with “what would have been credited or paid” if PJM had adopted the going-forward formula from the start.

The formula imposed monthly transmission enhancement charge (TEC) adjustments beginning in January 2016 and continuing through December 2025.

Linden argued that it did not need to make any of the payments created in the formula because it surrendered its firm transmission withdrawal rights on Jan. 1, 2018, about five months before FERC approved the settlement. PJM agreed that Linden did not need to pay TEC adjustments for 2018 to 2025, but they disagreed over TEC adjustments for 2016 and 2017.

Regarding TEC adjustments, the PJM tariff states, “If all responsible customers in a zone or merchant transmission facility are no longer subject to transmission enhancement charges under the PJM tariff during the period in which transmission enhancement charge adjustments are collected, then, during the portion of that period that such responsible customers are not subject to transmission enhancement charges, the payments from or credits to such responsible customers shall cease.”

Linden is the only responsible customer in its merchant facility, and it argued that the “period in which [TEC] adjustments are collected” began when FERC approved the settlement, because PJM “did not and could not collect any payments before then.”

FERC said that TEC adjustments began to accrue and were “collected” as soon as the settlement became effective in January 2016.

“The plain meaning of ‘collected’ unambiguously supports Linden,” the court ruled. “FERC has not identified a single example, in a dictionary or otherwise, where ‘collect’ means to accrue liability. Nor have we found any. This strongly suggests that ‘collect’ simply cannot bear that meaning.”

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ERCOT, Brazos Agree to Mediation in Dispute

ERCOT and Brazos Electric Power Cooperative agreed last week to enter mediation over the amount of money the bankrupt cooperative owes the Texas grid operator’s market.

The agreement paused a two-week proceeding in Houston before the U.S. Bankruptcy Court for the Southern District of Texas and followed testimony Thursday by Kenan Ögelman, ERCOT’s vice president of commercial operations.

Ögelman explained to the presiding judge that ERCOT is a nonprofit, “invoice-in, payment-out” manager of the state’s electric market. Defaults on any power purchases would be uplifted to its participants, he said.

“How does ERCOT pay? They’re a clearinghouse. What assets do they have?” Chuck Gibbs, an attorney representing Brazos’ largest member, said last month during an Infocast ERCOT Market Summit. (See ERCOT’s Legal Issues Continue to Mount.)

U.S. Bankruptcy Judge David Jones suggested the two sides reach an agreement over their differences “to make this all work. ERCOT … [is] a lifeblood for everybody that lives in this state.”

ERCOT and Brazos will mediate their dispute before Judge Marvin Isgur, the court’s other presiding judge. The bankruptcy proceeding is expected to resume in April.

At issue is $1.9 billion in market charges ERCOT assigned to Brazos during last February’s winter storm, when regulators ordered prices be kept at $9,000/MWh over four days. The cooperative is not disputing how much energy it bought to compensate for its own plants that did not run, but it argues it should owe about $800 million (21-03863).

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MISO Winter Fuel Security Surveys Now Permanent

With winter largely behind it, MISO staff last week told stakeholders that winter fuel security surveys will become an annual fixture.  

The RTO rolled out the weekly surveys to its fossil fuel generation fleet’s owners in early December, despite some members saying it was a burdensome task. At the time, MISO said it was receiving concerning reports about possible fuel scarcities ahead of the winter. The mandatory surveys ended last month.  (See MISO Sounds Alarm on Potential Winter Fuel Scarcity.)

During a Reliability Subcommittee meeting Thursday, staff’s J.T. Smith said the grid operator will refine the format to make sure it’s efficient and easier to use by next winter.  

“We know that this was a very ad-hoc, quick move,” Smith said of last year’s abrupt rollout. He said staff will examine whether the RTO is “asking the right questions or not.”

He admitted that not all generation owners responded to the survey after it was introduced. MISO has said some operators were “hit and miss” in filling out the weekly surveys.

“By the time we started to get decent information, it wasn’t as relevant anymore,” Smith said.

MISO said the survey results showed “healthy” fuel stockpiles this winter. It said the mild winter weather also contributed to the positive fuel management. Some operators reported slower train deliveries because of supply chain issues, labor shortages and harsh weather.

The RTO also delivered a refresher on how it positions itself for extreme weather. (See NERC Cold Weather Project Moves Forward.)

MISO’s Trevor Hines said each extreme weather event is different and the RTO prepares differently across heatwaves, arctic blasts, hurricanes or tornadoes.

He said the bulk of preparations rely on members’ most up-to-date offer data available. “We’re only as good as the information provided to us,” Hines said.

He said staff considers an extreme weather event’s unique risk before committing generation in advance. Hines said control room operators will monitor storm paths to anticipate what resources could become unavailable and will order early start times if it becomes too cold for generators to start up normally. MISO often dispatches additional units to account for forced outage risk, he said.

MISO is considering using extreme weather historical data to influence its decision-making, Hines said. He said going forward, staff might use past load data and generation- and transmission-failure data to predict response during unfolding events.

The RTO will also remove the “other” option when generation owners input data into the outage scheduler.

Senior engineer David Schoon said MISO suspects the generic option is overused as a cause code in the outage tickets that market participants submit for outages. In its place, staff will add several new outage explanation selections.

Staff said it’s important they understand why generation outages are occurring. MISO said it hasn’t meaningfully updated its outage-cause codes since 2014.

Some stakeholders said it isn’t immediately clear what causes generation to trip. They added that MISO’s outage ticket system is rigid and doesn’t allow members to retroactively modify their entries.

Staff said they would investigate why members can’t seem to edit outage notices.

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Nonprofits: NorthWestern’s Net-zero Goal Not Enough

Dozens of Montana organizations are demanding that NorthWestern Energy decarbonize by 2035, years ahead of its midcentury target for net-zero emissions.

More than 30 groups, including environmental nonprofits, public consumer advocates, health care professionals, consultants and a Montana State University professor, sent a letter Thursday to NorthWestern Board Chair Dana Dykhouse. The organizations demanded the utility decarbonize its fleet no later than 2035, saying the plan should be based on science and contain benchmarks.

The letter also said NorthWestern, which serves 753,600 customers across Montana, South Dakota and Nebraska in SPP and MISO, should model multiple scenarios that “eliminate the utility’s dependence on fossil fuels.”

“We urge you, as a fiduciary of NorthWestern Energy, to exercise your responsibility in a manner that guarantees the company’s long-term financial well-being,” the letter urged Dykhouse. “That can only be accomplished by requiring the company to adopt a meaningful climate strategy that will make it more resilient and prepared for the clean energy future.”

The same day, NorthWestern set a goal of achieving net-zero carbon emissions by 2050. Montana’s largest utility called it an “achievable target” in a press release.

“NorthWestern Energy begins this transition to an even cleaner energy future building on the considerable progress we have already made,” Energy CEO Brian Bird said. “We have the tremendous honor to be the stewards of this critical energy infrastructure that delivers safe and reliable energy to our region. Now is the time to raise the bar and start the transition to net zero by 2050.”

Northwestern said that last year, 56% of its electricity was generated from carbon-free resources, better than the electricity industry’s 40% average. It pointed out that its 10 hydroelectric facilities supplied 33% of the utility’s load.

Montana Environmental Information Center Co-Director Anne Hedges, one of the letter’s signatories, blasted the 2050 goal as a “PR move to improve lackluster” environment, social and governance perception. She said the target allows NorthWestern to raise emissions through 2035 by building more fossil fuel generation and pipelines.

“There are no benchmarks for reaching its 2050 goal in the electricity section of its business. Until we see NorthWestern actually plan for a clean energy future with benchmarks and actions that decrease its reliance on fossil fuels instead of increasing its reliance, it’s hard to take its proposal seriously,” Hedges said in an email to RTO Insider. “Anything short of meaningful planning and implementation is just more of the same from this laggard utility.”

She said NorthWestern’s largest financial investors have “raised concerns about companies that fail to plan for a lower carbon future” and added that financial analyst Moody’s has recently given the utility poor environmental and social scores. She said NorthWestern’s 2050 net-zero goal is only a “small step” and about decade behind other utilities in the region.

“Increased fossil fuel dependency means increased costs for customers, more expensive stranded assets and a failure to decarbonize according to the latest scientific research,” Hedges said.

NorthWestern did not respond to a request for comment.

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MISO, SPP Finalize JTIQ Results with MISO Transmission Duplicates

MISO and SPP on Friday announced that they have completed their Joint Targeted Interconnection Queue (JTIQ) study, though two of the project proposals might not proceed under the interregional planning effort.

The final study report’s portfolio includes seven projects, costing about $1.65 billion, designed to foster more generator interconnections and unclog the RTOs’ queues. If approved, the transmission projects could resolve 48 reliability constraints and deliver about $724 million in adjusted production costs savings to MISO and $247 million to SPP.

However, two of the JTIQ’s portfolio projects are also included in MISO’s long-range transmission portfolio. The transmission lines, in North Dakota and from South Dakota to Minnesota, could invalidate or seriously alter the RTOs’ plans for similar projects. (See MISO Stakeholders Uneasy Over Long-range Tx, JTIQ Overlap.)

MISO stakeholders have asked that SPP load bear some of the two projects’ costs, even if SPP’s benefits are shown to be small. Both projects are in the MISO footprint.

MISO planners have been firm that their long-range planning takes priority over the JTIQ study. Staff have also said the RTO’s benefits on the two projects eclipse SPP’s, and they have pointed out that the grid operators haven’t yet delved into meaningful cost-allocation negotiations.

According to the JTIQ study, the $424.5 million South Dakota-Minnesota line yields a $487 million APC benefit to MISO and a $32 million benefit to SPP. The $165 million North Dakota line results in $405 million in benefits to MISO and $56 million in SPP benefits.

The JTIQ study began in late 2020 and evaluated 59 project ideas. MISO kicked off its long-range planning in mid-2020.

In a joint statement accompanying the study’s release, MISO CEO John Bear and SPP CEO Barbara Sugg said the need to build transmission to accommodate increasing renewable energy requests “transcends boundaries.”

They said a lack of new transmission projects along their seam caused generation projects in both footprints “to drop out of the study process because costly network upgrades are triggered.”

MISO’s interconnection queue currently contains 127.1 GW of proposed generation. SPP has 97 GW worth of new generation in its queue. Both are overwhelmingly tipped toward renewable energy and storage projects.Their analysis shows the JTIQ portfolio could support a range of 28 to 53 GW worth of new generation along their seam.

“Both MISO and SPP have existing planning processes, and the JTIQ partnership allowed us to focus on future reliability risks based on the trends in our generation portfolios,” Antoine Lucas, SPP vice president of engineering, said in a press release. “The resulting portfolio of projects fully resolves the set of transmission constraints evaluated in the study, providing considerable reliability benefits to both RTO regions.”

The RTOs said they’re after an “equitable cost allocation mechanism between interconnection customers and load in MISO and SPP.” They expect cost-allocation discussions to continue “well into 2022.”

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NYISO Launches 2022 Grid Planning Study

NYISO on Wednesday presented stakeholders with a plan to clarify by year-end what increasing amounts of renewable energy mean for the grid over the next decades.

“I want to look at the evolution of load and net load shapes over time, i.e., load net of wind and solar, both behind the meter and in front of the meter, because that is really what the rest of the resources have to respond to,” Nicole Bouchez, principal economist for market design, told the Installed Capacity/Market Issues Working Group.

The multiphase study will first dive into the ISO’s Climate Change Phase I report from 2020 and follow with two studies coming this year that will have additional information.

The first new analysis planned is the Outlook study, followed by the Reliability Needs Assessment (RNA), which could possibly be leveraged for the Grid in Transition effort. (See NYISO Updates Grid in Transition Work and Plan for 2022.)

NYISO will examine “things like the distribution of hourly ramps over time, because in many ways that is what we are anticipating will be changing and what California has seen changing,” Bouchez said. “We’re also going to be looking at periods with low wind and solar and what that implies for these net energy and hourly ramps.”

Several stakeholders said that while some previous studies identified the dispatchable emission-free resource capacity that New York will likely need in the future, there is not much information available on the duration and magnitude of wind and solar lulls.

“It’s not just the energy amount, but how long and how often do we have a one-week lull; how many times do we have a two-day lull; and how many times do we have an hour or two lull — [in order] to understand what kind of pallet of dispatchable emission-free resources would most appropriately apply to the system conditions that we’re likely to see,” said David Clarke of Long Island Power Authority.

Accurate forward weather forecasting will become increasingly important, and the duration and frequency of wind lulls directly impact other resource requirements and other technology requirements as planners start to look out over a 10- or 20-year period, said Chris Wentlent of the Municipal Electric Utilities Association.

“So if we’re seeing a two- or three- or four-day lull, that creates a certain requirement as we think about storage going forward and storage capability,” Wentlent said. “Same thing with zero-carbon resources and the amount that we might need as backup in in those type of events.”

In terms of forward weather forecasting, Bouchez said she didn’t know of any studies specific enough to say at exactly what time of the year lulls will change, but that the second phase of the climate change study looked at historical data, and what scenarios could happen.

NYISO System Energy Forecast (NYISO) Content.jpgNYISO system energy forecast shows the Policy Case is lower as additional EE savings and PV adoption outweigh gains from electric vehicles and electrification. After 2030, CLCPA forecast is significantly higher than the Reference Case, largely driven by aggressive statewide electrification. | NYISO

 

NYISO commissioned Analysis Group to perform the Phase II study, which examined the potential impacts on reliability based on the electricity demand projections for 2020-2050 developed in the initial climate change study. Those include the impacts on load and resource availability from more frequent and severe storms and extended heat waves and cold snaps.

“We can definitely go back and re-leverage that information and look to see what we can leverage in terms of wind lulls, especially when we’re looking at periods of multiday potentially low solar,” Bouchez said. “We’ll see what we can pull to make those as realistic as possible, given what is expected in the future.”

The ISO plans to present the Phase I analysis in March and April in terms of market design and then the policy case from the Outlook study in the third quarter, Bouchez said. The RNA study would be presented in the fourth quarter.

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MISO to Loosen Some Interconnection Requirements

MISO said it will alter some interconnection rules so that generation owners can more easily replace generation at the same point of interconnection or share a single point of interconnection with other owners.

The RTO will remove the requirement that transmission owners must sign off on a shared facilities agreement among interconnection customers, saying there was never a need for transmission owners to be signatories to agreements for shared interconnection facilities.

During a March 1 Planning Advisory Committee, MISO’s Jackson Evans said that after the RTO’s shared network upgrade process was introduced in 2019, multiple disputes arose between interconnection customers and transmission owners over who has ownership rights to interconnection facilities and who would be responsible for their maintenance.

“It almost led to multiple withdrawals” in the interconnection queue, Evans said.

MISO will still require interconnection customers wishing to share interconnection facilities to submit a shared facilities agreement upon filing their request. However, that agreement will no longer be tied to the transmission owners’ interconnection facilities.

Customized Energy Solutions’ Ginger Hodge thanked MISO for the changes and ending a year of “delays, disagreements and frustrations.”

The grid operator said it will prepare a FERC filing for either April or May. The revised process would apply to entrants in the generator interconnection queue’s next cycle

The RTO also said it will make it easier for generation owners to replace units, allowing generators to request longer-term suspension reliability studies with the replacement requests. Previously, the grid operator granted reliability assessments only for the gap period between winding down generator operations at the outgoing unit and the replacement unit’s startup.

MISO added that it will reduce its decision time to approve suspensions for units set to be demolished and replaced. It also said it can shorten a required 26-week notice period to 30 days for generator suspensions in certain replacement situations.

The RTO intends to file the replacement generation process changes with FERC sometime in May.

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NY Officials Set 2022 Schedule for Climate Plan

New York officials on Thursday outlined a schedule to complete a final scoping plan by year-end to reduce economywide greenhouse gas emissions 40% by 2030 and no less than 85% by midcentury from 1990 levels.

Sarah Osgood (NYDPS) Content.jpgNYCAC Director Sarah Osgood | NYDPS

The Climate Action Council (CAC) in December approved a draft scoping plan that sets the approximate steps needed to achieve the emission limits set by the Climate Leadership and Community Protection Act (CLCPA).

Based on the discussion that occurred on the draft scoping plan, CAC staff pulled out a few topics on which council members do not concur and additional deliberation is needed, said CAC Director Sarah Osgood.

The council will hold nine, three-hour public comment hearings throughout the state between April 5 and May 11, two of them virtual and the remainder in person, with a mid-June deadline for submitting written comments.

Undefined Terms

Of the terms the council will deliberate, the state’s approach to transitioning the gas system is “of great interest to many of the council members,” Osgood said.  “It sounds like we need to determine what New York’s approach to decarbonizing the gas system should look like.”

If council members do not reach “100% agreement” on the topic, Osgood said there is “still plenty of room for additional progress.”

In approving the minutes of the December meeting, Donna L. DeCarolis, president of the National Fuel Gas, said she wanted to repeat her opposition to the council’s adoption of the term “fossil gas” in place of natural gas, noting that the term is not defined by the Public Service Commission or under state law.

Gavin Donohue, president and CEO of the Independent Power Producers of New York, agreed with DeCarolis and asked that their “no” votes be identified by name in the minutes, along with that of Dennis Elsenbeck, president of lithium-ion storage developer Viridi Parente.

Bob Howarth (NYDPS) Content.jpgBob Howarth, Cornell University | NYDPS

The CAC voted to apply vote breakdowns consistently throughout the minutes.

The council also will deliberate the potential applications of advanced fuels, including potential regulatory mechanisms, limits or conditions for their use, and the role of research, development and demonstration in these areas, Osgood said.

“Finally, we see room for further progress on carbon pricing policies, potential regulatory mechanisms around funding, the role of private funds and private financing, and how to align markets to help facilitate the needed resources,” Osgood said.

Beyond the cost benefit analysis, issues of how the state will pay for initiatives seem to be absent from the discussion and need to be included, said Bob Howarth, professor of ecology and environmental biology at Cornell University.

Urgency and Equity

The Intergovernmental Panel on Climate Change (IPCC) 6th assessment report issued on Feb. 28 is focused on impacts, adaptation and vulnerability. Much like prior IPCC reports, there are calls to action and updated forecasts for the causes and effects of climate change, said Doreen Harris, President and CEO of the New York State Energy Research and Development Authority (NYSERDA).

Doreen Harris (NYDPS) Content.jpgNYSERDA CEO Doreen Harris | NYDPS

“This report also paints a stark picture for humanity, warning that climate change risks are greater than thought,” Harris said. “In fact, the final two sentences of this new report really say it all, and I quote, ‘the scientific evidence is unequivocal: climate change is a threat to human well-being and the health of the planet. Any further delay in concerted global action will miss a brief and rapidly closing window to secure a livable future.’”

This week, the state Department of Environmental Conservation will put out the disadvantaged community criteria and maps, said Commissioner Basil Seggos, who also introduced the DEC’s first deputy commissioner for equity and justice, Adriana Espinoza.

The CAC this year will include advancing the integration of equity throughout the scoping plan and ensuring that it’s central to the council’s decision-making processes, Seggos said.

Basil Seggos (NYDPS) Content.jpgDEC Commissioner Basil Seggos | NYDPS

As the council approaches the topics set aside for further deliberation, a couple of questions to consider are how equity and justice will be considered and weighted, and what role the Climate Justice Working Group (CJWG) should have in shaping that approach as partners in this work, Espinoza said.

“The group’s meaningful involvement, combined with a robust public input process that we were just discussing will help ensure that the [CLCPA] is informed by priorities of disadvantaged communities, and as concerns from the [CJWG] are representative of concerns expressed by frontline communities, so these concerns must be considered when we deliberate,” Espinoza said.

She reminded the council that the working group “previously shared a lot of really poignant and helpful comments and resources about integrating equity into the council’s work” and that “we can consider reviewing these resources and others during future discussions to ensure that our shared commitment to equity and justice is clear in the final scoping plan.”

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NH Large Business Sector Takes Biggest Hit in Revised EE Budget

A drop in anticipated funding will significantly alter New Hampshire utilities’ plans for their large commercial and industrial energy efficiency programs.

Liberty Utilities, Unitil (NYSE:UTL), Eversource Energy (NYSE:ES) and New Hampshire Electric Cooperative filed a revised 2022-23 energy efficiency program plan on Tuesday to accommodate a 47.5% cut in their originally proposed $287 million budget for the period. The utilities’ large business C&I budget had the biggest decrease across the program offerings, dropping from $88.3 million to $29.4 million.

The NHSaves EE program went into lockdown last November after the Public Utilities Commission rejected the utilities’ proposed 2021-2023 Triennial Energy Efficiency Plan, which would have more than doubled spending. (See NH EE Plan Approaches 2nd Year Without Funding Certainty.)

New Hampshire Gov. Chris Sununu restored funding certainty on Feb. 24 by signing HB549, a bill that establishes funding rules for NHSaves. For this year, the law caps funding at the 2020 level and allows annual increases based on inflation. In addition, the law directed the utilities to file a revised 2022-23 program plan at the new funding level by Tuesday.

The utilities estimated in their revised plan that the large C&I sector program will serve 2,595 customers in 2022-23, which is 2,273 fewer than they expected to serve for the same period under their 2021-23 plan in September 2020. Annual kWh savings for the sector program will decrease by 136.1 million to 56.5 million, while annual Btu savings will decrease by 110.7 million to 135.3.

Offerings for the large C&I segment, which includes energy users with an average annual demand of at least 200 kW or 4,000 Therms, are pared down in the revised plan to incentives only for EE projects. Offerings under the original plan proposal included:

  • expanding retrofit services;
  • developing segment-specific services, such as chiller optimization for manufacturing;
  • exploring opportunities to integrate combined heat and power systems with energy-efficient projects; and
  • pursuing a codes and standards initiative.

Appeals

In its Nov. 12 order, the PUC said the utilities’ triennial plan was a burden on ratepayers and stood behind its decision to deny the plan, despite requests for rehearing and appeals to the state’s courts.

Legislators moved quickly at the start of the year to send HB549 to the governor, so the PUC is no longer able to change the basic components of the EE program and how it is funded. (See Legislators Step into NH’s Battle over EE Program.)

Passage of the bill means utilities are beginning to reopen programs they had suspended due to funding concerns, Sam Evans-Brown, executive director of Clean Energy NH (CENH), told NetZero Insider.

But the new law does not settle all outstanding issues from the PUC’s order, he said.

On Feb. 7, CENH and the Conservation Law Foundation (CLF) filed an appeal of the order with the New Hampshire Supreme Court after a Superior Court judge denied an earlier request for a temporary injunction.

The appeal says the commission did not follow the law in its order when, as the petitioners claimed, it essentially “dismantled” the Energy Efficiency Resource Standard, a framework the commission established in 2016. Under the EERS, programs are based on annual savings of kWh or Btu, and a budget is set to meet those annual savings.

Instead of focusing first on savings targets, the PUC’s order focused “solely” on rates and program budget, which “signaled a sharp departure” from the EERS, the appeal said. And the commission, the appeal claimed, failed to give stakeholders a chance to comment on that departure from the standing framework.

“What [HB549] does not do, that a repeal of the PUC’s order would, is re-establish the [EERS] policy framework,” Evans-Brown said. “There’s a symbolic policy discussion that can happen legally over whether the PUC had the right to dismantle the framework without telling anybody that’s what they were planning on doing.”

The state’s utilities and the nonprofit Listen Community Services each filed separate Supreme Court appeals in early February that are substantively similar to the CENH-CLF appeal.

On Feb. 10, the commission reached a settlement with the Office of the Consumer Advocate, which had asked the Supreme Court to stay the commission’s November order. Under the agreement, the OCA said it would withdraw its request and the commission reverted current EE program rates to the 2020 level, which is also what HB549 does.

The new law, however, takes the additional step of tying annual increases to inflation.

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ISO-NE to Publish Auction Results after Unprecedented Delay

ISO-NE will publish the results of its capacity auction next week after the D.C. Circuit Court of Appeals lifted a stay retaining the capacity supply obligation of the Killingly Energy Center.

The grid operator confirmed its plans in a news release Tuesday, ending the uncertainty surrounding the capacity auction since it took place in early February. (See Killingly Uncertainty Could Delay Capacity Auction Results Another Month.)

ISO-NE has also begun plotting out the schedule for next year’s capacity auction, FCA 17, a process which has been delayed as well by the Killingly saga.

In a presentation to the NEPOOL Participants Committee on Thursday, ISO-NE Resource Qualification Manager Alex Rost said that activities for FCA 17 will start in April and that the auction will take place on March 6, 2023, a month later than usual.

The process will be compressed in at least two sections to make up for the lost time, Rost said.

That plan is not final, and ISO-NE said it’s asking market participants for feedback before it publishes the schedule.

Financial Assurance Proposal Update

Also at Thursday’s Participants Committee meeting, Competitive Power Ventures delayed a vote on its proposal to revamp New England’s financial assurance rules, adding new penalties for developers who miss key milestones. (See NE Stakeholders Propose Retirement, Financial Assurance Changes.)

The proposal, which has been discussed at several NEPOOL stakeholder meetings in the last few months, recently came under criticism from the renewable energy advocacy group RENEW Northeast.

RENEW wrote in a memo that the changes call for “excessive levels of Financial Assurance that would create an unnecessarily high burden for new entry, beyond what would be needed to incent the proper behavior.”

The group said it’s not opposed to increasing the required FA before each capacity auction, but that level should be a “careful balance” that doesn’t create overly punitive barriers for entry.

RENEW also challenged some of the language in CPV’s proposal as unclear. CPV is expected to revisit the proposal in other NEPOOL meetings over the next few weeks.

Consent Agenda

The committee also unanimously approved revisions to Planning Procedure No. 11 (Planning Procedure to Support Geomagnetic Disturbances) to conform to and support the requirements of NERC Reliability Standard TPL-007-4 (Transmission System Planned Performance for Geomagnetic Disturbance Events), as recommended by the Reliability Committee at its Feb. 15 meeting.