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November 12, 2024

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MISO Planning Subcommittee Briefs: Feb. 8, 2022

MISO has formed a special task team to explore rerouting transmission flows during heavy congestion periods.

The Reconfiguration for Congestion Cost Task Team’s meetings are being held behind closed doors, as transmission reconfiguration discussions contain confidential and market-sensitive information.

Speaking during Tuesday’s Planning Subcommittee meeting, Chair Ray McCausland said the group will review past real-world examples of the system’s congestion, necessitating privacy. The group first met in January and will meet again Feb. 17.

The team reports to the Reliable Operations Working Group, which also holds non-public meetings.

MISO’s Independent Market Monitor has recommended members use reconfiguration plans along with ambient adjusted transmission ratings to ease constraints. The Monitor reported that the RTO’s real-time congestion costs more than doubled from late 2020 to late 2021 as more transmission elements began binding year-over-year. Record wind output and high natural gas prices increased the cost of re-dispatching the system to manage constraints, the IMM said.

MISO Ponders Generation as Non-Tx Alternatives 

MISO is considering opportunities to convert retired generators to synchronous condensers and serve as non-transmission alternatives.

Some stakeholders have said the grid operator’s increased reliance on renewables may force preserving some generators so they can provide inverter services.  

Staff’s Jeanna Furnish said generation assets served as temporary solutions in other RTOs while long-term transmission solutions were built.

Generation owners interested in making the conversion would need to be evaluated under MISO’s annual transmission expansion planning process’ (MTEP) transmission alternatives selection process.

Furnish said staff also believes its existing Tariff Attachment Y process can help govern decisions on converting retiring generators to into synchronous condensers. Under Attachment Y, the RTO analyzes whether a retiring generator must keep operating under a system support resource agreement for reliability reasons.

Furnish said MISO must still develop written agreements, operating procedures, and compensation for generators.

MISO Debuts ’22 Cost Estimates

MISO also introduced its 2022 draft cost estimates for transmission structures, substation equipment construction, and other elements.

The MTEP 22 cost-estimation guide contains updates that reflect higher prices of materials. The RTO has also added costs for aluminum conductor composite core and 765-kV transmission that is interchangeable to about 640 kV.

The grid operator uses the guide to evaluate transmission alternatives in its annual system planning work. Stakeholders have until March 11 to review the draft and submit revisions.

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ISO-NE Asks FERC to Expedite Killingly Rehearing Decision

New England is still awaiting results of Monday’s capacity auction, and the wait could go on longer than usual as ISO-NE has to wait for federal action to announce them (ER22-355-001).

The grid operator on Wednesday asked FERC to take expedited action on a rehearing request from NTE Energy in regards to the Killingly Energy Center. A court ruling on Friday ordering ISO-NE to allow the under-development Connecticut gas-fired power plant into Forward Capacity Auction 16 has added a large amount of uncertainty to the process.

The RTO moved to terminate Killingly’s capacity supply obligation in November, a decision that was upheld by FERC in January. But the D.C. Circuit Court of Appeals ruled that FERC must answer NTE’s request for rehearing before the termination can be enforced. (See Killingly Stays Alive After DC Circuit Halts FERC’s Termination Order.)

“Expedited action is necessary so that ISO-NE may provide to New England stakeholders and file with the commission the results of Forward Capacity Auction 16,” the RTO said in a filing to FERC on Tuesday. “Prompt resolution of the continuing uncertainty regarding the status of Killingly will also enable the ISO and market participants to conduct qualification activities related to FCA 17, which is scheduled to be conducted in February 2023.”

The RTO asked FERC to issue an order responding to NTE’s rehearing request by Thursday.

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FERC Rejects PJM Redefinition of ‘Designated Entity’ Under Order 1000

FERC on Tuesday rejected a filing by PJM in its Order 1000 compliance docket that would have updated the definition of “designated entity,” agreeing with a coalition of stakeholders that it infringed on their due process rights (ER13-198-008).

The commission not only disagreed with the RTO’s arguments for why the update was necessary; it also said that “PJM improperly filed revisions to its Operating Agreement as a compliance filing in response to an order that was final and required no compliance.”

In its September filing, PJM said the term “designated entity” was added to the OA at the time it submitted its Order 1000 compliance filing to refer to either an incumbent transmission owner or non-incumbent developer designated by the RTO to “construct, own, operate, maintain and finance immediate-need reliability projects, short-term projects, long-lead projects or economic-based enhancements to expansions projects that are selected through PJM’s competitive proposal window process.”

But the RTO said it identified “imprecise and inconsistent usage” of the term in Schedule 6, resulting in conflicting interpretations as to how the RTO should use the Designated Entity Agreement. It argued that the definition was too broad and was “intended to apply only to transmission projects sponsored by an incumbent transmission owner or non-incumbent transmission developer through the competitive proposal window process.”

While references to short-term projects, long-lead projects or economic-based enhancements to expansions “clearly applied to those projects submitted through PJM’s competitive proposal window process,” the RTO failed to differentiate between immediate-need reliability projects selected through the competitive proposal window process and those exempted from the competitive proposal process. It said the term “designated entity” was “not intended to apply to those unsponsored immediate-need reliability projects exempted from the competitive proposal process that are identified and selected by PJM and designated to the incumbent transmission owner in the zone in which the project will be located.”

PJM proposed revising the term to only apply to those immediate-need reliability projects, short-term projects, long-lead projects or economic-based enhancements selected in a competitive proposal window pursuant to the OA. The RTO said the “limited proposed updates” to the earlier Order 1000 compliance filing “will avoid potential confusion and eliminate any conflicting interpretations as to how PJM originally intended to use the Designated Entity Agreement.”

Stakeholder Protest

Several PJM stakeholders jointly protested the filing, including LS Power, American Municipal Power, the Public Power Association of New Jersey, the PJM Industrial Customer Coalition, the Indiana Office of Utility Consumer Counselor and the D.C. Office of the People’s Counsel.

The protesters argued that PJM violated the Federal Power Act by making the filing without approval from stakeholders, saying the RTO was taking an “unprecedented step” and that it was “attempting to avoid a vote from the Members Committee and meeting its burden under Section 206.” They argued that the term “designated entity” explicitly includes immediate-need reliability projects, short-term projects, long-lead projects and economic-based enhancements, and that PJM offered no proof of confusion about this definition.

They also argued that PJM’s “piecemeal, after-the-fact compliance filing approach” was inconsistent with due process principles that indicate parties should have the opportunity to protest the full compliance filing at the outset and that the commission should review the entire compliance filing “holistically.”

PJM countered that the protesters cited no precedent to support the claim that an updated compliance was prohibited or improper and that they “misstate the law” when claiming the commission lacks authority to consider the filing.

“When in 2015, the commission accepted PJM’s proposed tariff revisions implementing the requirements of Order 1000 in the PJM fourth compliance order with no further compliance directives, the accepted tariff revisions, including the definition of designated entity, became the rate in effect,” FERC said. “If PJM thinks that revisions to the definition of ‘designated entity’ and certain provisions of Schedule 6 would also be consistent with Order 1000, it should proceed by following its tariff procedures for submitting a Section 205 filing. Alternatively, if PJM believes its current tariff is unjust and unreasonable, it may file under Section 206.”

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NY Stakeholders, Residents Split on HVDC Tx Projects

New York’s plan to buy power from two new transmission lines being built to bring over 2.5 GW of renewable energy into New York City drew more than 17,000 comments by Monday, with opinion generally in favor of the entirely in-state project but divided on the project that would import electricity from Hydro-Québec in Canada (15-E-0302).

The state in September selected two transmission projects as Tier 4 renewable resources under its Clean Energy Standard. The 1,300-MW Clean Path New York (CPNY) project, developed by the New York Power Authority (NYPA) and Forward Power, a joint venture of Invenergy and energyRe, would bring upstate solar and onshore wind into the city. The 1,250-MW Champlain Hudson Power Express, developed by Transmission Developers Inc. and Hydro-Québec’s U.S.-based subsidiary HQUS, would run from the state’s border with Canada to Queens, with portions of the line running underneath the Hudson River.

<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686782404.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

CPNY Contracting Summary

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Regional development entities, county legislatures and labor union members supported both projects for creating an estimated 10,000 jobs statewide with $8.2 billion in in-state economic development investments. Others touted the new lines’ environmental benefits.

Julie Tighe, president of the New York League of Conservation Voters, said that CPNY is projected to reduce the state’s greenhouse gas emissions by 2.4 million metric tons annually, reducing overall emissions from the state’s electricity sector by 22%. CHPE would reduce GHG emissions by 37 MMT through 2040 and establish a $117 million environmental trust fund to improve water quality across the Hudson, Harlem and East rivers, as well as Lake Champlain, she said.

The projects are expected to deliver 18 million MWh of renewable energy per year to New York City, representing more than a third the city’s annual electricity consumption.

CPNY has a planned June 30, 2027, commercial operation date, while CHPE has an estimated COD of Dec. 15, 2025.

Winter Peak

The Independent Power Producers of New York (IPPNY) reiterated their longstanding opposition to CHPE. (See Enviros, Generators Oppose Canadian Hydro Line to NYC.)

“It is entirely possible that the [state’s] 2040 zero-emissions goal can be met at a lower cost with greater net benefits with the CPNY project, along with other zero-emission technology that does not require expensive new transmission lines,” IPPNY CEO Gavin Donohue said.

Not only would the CHPE project bypass both existing and new upstate renewable generation, it will not be able to meet the city’s power needs during winter months because Quebec load would take priority, IPPNY said.

HQUS CHPE Contracting Summary (NYSERDA) Content.jpgHQUS/CHPE Contracting Summary | NYSERDA

 

With the state’s electric system projected to become a winter-peaking system by 2041, “it is concerning that the HQUS project was selected despite being only able to provide capacity during nearly half the life of the proposed 25-year contract, raising serious questions regarding the reliability benefits of the project,” Donohue said.

IPPNY cited New York State Energy Research and Development Authority’s own benefit-cost analysis as showing CPNY would produce 34% greater net benefits than those yielded by CPHE, and the combined awards producing lower net benefits than if NYSERDA contracted CPNY alone.

Environmental, First Nations Concerns

The Sierra Club asserted that hydropower from mega-dams like the ones in Quebec is not renewable energy. The dams’ reservoirs can flood and destroy thousands of trees of the boreal forests that absorb tons of CO2 out of the atmosphere, and submerged vegetation causes more methane and CO2 to be released, said Catherine Skopic of the Sierra Club NYC Group and Atlantic Chapter.

In addition, dredging to lay the cables would stir up toxic polychlorinated biphenyls on the riverbed and further contaminate the waters of the Hudson River, Skopic said.

“The Hudson River is a fragile and important ecosystem, and under no circumstances should we be dredging up 100 years of buried toxins to build this pipeline,” Sierra Club volunteer Tara Noble added.

Some Bronx and Queens residents said they were more concerned about the air they breathe than about potential dangers from churning up riverbeds.

Since 2001 NYPA has operated four natural gas-fired peaker plants in the Mott Haven and Port Morris neighborhoods, promised at the time to be temporary, which neighborhood advocacy group South Bronx Unite said “have instead become permanent fixtures, burdening our community with additional air pollution.”

The group said those two neighborhoods have asthma hospitalization rates eight times higher than the national average and 21 times higher than any other neighborhood in the city.

Both transmission projects are essential to meeting decarbonization goals in New York City and improving public health, Queens resident Gianna Lum said.

“A just transition from fossil fuels is not only a priority to protect future generations,” Lum said. “The current peaker plant in Western Astoria is polluting nearby [public] housing and putting the health of vulnerable community members at risk.”

The Mohawk Council of Kahnawake, Quebec, said it supports CHPE and has agreed with Hydro-Québec on terms to host the new Hertel substation and the new 36-mile transmission line to be built through its territory.

While reparation claims by other indigenous groups for past harms by Hydro-Québec “must clearly be addressed with the relevant authorities, it is important to point out that the hydropower installations in question were not built as a part of the CHPE project,” the council said.

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Gov. Polis Speaks on Colorado’s Carbon-free Future

DENVER — Gov. Jared Polis last week joined energy industry stakeholders at the Colorado Solar and Storage Association’s 2022 Solar Power and Energy Storage Mountain West Conference to discuss the state’s future renewable energy economy.

Despite having trekked through a foot of snow to make it to the Feb. 2 conference, Polis was grateful to be able to speak for a live audience.

Writing in Colorado’s Greenhouse Gas Pollution Reduction Roadmap issued in January, Polis said that GHG reduction commitments from electric utilities are key to meeting the state’s carbon goals.

On Wednesday, the governor announced that most of the state’s largest utilities have submitted required clean resource plans showing regulators how they plan to achieve 80% emissions reduction compared to 2005 levels by 2030. He believes it’s possible that utilities will reduce emissions beyond the 80% goal.

“That’s the floor not the ceiling, but it’s a very, very aggressive floor,” he said.

Coal plant retirements are also an important piece of the state’s climate plan. As aesthetically displeasing as they are bad for air quality, coal plants are “urban blights” that only cost ratepayers more money, Polis said.

“Coal is our most expensive form of electricity in Colorado … and we really have to ask ourselves how long are we going to force Coloradans to pay more on their electric bills just to keep our coal plants going?”

With many of the state’s utilities moving toward carbon-free generation, Polis is most interested in keeping these renewable energy projects as low-cost as possible. With some “downward pressure” on the solar industry, Polis is optimistic that solar projects could come in under 3 cents/kWh, but he lamented the supply issues and costs the industry faces.

“We hope that President Biden discontinues the tariffs for China. That will help a lot,” he said. “Because whenever you think of the geopolitical landscape … the clean energy transition is something that should bring us together. We need the lowest cost solar panels possible, and I don’t care where they’re made. We need to get them done; we need to get the cost down.”’

On Friday, Biden extended the tariffs, but softened the blow by continuing an exemption for bifacial panels and doubling the amount of imports that can enter the country duty free each year, from 2.5 GW to 5 GW. (See Biden Extends Tariffs on Imported Solar Panels.)

Colorado has also made efforts to decarbonize buildings and transportation. Polis touted that, as of last month, electric vehicles made up 13% of the state’s total new vehicle sales.

Besides promoting EV sales, Polis hopes the state can modernize transportation as a whole with money state regulators budgeted to help improve air quality.

“In November, as part of our state budget, we proposed nearly half a billion dollars of one-time investments to improve air quality and accelerate the adoption of clean technology that improves the health of all Coloradoans and helps Colorado meet our climate goals.” Polis said.

The state hopes to use the funds to “improve transit opportunities, electrify school buses … replace the state’s oldest, polluting diesel trucks and grow the market for electric bicycles, giving rebates for rideshare programs and subsidies for low-income folks to be able to commute to work on e-bikes.”

Planning Ahead: Organized Markets

Looking to the next decade, Polis said joining an organized market will be integral to achieving the state’s long-term climate goals.

“In 2019, I signed into law the Colorado Transmission Coordination Act, which directed the PUC [Colorado Public Utilities Commission] to investigate the possible merits of joining an organized market,” Polis said.

In December, the PUC released a report saying that state utilities could save up to $230 million by joining a wholesale electric market. (See Colo. PUC: State Could Save up to $230M in Wholesale Market.)

“We now know what we suspected: that Colorado’s participation in a regional market is likely to reduce costs, improve the safety and reliability of the grid and advance our climate and clean energy goals,” the governor said.

In January, Xcel, Public Service Company of Colorado, Platte River Power Authority and Black Hills Colorado Electric chose to join SPP’s Western Energy Imbalance Service, which Polis described as “progress in the right direction.” (See Colorado Utilities Choose WEIS over WEIM.)

“A Western market is really an important part of reaching our clean energy goals faster and at a lower cost,” he said.

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FERC Auditors Find FirstEnergy Accounting Irregularities

FirstEnergy’s (NYSE:FE) long-time use of an internal service company to handle the day-to-day accounting for its transmission companies, local distribution companies and former power plant companies violated a number of federal regulations, a FERC audit has concluded (FA19-1).

FERC’s Division of Audits and Accounting issued an 85-page report Friday detailing the findings of the audit it announced a year ago. The company has largely agreed with its findings and committed to refunding $9.6 million to customers, the audit report noted.

The close examination of FirstEnergy’s accounting practices discovered that the cost of routine operations — from day-to-day local utility customer services to corporate political lobbying — somehow were reflected as other costs in accounting — for example, in transmission company overhead — and consequently may have been passed on as customer charges.

It also found that the internal company FirstEnergy had created to handle back-office accounting, FirstEnergy Service Co. (FESC), accounted for routine distribution company operating and overhead expenses as, for example, construction works in progress, though the expenses had nothing to do with construction.

In some cases, those mislabeled construction cost were deferred, meaning they were temporarily listed as a loss, only to be later amortized and collected in delivery rate increases.

FESC “capitalized overhead costs to Construction Work in Progress-Electric using an allocation method that was not based on actual time employees were engaged in construction activities based on timecard reports or on a representative time study,” the report said. “This may have led to FirstEnergy’s subsidiaries capitalizing costs to [that account] that did not have a definite relationship to construction. As a result, the companies may have overstated construction costs recorded in [the electric plant in-service account] as well as accumulated depreciation, depreciation expenses and accumulated deferred income tax (ADIT) balances, and understated operating expenses.

Relation to Bribery Scandal

The audit closely examined the role the unorthodox accounting practices played in the largest political scandal in Ohio’s history: FirstEnergy’s contributions of at least $70.1 million to “dark money” groups to bankroll a yearslong campaign to win legislative approval of a $1.1 billion subsidy for two nuclear power plants formerly owned by the company. Ohio lawmakers approved the bailout in 2019 in legislation known as House Bill 6.

Passage of H.B. 6 turned out to have been the key event in an ongoing federal probe into political corruption at the state level.

Lawmakers repealed the nuclear bailout provision of H.B. 6 in March 2021, eight months after federal prosecutors indicted former Ohio House Speaker Larry Householder (R) and four of his associates on federal racketeering charges. Two of the associates have pleaded guilty and are awaiting sentencing. A third killed himself. Householder and the fourth are awaiting trial.

FirstEnergy pleaded guilty to conspiring with public officials in a deferred prosecution agreement and agreed to a $230 million fine. The federal investigation is continuing, and further indictments are possible.

The audit found that “FESC improperly accounted for and improperly reported lobbying expenses, donations and other costs that lacked proper supporting documentation or were misclassified” as unsupported costs. The costs were charged to FirstEnergy subsidiaries as well as to the corporation. This led the subsidiaries to improperly account for and report the costs in their respective accounting records.

The report added that “out of $70.9 million of payments, $44.5 million was recorded in the accounts of [former power plant subsidiary] FirstEnergy Solutions [FES], and $25 million was recorded in FirstEnergy’s own books.”

FERC audit staff’s “discussions on internal controls during on-site interviews of FESC employees raised audit staff’s concerns about the existence of significant shortcomings in FirstEnergy and its subsidiary companies’ controls over financial reporting, including controls over accounting for the costs of civic, political and related activities, such as lobbying activities, performed by and on behalf of FirstEnergy and its subsidiaries,” the report said.

“Moreover, these controls may have been circumvented in ways designed to conceal the nature and purpose of expenditures made and, as a result, that led to the improper inclusion of lobbying and other nonutility costs in wholesale rate determinations.

Payments to Randazzo

The report details $22.8 million in payments FirstEnergy made between 2010 and 2018 to a pair of tiny Ohio companies incorporated by veteran utility lawyer and lobbyist Samuel Randazzo. Gov. Mike DeWine appointed Randazzo chair of the Public Utilities Commission in February 2019, a few weeks after the company made a final $4.3 million payment to Randazzo. DeWine has said he was unaware of the payment.

The company charged $20.9 million of the $22.8 million it paid to Randazzo to transmission companies and some of the corporation’s 10 local distribution companies, which the audit did not identify.

“FirstEnergy represented to audit staff that it will make refunds of around $185,000 to retail and transmission customers and has already made the related accounting entries to correct charges of $6.7 million allocated to electric plant in service of the [franchised public utilities] and transmission companies and to prevent those expenses from impacting future rates,” the audit said.

Randazzo resigned in November 2021, four days after FBI agents raided his downtown Columbus condo. He has not been charged.

The report also revealed that FirstEnergy told FERC staff auditors it was investigating $28.8 million in payments to 16 “entities associated with an individual identified by FirstEnergy” but not revealed in the report.

Most of those payments ($19.7 million) were charged to local distribution companies, while $1.1 million went on the books of FirstEnergy’s transmission companies, $2.2 million to FES and $5.8 million to the corporate books.

The audit report could bolster an effort by the Ohio Consumers’ Counsel (OCC) to convince the Ohio PUC to compel FirstEnergy to submit discovery in a case regarding the company’s political expenditures pending before the commission. The OCC, a state agency charged with representing consumers in utility issues, again pressed a PUC administrative judge for discovery within hours of the FERC audit release.

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Washington Considers EV Fee to Offset Lost Gas Taxes

Washington lawmakers are considering a bill to apply a per-mile charge to electric vehicles to compensate for expected lost gas tax revenue over the next few decades.

The bill (HB 2026)  introduced by Rep. Shelley Kloba (D) calls for EVs to pay the state a “road usage charge” of 2.5 cents per mile starting in July 2025. That fee would be mandatory for EVs bought as of that date and voluntary for EVs purchased prior to that date. The mandatory annual fee would be capped at $225, while the voluntary fee would be limited to $175.

The bill would allow certain hybrid vehicles to participate in the road usage charge on a voluntary basis beginning July 1, 2026. The Washington State Department of Licensing and a joint subcommittee of the House and Senate transportation committees would be charged with evaluating the program and recommending improvements to the main House and Senate transportation committees by Jan. 1, 2029.

The money raised by the charges would go to various Washington transportation funds.

The Licensing Department would be required to offer EV owners one or more methods of reporting miles driven, including one based on submittal of periodic odometer mileage. The department also must offer one or more automated reporting methods. The state could use private sector services to manage the process.

At a Thursday hearing before the House Transportation Committee, Travis Dunn, vice president of consulting firm CDM Smith, said Washington’s gas tax revenues are expected to shrink by half by in the next two decades, assuming that 27% of the state’s vehicles will be EVs by 2040.

“Another factor is that cars will become more fuel-efficient and require less refueling,” said Reema Griffith, executive director of the Washington State Transportation Commission.

“HB 2026 gets us on a path to steady transportation revenue,” Rep. Emily Wicks (D) said. “The gas tax is a fleeting revenue source,” testified Jane Wall, executive director of Washington’s County Road Administration Board.

Inslee Wary of EV Fee

However, Gov. Jay Inslee opposes the bill in its current form, said Debbie Driver, Inslee’s senior transportation adviser. One objection was making the EV per-mile charge mandatory in 2025. “It could dissuade people from buying an EV,” she said.

Driver could not predict whether Inslee would veto all or part of the bill, if passed.

In a follow-up e-mail, Inslee spokesperson Mike Faulk wrote: “Our office’s concerns are there are still key untested elements to this policy, including the impact a mandatory [road usage charge] might have on a consumer’s choice to purchase a new EV, privacy concerns and impacts to low-income drivers with longer commutes.”

Faulk wrote that Inslee does not oppose road usage charges but wants more due diligence on the matter — especially on the effects of gas taxes and EV fees on the poor. If low-income families end up paying EV charges, the governor wants those charges to be less than what such families pay in gas taxes, Faulk said.

Faulk also noted that Inslee’s fiscal 2022/23 budget proposal asked for $100 million in rebates to make EVs accessible to low- and moderate-income Washingtonians. The proposed rebates are $7,500 for new EVs and $5,000 for used vehicles. Inslee has proposed an additional $5,000 rebate for people making less than 60% of the state’s median income.

At the hearing, EV interests and some EV owners supported the proposed charge. “It’s a more equitable approach for EV drivers to pay their share,” Peter Chipman, policy director for Plug In America, said.

Meanwhile, a half dozen private citizens testified against the bill, arguing that it would represent an extra unneeded tax.

“It’s too early to make such a systematic drastic change,” private citizen Eric Pratt said. “This assumes everyone will jump on the electric vehicle wagon,” Jeff Pack of Washington Citizens Against Unfair Taxes said.

Kloba said the proposed EV charge replaces tax revenue and does not add to drivers’ tax burdens.

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NEPOOL Markets Committee Briefs: Feb. 8, 2022

Committee Declines to Recommend Additional FA Changes

The NEPOOL Markets Committee on Tuesday voted against recommending two pieces of a proposal from Competitive Power Ventures to change ISO-NE’s financial assurance rules.

The meat of the proposal, aimed at increasing the consequences for projects that don’t meet development milestones required for participation in the Forward Capacity Market, is under consideration by NEPOOL’s Budget and Finance Subcommittee. It would create new financial assurance requirements for projects that fail to meet certain milestones and add penalties for projects that fail to deliver physically by their commitment date.

But a new addition to the proposal voted on by the MC — to allocate forfeited financial assurance to all buyers and sellers in the market (rather than just sellers) — failed to get the support required for a committee recommendation. Also rejected were changes to the critical path schedule provisions in the proposal.

It was an especially timely conversation this week as a late court ruling on the Killingly Energy Center, which has challenged an RTO determination that it failed to meet development milestones, threw Monday’s Forward Capacity Auction 16 into chaos. (See Killingly Stays Alive After DC Circuit Halts FERC’s Termination Order.)

Committee Discusses ‘Mothball’ Option

The MC also continued work on a proposal by Sigma Consultants to make changes to the resource retirement process.

At Tuesday’s meeting, the discussion was specifically around whether ISO-NE needs a mechanic for resources to “mothball,” or exit service in a way that would later allow them to return from retirement. Sigma’s idea is to remove the “repowering rule,” which requires a minimum investment to re-enter service.

But Sigma’s Bill Fowler acknowledged in his presentation that major questions remain around the plan, including whether it should apply to permanent delists as well as retirements, and how retirement bids should be restructured.

The committee ultimately did not vote on the proposal. Fowler expressed frustration with a lack of responsiveness from ISO-NE.

“At the January MC, the ISO made clear that they are unable to support new stakeholder-driven proposals that are not in the work plan — at least for the foreseeable future,” his presentation said. “To resolve the bidding question, as well as ensure that the overall rule does not raise other concerns, we need ISO support.”

IMM Presents Fall Markets Report

Donal O’Sullivan of the ISO-NE Internal Market Monitor presented highlights from the IMM’s Fall Quarterly Markets Report to the committee.

Electricity costs in NE (ISO-NE) Content.jpgElectricity costs in New England this past fall were up 67% over 2020. | ISO-NE

 

Fall 2021 saw large increases in wholesale market and energy costs over the same period in 2020, driven by higher gas prices and slightly higher loads.

A big increase in gas generation over fall 2020 offset a decline in net imports and nuclear generation in 2021.

Real-time reserve payments were up substantially last year over 2020, and uplift payments increased slightly but remained relatively low.

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Vt. Lawmakers Working on Clean Heat Standard Bill

The Vermont House of Representatives’ Energy and Technology Committee has drafted a bill intended to align with the state Climate Action Plan’s call for the adoption of a Clean Heat Standard (CHS).

Committee members will continue to fine-tune the draft before introducing it in the House, Rep. Timothy Briglin said during a Feb. 1 meeting.

As drafted, the bill directs the Public Utility Commission to design and implement a CHS to reduce greenhouse gas emissions in Vermont’s thermal sector, which is responsible for one-third of overall state emissions.

The Vermont Climate Council’s initial climate plan, adopted in December, identified a CHS as a top pathway for decarbonizing building heating. About 70% of the state’s thermal sector relies on natural gas, fuel oil and propane. (See Vt. Climate Council Adopts ‘Initial Climate Action Plan’.)

Entities covered under the CHS would reduce thermal sector emissions by producing or buying clean heat credits to ensure the sector meets the carbon reduction requirements of the 2020 Global Warming Solutions Act. Covered entities would include natural gas utilities and fossil-based heating fuel wholesalers.

To obtain credits, providers could offer services for fuels or technology that reduce GHG emissions, such as advanced wood heating, cold-climate heat pumps, biofuels, renewable natural gas or weatherization. They also could purchase credits or hire a third party to provide clean heat services.

The draft bill excludes switching from fuel oil to natural gas as a qualified clean heat measure.

By September 2023, regulators would need to establish the number of credits — based on volume of sales — needed by providers annually for 10 years, starting in 2024. Updated 10-year plans will be due every three years.

A regulatory proceeding to implement the CHS would begin in August, and the PUC would have a year to finalize and adopt the standard framework.

Providers Respond

If Vermont adopts a CHS, it would put some of the state’s smaller fuel providers out of business, Paul Beauregard, owner of OnSite Propane, told committee members in Feb. 2 testimony on the draft bill.

OnSite, he said, would be “out of business Day 1.”

About 25% of the fuel providers in the market would be in that same position because they do not have a staff to install or service clean technologies, such as heat pumps, according to Beauregard.

“It will literally have tens of thousands of Vermonters scrambling immediately to find a provider to meet their needs,” he said.

Other companies that already have diversified from fuel delivery to meet the interests of customers who want cleaner heating solutions could fare better under a CHS, according to Rob Stenger, owner of Simple Energy.

Stenger has transitioned Simple to fit into what he says is a “wildly competitive market.” In addition to fuel delivery, the company provides HVAC services, blends fossil fuel with biodiesel, and installs solar systems and geothermal and cold-weather heat pumps.

But Stenger said in testimony that counting on companies to pivot like Simple is not a straightforward solution for Vermont.

While cold-weather heat pumps have become popular, they are not a reliable source in the extreme low temperatures of Northeast winters, according to Stenger. Furthermore, the skills needed to install and maintain the systems are not transferable from fossil technologies.

“There’s a ton of technical information and training that goes into selling and installing heat pumps properly and setting the right expectation for consumers,” he said.

New trade professionals are “unskilled and wildly expensive to employ,” he said, adding that it can be years before his company can recoup the investment on that labor. Revenues from fossil fuel delivery allow Stenger to invest in the extensive staff training needed to be a heat pump service provider.

The Energy Co-op of Vermont has adjusted to the energy market in much the same way as Simple, according to General Manager Brian Gray.

The cooperative delivers heating oil, kerosene and wood pellets; installs heat pumps; and performs energy audits and home weatherization retrofits. In the past year, its heat pump, weatherization and wood pellet sales accounted for 40% of revenues and “continue to grow,” Gray said in testimony.

Gray serves as a member of the Vermont Climate Council representing the fuel sector. His role on the council, he said, is to ensure fuel dealers have an opportunity to continue to thrive, and he believes a CHS aligns with that goal while meeting emission-reduction requirements. A CHS, however, will increase the cost of fossil fuels and leave Vermonters that cannot afford to switch to clean technologies with the burden of those higher costs, according to Gray.

Enhancing rebates and financing opportunities for fuel switching, he said, are key to making a CHS work.

The draft bill would direct regulators to “enhance social equity” by ensuring all customers can benefit from clean heat measures. At implementation, one-third of the clean heat credits needed to satisfy the standard would have to come from services to low-income households.

Committee members will hear more testimony on the draft this week.

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Maine Governor Revisits Vetoed Plan to Replace IOUs

Maine Gov. Janet Mills introduced a bill Wednesday that opens a new chapter in a long-standing effort to hold the state’s investor-owned utilities accountable for reliable and affordable electric service.

Bill Harwood, Maine’s newly appointed public advocate, applauded Mills for introducing the bill, saying in a statement that it will fill in “glaring gaps” in the state’s regulation of its utilities.

The Act to Ensure Transmission and Distribution Utility Accountability (LD 1959) would direct the Maine Public Utilities Commission to establish a performance report card for the state’s T&D utilities, with the possibility of imposing fines for not complying with performance standards. If a utility “consistently fails” to meet those standards, the commission would decide whether to sell off the utility’s assets, according to the bill.

If the commission were to move forward with divestiture, it would consider bids from potential buyers along with a proposal from a state-appointed committee to create a consumer-owned utility to purchase the assets.

Last July, Mills vetoed a similar bill, the Act to Create Pine Tree Power Authority (LD 1708), saying in her veto message that while  the concept was sound, the bill was “hastily drafted.” (See Mills Tells Maine Legislature to Slow Down on Plan to Replace IOUs.)

The bill would have set reliability, cost and customer service metrics for the commission to determine whether the state’s two IOUs, Central Maine Power and Versant Power, are “fit to serve” Maine ratepayers. It also would have authorized the creation of a consumer-owned nonprofit, called Pine Tree Power, to purchase a utility’s assets, should it be found unfit.

CMP is owned by Spain-based Iberdrola via Avangrid (NYSE: AGR), while Versant is a subsidiary of Calgary, Canada-based ENMAX.

Our Power, a nonprofit supporting the creation of Pine Tree Power, began a citizen initiative in August to force a public vote on LD 1708. The group has collected 73% of the 60,000 signatures needed for the initiative, Stephanie Clifford, campaign manager for Our Power, said in a Jan. 19 statement.

To make the November 2022 ballot, all signatures were due Jan. 31, but the group said it will continue collecting signatures throughout this year for the 2023 ballot.

Our Power opposes the governor’s new bill for not aligning with the group’s goals, Wayne Jortner, former senior counsel for the Maine Public Advocate and lead petitioner for the ballot initiative, said in a Feb. 3 statement.

“We know all Mainers share our goals: thriving democracy, economic competition, a livable planet, and safe and affordable energy infrastructure,” Jortner said. “That is why our ballot question is built on those principles.”

The governor’s bill now goes to the Joint Energy, Utilities and Technology (EUT) Committee.

Rep. Nicole Grohoski (D), a member of the EUT Committee, does not believe the governor’s bill can provide relief for current high energy costs the way LD 1708 would. Grohoski co-sponsored LD 1708 and is a co-petitioner of the Our Power initiative.

“Maine people work hard for their money, while CMP’s and Versant’s far-off investors sit back in their cushy chairs siphoning off as much as they can get away with,” she said in a statement. Our Power’s referendum “frees us from this abusive relationship and offers net savings of $9 billion … with lower bills starting for us all on Day One.”

Mills received support for her proposal from a bipartisan group of EUT Committee members.

EUT Committee Chair Sen. Mark Lawrence (D) said he is “pleased” to work with the governor and committee members to move the legislation forward.