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December 25, 2024

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KEPCo, Xcel Rehearing Requests on Z2 Fail

FERC on Thursday rejected a pair of separate rehearing requests by SPP members related to the RTO’s assignment of network upgrade charges under Attachment Z2 of its tariff.

The commission affirmed its original decisions involving Kansas Electric Power Cooperative (KEPCo) and Xcel Energy (NASDAQ:XEL) operating company subsidiary Southwestern Public Service (SPS) that SPP’s assignment of network upgrade costs did not violate the utility’s service agreements or the RTO’s tariff (EL17-21, EL18-9).

Attachment Z2 promised transmission upgrade sponsors would receive credits from any upgrade users whose service could not be provided “but for” the upgrade. But section I.7.1 of SPP’s tariff also required the RTO to invoice the charges monthly and to make any adjustments within one year. Because of software problems, it took SPP eight years to implement the attachment, during which the RTO did not invoice for the upgrade charges.

KEPCo had argued that SPP inappropriately assigned $6.2 million in upgrade costs in violation of four separate network integration transmission service agreements (NITSAs), with which FERC in November 2017 disagreed.

In its rehearing request, KEPCo maintained that SPP violated the filed-rate doctrine by assigning to the cooperative credit payment obligations (CPOs) for upgrades not listed in the NITSAs, saying FERC’s holding to the contrary is “based exclusively on the finding that KEPCo had sufficient notice of possible Z2 credit payment obligations.”

The cooperative also alleged the commission’s order did not address the NITSAs’ structure and its argument that SPP may not retroactively assess costs not specified in the NITSAs. It disputed the determination that it was on notice of possible Z2 responsibility and contends that the commission “does not explain why such notice — neither of which is contained in the [NITSAs] or tariff — is sufficient to make KEPCo liable” for CPOs not otherwise specified in the NITSAs.

KEPCo Coops (KEPCo) Content.jpgKEPCO’s Kansas member cooperatives | KEPCo

FERC disagreed, saying that in 2017, SPP did not have a tariff requirement specifying Z2 upgrades must be listed in NITSAs. It noted that the attachment is the governing tariff provision and “sets forth an expectation that sponsors will receive reimbursement from subsequent users that derive beneficial use of those upgrades.”

Referring to the 2017 order, the commission said the NITSAs are part of and “subject to the terms of the tariff, which bound KEPCo to the obligations imposed under Attachment Z2.” FERC said the filed rate included Attachment Z2, through which KEPCo was on notice of the possibility of CPOs that occur within the tariff’s billing requirements.

The commission had granted SPP a retroactive waiver of its tariff in 2016 so that it could invoice transmission service customers for Z2 credit payment obligations for 2008-2016 (ER16-1341). But it reversed course in 2019, saying its original decision was prohibited by the filed-rate doctrine and the rule against retroactive ratemaking. (See FERC Reverses Waiver on SPP’s Z2 Obligations.)

The D.C. Circuit Court of Appeals upheld FERC’s reversal of the retroactive waiver in August. (See DC Circuit Upholds FERC Ruling on SPP Z2 Saga.)

While saying KEPCO no longer has any CPOs during the historical period, FERC found that Attachment Z2, the filed rate, did provide notice of prospective CPOs that did not require waiver of the tariff’s billing requirements.

“The fact that these charges were not specified in the NITSAs does not relieve KEPCo of its obligation under the tariff to reimburse sponsors for the costs of network upgrades from which KEPCo derives beneficial use,” the commission wrote. “Accordingly, we continue to find that there has been no violation of the filed-rate doctrine for charges assessed after the historical period.”

Xcel alleged that SPP’s Attachment Z2 implementation violated the tariff and filed-rate doctrine because the grid operator failed to appropriately apply the “but for” test set forth in the tariff. It said the attachment “unambiguously” provides for CPOs to subsequent service requests that “could not be provided but for” the creditable upgrade.

In denying Xcel’s rehearing request of a 2018 order, FERC continued to find that SPP did not violate the tariff or the filed-rate doctrine in assigning CPOs to SPS. It also rejected Xcel’s contention that SPP’s assignment of CPOs was not sufficiently transparent and was unjust and unreasonable. The commission said Xcel did not identify any particular payment obligation or what type of support it asserts is lacking. It noted that FERC said in its 2018 order that SPP market participants had various channels by which to examine costs, including one-on-one sessions, and noted that Xcel could and should have taken advantage of those channels.

AEP Rehearing Request Rejected

FERC also granted American Electric Power’s (NASDAQ:AEP) clarification of a 2018 order accepting SPP’s filing of an unexecuted NITSA while affirming its previous decision (ER18-1702).

SPP made the filing after AEP declined to execute the revised service agreement because of nonconforming terms and conditions in the RTO’s tariff. AEP asked for a rehearing of the proceeding, alleging that the commission erred in failing to consider specific concerns regarding the applicability of completed aggregate facilities study (AFS) agreements, which the company said reflect an agreement that it need not pay for directly assigned network upgrade costs.

AEP asserted the charges included in the unexecuted NITSA were “plainly inconsistent” with its completed AFS agreement that outlined the terms under which a customer would agree to take transmission service. The company argued those terms “included a clear indication that AEP desired to make no payment for” directly assigned network upgrade costs.

It said that unless the AFS agreements’ terms are binding on SPP, they serve as “a vehicle for SPP to falsely induce customers into taking service under certain terms and conditions and later changes those terms and conditions without any recourse or protection to the customer.”

The commission granted AEP’s clarification request that it will consider the completed AFS agreements’ applicability in the ongoing proceeding to determine how SPP can unwind and resettle CPOs (16-1341).

But it also continued to find that that the issue is whether SPP “has appropriately included certain information in the service agreements pursuant to its tariff” and not administering its Attachment Z2 process during a prior period. The commission said the D.C. Circuit’s decision to uphold FERC’s reversal of the retroactive waiver granted to SPP rendered AEP’s protest moot.

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FERC: PJM Right to Block Gen Stability Limit Payments

FERC on Thursday ruled that PJM is within its rights to refuse lost-opportunity cost payments to generators that must rein in output to avoid damage to themselves and keep the system stable.

The commission accepted PJM’s clarifying changes to its tariff effective June 1 over protests from PJM Power Providers Group. The edits specify that the RTO doesn’t need to compensate generators for temporary restrictions on output to prevent loss of synchronization and further system strain during transmission outages (ER21-1802).

PJM said some generators’ expectation of lost-opportunity cost payments for maintaining stability limits is a “mistaken interpretation.”

The RTO’s tariff makes lost-opportunity cost payments when a generator’s output is “reduced or suspended … at the request of the Office of the Interconnection due to a transmission constraint or other reliability issue.” PJM conceded that the “other reliability issue” language is vague and could be misconstrued by generation operators to expect payment for honoring system stability limits.

The grid operator filed the revisions in late April with its Independent Market Monitor’s support. The RTO said paying lost-opportunity costs for “output limitations associated with stability limits is unnecessary because generators are already incentivized to operate within those limits.”

PJM explained that if generators don’t abide by generator stability limits, they risk damage to their own equipment. It said lost-opportunity costs are intended to motivate generators to forgo market revenues and voluntarily follow dispatch instructions when the transmission system is at risk.

The IMM agreed that “violating the stability limit is not rational behavior for the generator” and contended that generators have no lost opportunity to recoup.

The PJM Power Providers Group argued that the RTO’s edits “confiscate compensation owed to the generator for providing the reliability service of mitigating stability limits, while continuing to pay other generators for reducing output to provide reliability services” to protect the bulk electric system. The group said PJM’s distinction was discriminatory and preferential and said the grid operator offered “no compelling reason for the unique treatment of generators following PJM reliability directives to honor a stability limit.”

FERC said that generators “do not experience a lost opportunity when PJM directs them to back down due to a stability limit on the transmission system.”

“We agree with PJM that generators are already sufficiently incentivized to operate within stability limits in order to avoid any potential physical harm to their resource, and therefore … payments are unnecessary,” the commission said. “Violating a stability limit to achieve higher energy market revenues, at the risk of damaging the generating equipment, is neither rational nor economic behavior.”

FERC agreed with PJM that its status as a NERC reliability coordinator obligate it to “prevent or mitigate damage to generating facilities” by establishing and enforcing stability limits. It added that the RTO is justified in treating different types of system limitations differently.

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ISO-NE Asks Court for an Out as Killingly Uncertainty Balloons

ISO-NE on Friday asked the D.C. Circuit Court of Appeals to undo its stay order, which is keeping the Killingly Energy Center’s capacity supply obligation alive and holding up the results of the Forward Capacity Auction held earlier this month.

Warning of increasing damage to New England’s capacity market and its participants, ISO-NE argued that because Killingly developer NTE Energy has now defaulted on its financial assurance, the stay ordering the RTO to wait on a rehearing resolution from FERC is moot because the under-development gas plant will lose its CSO regardless of the outcome.

“The harm to the market and market participants of the delayed auction results grows with each day it continues, and the delay soon will disrupt activities necessary to the timely and orderly conduct of next year’s auction. The ISO therefore respectfully submits that action by the court on this motion by Feb. 25, 2022, is justified and necessary,” ISO-NE wrote in a filing to the court.

The grid operator has said that at the current pace, it may not be able to deliver results of the auction until mid-March, and that next year’s auction may also have to be delayed by a month. (See related story, Killingly Uncertainty Could Delay Capacity Auction Results Another Month.)

NTE was using a letter of credit for its required financial assurance with ISO-NE that will expire at the end of this month, and therefore was considered to have zero value 30 days prior (Jan. 31), according to the RTO’s rules. The company failed to extend the letter of credit or provide another form of financial assurance to resolve its default and is now no longer in compliance with the financial assurance rules.

“Termination of Killingly’s capacity supply obligations by operation of the tariff moots the court’s stay order. With or without the stay order, Killingly’s capacity supply obligations are terminated. Therefore, the ISO requests that the court dissolve its stay order because the stay no longer serves any purpose,” ISO-NE said.

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MISO, PJM Weigh ’22 Interregional Plan

MISO and PJM are assessing the need for an interregional study and transmission plan later this year, staffs told stakeholders during Thursday’s Interregional Planning Stakeholder Advisory Committee (IPSAC) teleconference.

MISO engineer Ben Stearney said the RTOs are reviewing data and will announce within 45 days whether they see a need for an interregional study.

The grid operators late last year compiled and exchanged data on historical market-to-market congestion, regional issues, and newly approved projects near the seam. They said they will review their most highly congested transmission elements and possible mitigations and might pursue a “full or limited” targeted market efficiency project (TMEP) study this year.

Staff said they’re also considering conducting a more specific analysis into the planning impacts of Illinois’ Climate and Equitable Jobs Act, which targets 100% clean energy in the state by 2050.

For the past two years, MISO and PJM have decided against both the more involved coordinated system plan and a TMEP study, which produces smaller, congestion-relieving seams projects.

Days before the latest MISO-PJM IPSAC meeting, MISO and SPP announced they would conduct a TMEP-style study this year on some of their more heavily used flowgates. (See MISO, SPP Take on 2nd Interregional Planning Effort.)

MISO isn’t obligated to conduct an interregional study once every two years on its PJM seam, as it does with SPP. However, MISO and PJM have approved three small TMEP portfolios since 2017 and one larger interregional market efficiency project in northwest Indiana in 2020.

MISO’s and PJM’s TMEPs must cost less than $20 million, completely cover installed capital costs within four years of service, and be in service by the third summer peak from its approval. The projects are assessed using a shorter time horizon than interregional market efficiency projects.

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PJM MRC/MC Preview: Feb. 24, 2022

Below is a summary of the consent agendas scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Thursday. Besides the consent agendas, the committees will not vote on any items at the meetings. The MRC will, however, hear first readings of seven different proposals, potentially teeing up as many votes at next month’s meeting.

Markets and Reliability Committee

Consent Agenda (9:15-9:20)

B. Stakeholders will be asked to endorse proposed conforming revisions to Manual 27: Open Access Transmission Tariff Accounting as a result of PJM’s recent formula rate filing with FERC (ER22-26). (See FERC Sets Hearing on Industrials’ Challenge to PJM Administrative Rates.)

C. Members will be asked to endorse proposed revisions to Manual 40: Training and Certification Requirements resulting from its periodic review. The changes were endorsed by the Operating Committee on Feb. 10. (See “Manual 40 Endorsed,” PJM Operating Committee Briefs: Feb. 10, 2022.)

Members Committee

Consent Agenda (11:25-11:30)

C. The committee will be asked to endorse proposed revisions to the Operating Agreement and Manual 15: Cost Development Guidelines addressing clarifications to fuel-cost policy standards and Schedule 2 penalty revisions. Members unanimously endorsed the joint PJM/Independent Market Monitor proposal at the Jan. 26 MRC meeting. (See “Fuel-cost Policy Standard Clarifications Endorsed,” PJM MRC/MC Briefs: Jan. 26, 2022.)

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Builders Oppose Labor Provision in Washington Solar Canopy Bill

The labor practices component of a Washington solar power bill has drawn opposition from construction interests in the state.

On Thursday, the Washington Senate’s Ways and Means committee heard testimony on a bill to grant tax breaks to solar canopies built over large parking lots in urban areas. Senate Bill 5714 was introduced by Sen. Reuven Carlyle, (D), chairman of the Environment, Energy and Technology Committee, who got the idea for the legislation from the global climate summit held in Glasgow, Scotland last fall.

Carlyle described a scenario in which a typical Walmart parking lot covers five acres and a canopy of solar panels could be built over one acre of it, locating solar farms within towns and cities.

His bill would provide tax breaks to those efforts if the builder approaches the Washington Department of Revenue in advance and meets certain criteria. The breaks would consist of repayments of sales and use taxes accumulated during construction.  Construction would have to be completed in two years to receive all requested tax breaks.

Under the bill, a qualifying project must be at least 50,000 square feet and have a nameplate capacity of 1 MW. The solar canopy installer would receive a 50% refund or deferral of its taxes if it is an organization owned by women, minorities, or veterans, or an entity with a history of complying with federal and state wage and hour laws, apprenticeship utilization and using preferred entry workers living in the project construction area.

Refunds or deferrals of 75% would go to one of those organizations if workers on a project were compensated at prevailing wages determined by collective bargaining agreements.

A 100% refund would go to a contractor operating under a community workforce agreement or a project labor agreement (PLA), which is a special collective bargaining agreement tailored to a specific project that supersedes existing bargaining agreements.  A typical PLA requires that workers are hired through union halls, and that nonunion workers are paid union wages for the length of the project. Also, the contractor must follow union rules on work conditions, pensions and disputes.

The PLA requirement for a 100% tax exemption prompted opposition from two contractor organizations — Associated Builders and Contractors of Washington and Associated General Contractors of Washington, who asked that the provision be removed from the legislation.

“The PLA language is totally unnecessary,” said Jerry VanderWood, chief lobbyist for the Associated General Contractors.

The two contractor associations were the only ones that testified about the bill Thursday.

At a Jan. 13 hearing before the Senate energy committee, several groups supported the use of parking lots as solar canopy sites at locations in or next to cities, saying the structures would help protect habitat and green spaces that would normally host solar farms. The canopies would also prove shade in the summer and shelter in the winter, according to testimony.

At the same hearing, Todd Myers, director of the conservative Washington Policy Center, testified that solar power is not cost-efficient, and that rainy and heavily urban Western Washington would be a poor location for solar resources.

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FERC Opens Inquiry on Dynamic Line Ratings

FERC opened a Notice of Inquiry Thursday to build an evidentiary record on the use of dynamic line ratings (DLRs), an initiative it signaled in its Dec. 16 order calling for the end of static transmission line ratings.

The December order required transmission providers to employ ambient-adjusted ratings (AARs) for short-term transmission requests for all lines that are impacted by air temperature (RM20-16, Order 881). But the commission did not mandate the use of DLRs, saying more evidence was needed concerning DLRs’ costs and benefits. (See FERC Orders End to Static Tx Line Ratings.)

Thursday’s NOI solicits comments on potential criteria for DLR requirements, the benefits, costs and challenges of implementing DLRs, and timeframes for implementation. It also asks whether the lack of DLR requirements makes wholesale rates unjust and unreasonable (AD22-5). In the December order, the commission said the use of only seasonal and static ratings was unjust and unreasonable because it resulted in the underutilization of available transmission capacity.

Initial comments are due 60 days after publication in the Federal Register, with replies due 30 days later.

AARs vs. DLRs

While AARs are based on forecasted ambient air temperatures and the presence or absence of solar heating, DLRs also consider wind, cloud cover, solar heating intensity, precipitation and line conditions such as tension or sag.

The December order required transmission providers to use AARs as the basis for evaluating transmission service requests ending within 10 days. It also required providers to electronically update transmission line ratings at least hourly to allow for use of DLRs by transmission owners that voluntarily adopt them.

The order acknowledged that DLRs can benefit customers when the limiting element of a congested transmission facility is the conductor and conditions besides ambient air temperature impact the line’s capacity. It also noted that in addition to often allowing greater power flows, DLRs can also detect situations where power flows should be reduced to maintain safety and reliability.

Costs

But the commission said it could not consider mandating DLRs without more information on their costs and challenges, such as the costs of sensors and cybersecurity.

In the Order 881 proceeding, some, including SPP’s Market Monitoring Unit and industrial customers, endorsed DLRs. But, FERC noted, “many commenters, including nearly all transmission owners that filed comments about DLRs, either opposed a requirement to implement DLRs on all transmission lines or opposed a DLR requirement in any form.”

FERC cited Bonneville Power Administration’s estimate that DLR implementation would cost more than $1 million per transmission line in monitoring equipment, software and hardware, and MISO Transmission Owners’ estimate of $100,000 to $200,000 per transmission line, or $1.5 billion for the entire RTO. SPP said DLR could require an energy management system (EMS) upgrade at a cost of up to $1 million.

Among the NOI’s 29 questions were queries on:

  • whether FERC should require DLR implementation on all or only certain transmission lines, and what criteria (e.g., congestion, curtailment levels, voltage levels, infrastructure, and/or geography/terrain) it should use to decide;
  • whether FERC should regularly reevaluate lines to ensure its criteria still apply;
  • whether there are differences between RTOs/ISOs and non-RTO/ISO transmission providers that the commission should consider;
  • how DLR requirements should be considered in regional transmission planning and interconnection processes;
  • what transparency measures the commission should require (e.g., informational reports that show which transmission lines meet criteria for DLR implementation);
  • the potential impacts to reliability if the digital devices that monitor or communicate line conditions are hacked in a cyber event;
  • whether FERC should order NERC to evaluate how a DLR requirement could introduce risks to the operation of the bulk electric system and whether any standards require modification to address risks;
  • whether FERC should require the use of sensors or just more up-to-date weather forecasts than required in Order 881;
  • how often transmission providers should be required to calculate transmission line ratings and for what services (e.g., hourly point-to-point; daily point-to-point; weekly point-to-point, etc.);
  • whether the commission should limit the number or proportion of transmission elements on which a transmission provider must implement DLRs at any one time; and
  • the appropriate time frame for identifying which lines are subject to DLRs, designing a DLR system, and integration and testing of the system.
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NERC: Grid Transformation Continues to Accelerate

The ERO Enterprise recommitted itself to adapting to meet its growing challenges in 2021, including the ongoing COVID-19 pandemic, climate change and cybersecurity, NERC said in its annual report released Wednesday.

NERC CEO Jim Robb wrote in the report that the previous two years have “brought significant clarity” to the cyber and climate risks, with both vividly on display in 2021. The year was bookended by the discovery of major electronic supply chain security breaches, with the SolarWinds Orion compromise coming to light in December 2020 and the Apache Log4j vulnerability identified a year later; meanwhile, the massive outages in Texas caused by February’s severe winter storms illustrated the danger facing the current electric grid under rapidly shifting climate patterns.

“We are at a historic moment,” Robb said. “Our model was developed during a time when risks were well known and the grid was evolving at a measured pace. We are now in a time where significant risks are emerging; they are new and unfamiliar; and the grid is transforming at a significant pace.”

Transformation was a major theme of the report, both as it relates to the grid’s transition to new energy sources and digital control, and concerning the organization of the ERO Enterprise itself. For the latter NERC noted the launch of its “NERC 2.0 – Invented Future” initiative in 2021, the name of which “recognizes that … NERC employees have the opportunity to innovate and create the future they want to have for themselves every day.”

The initiative comprises a new flexible work model that gives employees more freedom to work remotely — inspired in part by the experience of the COVID-19 pandemic — as well as new training that encourages employees to take on leadership roles. NERC also created the post of vice president of people and culture to oversee the initiative; the first and current holder of the role is Bryan Preston, who joined the organization in September. (See “Trustees Re-elected; Leadership Shuffle at MRC, Board Committees,” NERC Board of Trustees/MRC Briefs: Feb. 10, 2022.)

For the grid transformation, the report observed that “the past year has seen the manifestation” of multiple risks relating to “the transition to a cleaner energy future,” meaning the replacement of conventional generation resources with renewables like wind and solar, along with the growth of distributed energy resources.

First is extreme weather: Much of the report is dedicated to NERC’s actions over the past year to prevent another near-breakdown of the grid like what nearly happened in Texas. (See ERCOT: Grid was ‘Seconds and Minutes’ from Total Collapse.) Those efforts include accelerating approval of the cold weather standard that was under development before the storm; initiating work on a new standard inspired by the recommendations from FERC and NERC’s joint inquiry on the storm; and NERC’s outreach to industry to encourage preparedness ahead of the current winter season.

The other major risk that the report points out is cybersecurity, particularly the supply chain risks highlighted by the SolarWinds and Log4j compromises, but also the potential weaknesses in the nation’s pipeline infrastructure exposed by the Colonial Pipeline ransomware attack in May. (See Colonial CEO Welcomes Federal Cyber Assistance.)

NERC observed that the industry has grown more reliant on remote work because of the pandemic, creating “an increased remote cybersecurity attack surface” that, coupled with known weaknesses in widely used software, gives potential attackers myriad opportunities to infiltrate critical systems. The organization called for itself and the industry to “maintain a continued focus on improving defenses by increased sharing with” the Electricity Information Sharing and Analysis Center.

NERC Board of Trustees Chair Ken DeFontes warned that “significant policy and technical forces” are driving change in the grid, and that “these changes are occurring at a rapid pace.” He said that the board’s three top priorities for 2021 — weatherization, energy reliability assurance and cybersecurity — will likely remain at the top of the organization’s mind “for some time.”

“The more complex the system becomes, the greater the risk to reliability, resilience and security. At the same time, the future offers exciting new opportunities and transitions for an industry that is amazingly adaptive to change,” DeFontes said. “I look forward to working with all of our stakeholders and policymakers as we rededicate and reorient ourselves to meeting these challenges.”

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Advocates Seek Pathway for Biofuels in New Connecticut Energy Strategy

Representatives of the biofuels industry asked Connecticut regulators Thursday to acknowledge liquid fuels in the state’s 2022 energy plan as a near-term option for reducing greenhouse gas emissions.

“Bioheat should be an established carbon-reducing pathway in the Comprehensive Energy Strategy (CES),” said Stephen Dodge, director of state regulatory affairs for Clean Fuels Alliance America (CFAA).

Electrification cannot “realistically” be the only path to emission reductions, when heating fuel blended with biodiesel can reduce GHGs “immediately,” he said during a Connecticut Department of Energy and Environmental Protection (DEEP) CES scoping meeting.

In its 2018 energy strategy update, DEEP credited biodiesel with improving air quality and reducing GHG emissions and called for further assessment of biodiesel market maturity. Displacing fossil fuels with biodiesel, the CES said, would require tracking feedstock sources, manufacturing, and amount sold and consumed.

DEEP accepted public comments at the scoping meeting as part of its proceeding to update the CES.

Dodge pointed to New York, Rhode Island and Massachusetts as examples of states with an established biodiesel pathway for reducing emissions. Massachusetts regulators recently ruled that electric ratepayer-funded subsidies for liquid fuel-fired home heating should remain in place, he said, after the alliance “successfully argued that bioheat fuel is a legitimate pathway to immediately begin reducing CO2 emissions.”

A study by Trinity Consultants, commissioned by CFAA, found that using 100% biodiesel as a heating oil replacement can reduce carcinogenic diesel particulate matter emissions by 86%.

At a 50% blend, biodiesel would have lower CO2 emissions than power coming from the transmission grid, said Chris Herb, president of the Connecticut Energy Marketers Association.

“Conversions to cold climate heat pumps … will only increase CO2 emissions” compared to biodiesel used for heating, he said.

Herb called for the 2022 CES update to “leverage” a law enacted last year that requires the blending of advanced biofuel with fuel oil starting at 5% in July and increasing to 50% by 2035. That law requires DEEP to consider in the CES how biofuel blends may contribute on a lifecycle basis to meeting the state’s GHG emission reduction targets and how a thermal portfolio standard could contribute to further reductions.

“Hundreds of thousands of homes in our state need little to no modifications … to start using a fuel that is cleaner and has the ability to displace fossil fuels today,” he said.

Advancing bioheat through the CES, he said, would relieve the current pressure to bring enough clean energy onto the electric system to accommodate the state’s efforts toward heat pump and electric vehicle adoption.

The Acadia Center, however, cautioned regulators against using alternative fuels in buildings.

“Numerous studies … have determined that there’s no cost-effective role for alternative fuels, such as renewable natural gas, biodiesel and green hydrogen, in buildings,” said Ben Butterworth, Acadia’s senior manager of climate and energy analysis.

Alternative fuels, he said, are “limited” and “expensive” and should be reserved for decarbonizing hard to electrify sectors, such as heavy industry, shipping and aviation.

Heather Deese, director of policy and regulatory affairs for Dandelion Energy, made the case for geothermal heat pumps, calling them a low-cost option for heating and cooling that significantly reduces GHG emissions.

“In order to provide for an equitable transition of the building stock, the CES should leverage the low ongoing operating costs of geothermal heat pumps,” Deese said, adding that the technology reduces household emissions by up to 80%.

Deese said the CES should set “ambitious” goals for transitioning to a clean energy economy and articulate “specific goals” for building electrification.

DEEP is accepting comments on the scope of the CES through March 3 and expects to publish the final strategy scope by April. The agency will offer additional stakeholder engagement opportunities throughout this year, and it anticipates publishing the final CES by the start of the 2023 legislative session, said Vicki Hackett, DEEP’s deputy commissioner for energy.

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NYPSC Applauds Central Hudson Storm Response

The New York Public Service Commission on Thursday lauded Central Hudson Gas and Electric and assisting utilities for their quick response to the early February blizzard that swept through its service area and cut power to more than 65,000 customers.

The Feb. 3-5 storm dumped up to 18 inches of snow across parts of the state, while freezing rain and cold temperatures lingered mainly in Ulster Duchess and Columbia counties in the mid-Hudson region, with reports of localized icing of one-half to three-quarters of an inch.

“This was the largest workforce Central Hudson has ever assembled in the over 100-year history of their company,” said Kevin Wisely, director of the state’s Office of Resilience and Emergency Preparedness. “The large contingent of workers moving into a concentrated area such as this does pose logistical and significant coordination challenges, particularly with housing and feeding the crews.”

Central Hudson was able to house the emergency crews and has contingency plans in place, if a future need arises, to house additional workers at local universities and colleges, as well as the ability to set up large-scale tented housing units to support an incoming workforce, Wisely said.

National Grid, New York State Electric and Gas, and the Orange and Rockland utilities all provided mutual assistance to Central Hudson.

“Kudos to the utilities for working so well together, but also frankly it was really nice to see that we didn’t have the administration calling for an investigation while the storm was still happening,” Commissioner Diane X. Burman said.

The winter storm once again highlighted the need for utilities to continually reassess infrastructure vulnerabilities across their service territories to determine appropriate storm-hardening and resiliency projects to mitigate potential weather risks and adapt infrastructure to weather extremes, Wisely said.

OKs Enviro Certificate for Tx Line to NYC

The commission on its consent agenda approved a certificate of environmental compatibility and public need for the 1,250-MW Champlain Hudson Power Express (CHPE) developed by Transmission Developers Inc. and Hydro-Québec, as well as a petition for flexible financing practices (10-T-0139 and 20-E-0598).

The PSC will soon rule on a state petition to buy power from two new transmission lines being built to bring more than 2.5 GW of renewable energy into New York City, including the CHPE and the entirely in-state Clean Path NY project (15-E-0302).

Burman cast the lone “no” votes on both measures, saying that the commission should be looking at the transmission projects “more holistically” and that the requested flexibility in the financing arrangements is too lax.

“It’s requesting flexibility to modify without prior commission approval the identity of the financing entities, payment terms and the amount financed,” Burman said. “I think we should be putting in some conditions or having them come back to us if they are going to be changing some of that. I understand the need for some flexibility, [and] I think we can address that as we move forward when we get into the more thorny issues and the other items that are not before us.”

The nearly $24 billion in combined CPNY and CHPE contracts fall under the new Clean Energy Standard Tier 4 category of renewable energy credits (RECs) set up to bring renewable energy into the city by the commission, which set a Feb. 21 deadline for reply comments on the contracts.

CHPE said in its financing petition that it had withheld the expected amount of financing given certain competitive concerns, including bid preparation for the New York State Energy and Research Development Authority’s (NYSERDA) Tier 4 solicitation.

Given that the NYSERDA Tier 4 solicitation has concluded, with the project being one of two award recipients, CHPE said in a supplement to the petition that it “will seek to raise debt financing in an amount not to exceed $4.5 billion.”