Page 1008 – RTO Insider

December 9, 2020

High Marks for SPP’s Performance in 2020

SPP staff said this week that stakeholders’ overall satisfaction with the RTO’s services and staff’s performance in three specific areas all rose during 2020, even as survey responses dropped.

Staff shared the results of SPP’s annual stakeholder satisfaction survey and other assessments during the Board of Directors’ meeting Monday.

Scored on a 5-point scale, stakeholders gave SPP an overall 3.87 rating for 2020, a 0.25 increase from 2019. A year ago, overall satisfaction was only up 0.03 points. Stakeholders gave staff similar boosts of between 0.24 and 0.27 points when asked their satisfaction with responsiveness, accuracy of information and problem resolution.

However, the survey’s response rate fell from 18.6% a year ago to 13.6% this year. SPP sent out 1,283 invitations to the survey, with 174 stakeholders responding.

“Sometimes, people’s response rate is related to whether they feel anyone is responding to them,” board Chair Larry Altenbaumer said. “We want people to understand this is an important part of the process. We need to demonstrate that more effectively than we have in the past … to increase those numbers in the future.”

Staff reminded the board during its yearly metrics review of organizational effectiveness that they take all the comments received from the surveys and assign them to managers for action. SPP also makes periodic progress reports to the Markets and Operations Policy Committee.

“I know there is an ongoing activity, but we haven’t done as good a job as sharing with members the activities we do,” Altenbaumer said. “Too often, it comes across as a one-shot deal in December.”

Directors and members also reviewed evaluations of the board and the organizational groups’ self-assessments. The directors’ and Members Committee’s average rating of the board (4.25 out of 5) was identical to 2019. SPP extended the survey to the MOPC for the first time this year; the committee gave the board an average rating of 3.79.

Members Committee representatives rated the board’s performance lower than the directors did in all 23 assessed categories, ranging from 0.09 to 1.13 points lower.

“It’s important for those of us on the board to understand what would drive [the Members Committee] to say this,” SPP CEO Barbara Sugg said. She said staff would bring back thoughts on the gaps to the January board meeting.

COO Lanny Nickell will bring a proposed set of key performance indicators (KPIs) based on actual data to the same meeting. He shared a strawman that would reduce the number of KPIs to four: working together, responsibility and economics, keeping the lights on today, and keeping the lights on in the future.

Wolf Creek-Blackberry Timeline Tweaked

The board approved a consent agenda that added another year for regulatory approval to the 345-kV Wolf Creek-Blackberry competitive project. Staff determined that the current Jan. 1, 2022, deadline gave Kansas regulators only 66 days instead of the normal 180 to verify whether the potential transmission owner has gained utility status and, with it, the right of eminent domain. Staff recommended the deadline be extended to Jan. 1, 2023.

In September, the board lifted a suspension of the project and authorized the Oversight Committee to create an industry expert panel to evaluate responses to a request for proposals, which staff have since issued. (See “Board Lifts Suspension on Competitive Upgrade,” SPP Board of Directors/MC Briefs: Sept. 22, 2020.)

SPP expects to award the project a notification to construct next October. It is expected to cost $152 million, which members will fund according to load-ratio share.

With its sign-off of the consent agenda, the board approved the Corporate Governance Committee’s nomination of ITC Holdings’ Alan Myers as the MOPC’s vice chair. Myers will serve alongside acting MOPC Chair Denise Buffington, of Evergy.

Myers has chaired the Economic Studies Working Group since 2008 and will commence another two-year term in January following the board’s approval of his CGC nomination.

Also approved as stakeholder group chairs were: American Electric Power’s Richard Ross (Market Working Group); AEP’s Brian Johnson (Project Cost Working Group); Evergy’s John Anderson (System Protection and Control Working Group); Oklahoma Gas & Electric’s Jerad Ethridge (Model Development Working Group); and City Utilities of Springfield (Mo.)’s Russell Moore (Operations Training Users Forum).

Ross, Ethridge and Moore are all incumbents.

OG&E’s McAuley Says Goodbye

The meeting was the last as a Members Committee representative for Greg McAuley, OG&E’s director of RTO policy and development and one of the more vocal proponents of more equitable cost allocations for transmission upgrades. McAuley is returning to his native Florida to spend more time with his elderly mother.

“He has been one of the truly great contributors to SPP,” Altenbaumer said. “Please note there were many times we didn’t agree on things, but he always approached those discussions constructively.”

McAuley thanked staff and stakeholders for welcoming him into the SPP community when “I was new to the role.”

“The professionalism of this group is incredible. Your leadership, and Barbara’s now, is really doing some good work,” McAuley said in response to Altenbaumer. “Hopefully, our paths will cross in the not-too-distant future.”

“I’m saddened to see you leave the SPP family,” Sugg told McAuley.

April Board Meeting to be Virtual

Altenbaumer concluded the year’s final virtual board meeting by telling directors and members to expect more of the same in the first half of 2021. SPP had hoped to return to in-person meetings by April, but Altenbaumer said that after conferring with Sugg, they concluded it was too soon to end virtual meetings.

“While we were hopeful of getting through this surge and benefiting from a widespread vaccine, we just aren’t that confident that it’ll be the scenario we’ll face in April,” he said.

SPP’s current schedule lists the July and October board meetings as being held in-person at its Little Rock, Ark., headquarters.

December 8, 2020

FERC Audit Finds ALLETE Overcharged Customers

FERC’s Office of Enforcement last week found that ALLETE overbilled its wholesale transmission customers through improper accounting practices.

ALLETE, which owns Minnesota Power, inappropriately billed its customers for environmental mitigation costs imposed on it after it violated the Clean Air Act, FERC said in an audit report Dec. 4. The audit covered Jan. 1, 2016, to Sept. 3, 2020 (FA20-2).

The commission gave the Duluth, Minn.-based utility 60 days to submit a refund analysis identifying the improperly recovered expenses. ALLETE wrote that it accepted FERC’s audit findings and recommendations Nov. 19. But it said FERC’s finding on accounting for environmental costs “overlooks important policy considerations that should inform the proper accounting of related expenses.”

FERC investigators found that the utility used an account earmarked for its labor and general management to record environmental mitigation projects after a failure to comply with the Clean Air Act. The commission said the ensuing solar projects should have been accounted for in an account reserved for projects donated after their completion and not included in its wholesale annual transmission revenue requirement (ATRR).

EPA struck a settlement with the company in 2014 over emissions at three coal-fired power plants in Minnesota. The settlement required ALLETE to pay a $1.4 million civil penalty, install pollution-control technology and spend $4.2 million on projects benefiting the environment and local communities.

FERC Enforcement staff found several other accounting irregularities at the utility. They said it also:

applied state-approved depreciation rates to assets included in its transmission formula, though it had not filed those depreciation rates with FERC.
overstated transmission plant balances in its ATRR by miscalculating the pre-funded allowance for construction funds.
inappropriately recorded proceeds from long-term debt in accounts reserved for miscellaneous deferred debt.
misclassified distribution assets in transmission plant accounts and transmission assets in distribution plant accounts.
improperly recorded $26,000 worth of lobbying expenses in 2016 and 2017 in an account for office supplies when they should have gone into an account reserved for civic, political and related expenses. Audit staff said some lobbying costs were incorrectly recovered as part of ALLETE’s ATRR.
wrongly recorded various administrative and general expenses “in a manner contrary to the commission’s accounting regulations.”
did not report all the required information in FERC filings.

In addition to calculating customer refunds with interest, the commission prescribed that the company update its policies within a month and provide more employee training on accounting procedures. FERC also asked for progress updates on the corrective actions in quarterly reports.

“Integrity and compliance are core values at ALLETE. We take audits of this nature seriously and believe they help improve systems and procedures, and we look forward to implementing and improving compliance measures,” ALLETE Manager of Corporate Communications Amy Rutledge said in an emailed statement.

Rutledge said FERC auditors during the process “expressed their appreciation about ALLETE’s high level of cooperation and collaboration.” She also said that FERC’s findings affect only Minnesota Power’s transmission and wholesale customers, “all of whom have been notified regarding the plans for refunds.”

“FERC identified no systemic issues in ALLETE’s accounting practices, and the findings related primarily to differences in interpretation of FERC regulations,” Rutledge said.

December 8, 2020

Reserve Shortfalls Seen for MISO and Ontario, MRO Told

Planned reserves will fall below reference margins in MISO and Ontario within the next five years, NERC told the Midwest Reliability Organization in a preview of its Long-Term Reliability Assessment (LTRA) on Tuesday.

Mark Olson, NERC’s manager of reliability assessments, said Ontario, part of the Northeast Power Coordinating Council, will fall below its reference level in 2022, with MISO projected to drop below the threshold in 2025.

“Although MISO is over the reference margin level in 2022, their anticipated reserve margins are falling throughout the [first five-year] period, and they drop below the reference margin level in 2025,” Olson said. But he noted that the RTO has more than 100 GW of planned resources in its interconnection queue and ranks with PJM and ERCOT as having the most solar and wind planned. “Resource and transmission planners can develop these prospective resources to meet their current projected shortfall,” he added.

Olson also noted that MISO is among the areas for which a reduction in expected operating reserves is causing an increase in projected loss-of-load hours in non-peak months.

Ontario Reserves — MISO is among the areas facing an increase in projected loss-of-load hours in non-peak months. | *NERC*

The LTRA, which considers reliability over a 10-year horizon, will be released next week, after the expected approval Thursday of NERC’s Board of Trustees, Olson said. It will include study process or methodology changes since last year’s assessment. (See NERC Sees Opportunities, Challenges in Grid Evolution.)

MRO heard briefings from all four of its assessment areas: MISO, SPP, Manitoba Hydro and SaskPower.

MISO

MISO’s Stuart Hansen, who also spoke at the MRO briefing, said the RTO is actually projected to fall slightly below its 18% reserve margin in 2024. “But there’s no huge need for concern,” he said. “We will see additional retirements in the coming decade, but we do have plenty of new units that we’re studying in our interconnection queue, which is at record-high numbers right now. So, that will in all likelihood help maintain” the margin.

The RTO’s planning reserve margin increased to 18% from 16.8% in the 2019 LTRA because of changes in load shape, generation verification test capacity, and retirements and new resources, Hanson said.

He said MISO and its stakeholders are addressing any concerns through the resource availability and need (RAN) initiative. He also noted that wind and solar represent 84% of the 104.1 GW in the interconnection queue. The high proportion of intermittent resources “kind of highlights the need for this RAN effort, to make sure that we’re capturing all of our resource adequacy risks accurately and that we’re relaying that information to our members so that they can better plan the system,” he said.

SPP

Chris Haley, senior planning specialist for SPP, said the RTO has seen no major changes since 2019’s assessment, but he noted it continues to add wind, setting a new wind peak of 19,176 MW on Nov. 23. The RTO now has 25.5 GW of wind in total.

Haley also noted SPP’s coordination plan with ERCOT, which addresses operational issues for the DC ties between the Texas and Eastern interconnections. SPP has the ability to recall the capacity of any switchable generation resources that have been committed to satisfy the resource adequacy requirements contained in SPP’s Tariff. “We did have an instance in [summer] 2020 where we did recall some of that capacity,” he said.

The RTO’s 2019 loss-of-load-expectation study results indicates the region may need to increase its current 12% planning reserve margin by 2024 to maintain its one-day-in-10-years metric.

Saskatchewan, Manitoba

Suman Thapa, a senior engineer for SaskPower, highlighted major transmission projects under construction in the province. He said a 230-kV tie line with Manitoba expected in service by mid-2021 “will facilitate our new long-term … contracts with Manitoba.” The company is also testing a new 230-kV phase-shifting transformer on its line to North Dakota, expected in service by March 2021.

In June, Manitoba Hydro placed a 500-kV line from Dorsey (near Winnipeg) to the Iron Range near Duluth, Minn., into service. “That’s a significant interconnection,” the utility’s Kelly Hunter said. “It improved our Manitoba-MISO transfer capability … from an export-import perspective, and we think it adds resilience to both systems.”

The company also is completing work on the Keeyask hydroelectric generating station, a 630-MW addition.

Hunter said the new plant and the additional import capability from the Manitoba-Minnesota transmission line may prompt the retirement of the Selkirk natural gas plant (33 MW summer/118 MW winter).

Unlike its neighbors to the south, the Manitoba system is evolving slowly, Hunter said, and will likely remain dependent on hydropower. Solar PV has become unattractive for the winter-peaking region as incentives have expired and it has added no wind since 2011, he said.

“The economics [for wind] really are not that favorable right now because we already tend to be an exporter,” he said. “Any additional wind we built would probably end up being sold outside the province. And if we sell it into MISO, we’d be competing with wind energy that’s subsidized by the [U.S. production tax credit.] So, it just doesn’t make economic sense for us.”

NERC asked questions for this year’s LTRA regarding regions’ use of inverter-based resources. Almost two-thirds of Manitoba’s resources are inverter-based, including 138 MW of wind, 35 MW solar PV and 4,184 MW of hydro, including Keeyask.

That creates a challenge in ensuring an adequate short-circuit ratio at the HVDC inverter bus, which the company has addressed with 13 synchronous condensers, Hunter said.

December 8, 2020

PJM PC OKs RTEP Rules for SATA

Stakeholders endorsed PJM’s proposed rules for how storage should be considered in the Regional Transmission Expansion Plan (RTEP) process at last week’s Planning Committee meeting.

The PJM proposal, which includes criteria to be used in evaluating storage as transmission assets (SATA) to address reliability, market efficiency, operational performance and public policy, passed with 58% approval, including 91 “yes” votes. In a follow-up nonbinding poll, stakeholders endorsed the proposal over maintaining the status quo with 51% support, or 90 “yes” votes.

Jeffrey Goldberg of PJM reviewed the RTO’s package, saying no changes were made since it was presented at last month’s PC meeting for a first read. (See PJM Moves Closer to Endorsing SATA.)

The package establishes requirements to ensure implementation maintains system reliability consistent with NERC standards. The SATA evaluation approach also seeks to ensure there are no adverse impacts to the generation interconnection queue, Goldberg said.

The package only focused on SATA in Phase 1 of the stakeholders’ discussions, he continued. They will take up the issue of dual use for storage in Phase 2.

“We want to point out that SATA is a generator at times; it’s a load at other times, and it can be modeled as different types of components,” Goldberg said.

SATA Background

Michele Greening of PJM’s stakeholder affairs reviewed the work completed at the SATA Special Planning Committee sessions that began in June after stakeholders approved the issue charge in May. (See SATA Issue Charge Moves Forward in PJM.)

Phase 1 of the effort explored existing transmission planning criteria, including the performance measurement methodology and where there were gaps in planning.

PJM included a draft version of associated Operating Agreement language for informational purposes at the PC meeting. A first read of the proposed solution package and the supporting OA language is scheduled for the Market and Reliability Committee meeting Jan. 27.

Stakeholder Discussion

Sharon Segner, vice president of LS Power, asked if PJM was looking to amend Tariff language along with the OA in the package.

PJM attorney Pauline Foley said the RTO was attempting to pair the definitions of generating facilities and SATA with the Tariff language. She said the definitions will be contained in the Tariff.

Foley said stakeholder requests to PJM prompted the RTO to include the draft OA language for the PC meeting.

PC Chair Dave Souder said PJM will welcome feedback on the OA language going into discussions and the first read at the MRC. Souder said PJM plans to schedule another SATA working group meeting to talk through the concepts and language proposed for the OA.

“We have time to solicit feedback and modify that in advance of the MRC,” he said.

PJM SATA — Carl Johnson, PJM Public Power Coalition | © *RTO Insider*

Carl Johnson of the PJM Public Power Coalition said it wasn’t clear if the components in the PJM package would apply to supplemental projects as they do to reliability projects. Johnson said stakeholders needed clarity on the design components.

PJM’s Aaron Berner said the SATA discussions related to mitigation and reliability issues, not to supplemental projects. He said the intent of the SATA discussions was about how PJM would evaluate projects in the RTEP as potential solutions to reliability violations.

Berner said if there was any confusion around the proposed language, it could be modified before a vote at the MRC.

Bruce Campbell, director of regulatory affairs for CPower, asked if the PJM package will accommodate an aggregation of storage resources as outlined in FERC Opens RTO Markets to DER Aggregation.)

Berner said the dual use aspect of SATA, which is relevant to Order 2222, will be discussed in Phase 2.

Campbell asked if there was any intent of PJM to review the market components of SATA with members of the Market Implementation Committee. He said he remains a “bit uncomfortable” with the concept that a SATA resource could be active in markets.

Berner said the implications of SATA on markets have been discussed by PJM staff and will play a role in Phase 2 discussions. PJM said that Phase 1 reliability requirements must be established to ensure Phase 2 dual use does not adversely impact reliability. SATA models will appear in the base case in standby and be represented in sensitivity cases as both a generator and a load.

December 8, 2020

PJM MIC Briefs: Dec. 2, 2020

PJM’s Market Implementation Committee advanced manual language to the Markets and Reliability Committee regarding a stability limits capacity constraint proposal despite the objections of stakeholders who attempted to overturn the decision.

PJM Market Implementation Committee — Joe Ciabattoni, PJM | © *RTO Insider*

Joe Ciabattoni, PJM manager of interregional market operations, reviewed proposed updates to Manual 3: Transmission Operations; Manual 11: Energy & Ancillary Services Market Operations; and Manual 28: Operating Agreement Accounting. He also reviewed proposed Operating Agreement revisions to reflect the capacity constraint and opportunity cost packages that were endorsed at the September MIC meeting. (See “Stability Limits Endorsed,” PJM MIC Briefs: Sept. 2, 2020.)

The proposals were the result of several months of discussion at the MIC on potential changes to how PJM curtails generating output in order to maintain stability during maintenance outages. Generating units must sometimes be reduced below their normal economic max limit if a planned or unplanned transmission outage presents stability problems that could result in damage to the units. (See “Stability Limits in Markets and Operations,” PJM MIC Briefs: May 13, 2020.)

Current rules require the RTO to implement a thermal surrogate to reflect the stability constraint in the day-ahead and real-time markets and to bind the constraint, affecting the unit’s dispatch.

The capacity constraint proposal was put forward by PJM and the Independent Market Monitor and endorsed by the MIC with 64% support. It addresses the allocation of limits to multiple units by stating that the limit will apply to the sum of the output of the affected units plus ancillary service megawatts. Ciabattoni said the units would be dispatched in economic merit order up to the stated stability limitation.

If a unit chooses not to remedy a stability limitation identified during the planning process, its operating restrictions — as documented in its interconnection service agreement — would be invoked prior to those for other units, Ciabattoni said.

Lost opportunity cost (LOC) credits would not be paid for any reduction required to honor the stability limit. Similarly, LOC is not paid for economic megawatts of a resource that cannot produce because of a ramp limitation.

The opportunity cost proposal, presented by J-POWER and endorsed with 58% support, was fundamentally the same as the PJM-Monitor package except for providing compensation for LOCs. Paul Sotkiewicz of E-Cubed Policy Associates said payment for LOC is permitted by section 3.2.3 (f) of the Attachment K Appendix to the Tariff.

Ciabattoni said the proposed Manual 3, Manual 28 and Manual 11 language for the capacity constraint package clarifies that LOC will not be paid to the generator owners for reductions related to stability. It also includes Tariff language removing LOC eligibility from section 3.2.3 (f).

The alternate opportunity cost proposal had similar language in the three manuals but kept the Tariff language regarding LOC in place.

MIC Chair Lisa Morelli ruled that the manual language for both the capacity constraint and opportunity cost packages will move on to the MRC meeting on Dec. 17 for a first read.

Sotkiewicz made a request that the packages be voted on again at the MIC before being moved to the MRC. He said a September vote was “extremely close” and that PJM had stated “unequivocally” that Tariff and OA changes would be unnecessary in the capacity constraint proposal.

Morelli said it would be “extremely unusual” to vote again on packages already endorsed by the MIC.

Changes in Tariff and OA language would require a FERC filing and stakeholders may have voted differently on the packages with that knowledge, Sotkiewicz said, while the opportunity cost proposal did not require new OA or Tariff language.

Sotkiewicz registered a protest against Morelli’s decision to advance the manual language to the MRC, asking for a new vote on the packages given that ahead of the previous vote the proposal’s backers said there would be no need for Tariff or OA language changes. He said he believed the committee was not following the proper process under the rules of Manual 34.

“The vote was taken under a different set of assumptions about what was going to be required to make any changes,” Sotkiewicz said.

Tom Hyzinski of GT Power Group said he agreed with Sotkiewicz and that the addition of the Tariff language was an admission by PJM that the rules had to be changed as to not pay the LOC.

Stakeholders voted 63% against taking another vote on the packages, with 132 members voting “no” on Sotkiewicz’s protest.

Sotkiewicz said he appreciated PJM crafting manual language for the alternative opportunity cost proposal with members able to make a final decision between the two packages at the MRC.

“I think this is another area where the stakeholder process has failed us, and we’re going to have to revisit this,” Sotkiewicz said.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said advocates become frustrated when process issues take over substantive discussions at stakeholder meetings. He said the debate over the two packages was a “great example” of a process issue.

“The more we put in rules in the stakeholder process, it becomes a frustration when rules are used to frustrate a process,” Poulos said.

FTR Bid Limits Changes

Stakeholders endorsed a manual revision establishing bid limits for financial transmission rights (FTR) participants at the corporate entity level.

Brian Chmielewski, market simulation manager for PJM, provided an overview of updates to Manual 6: Financial Transmission Rights, which address the enforcement of FTR auction bid limits.

Chmielewski said the update included adding a bullet to Section 6.6 regarding “FTR Auction Business Rules” denoting the rule for FTR auction bid limits at the corporate entity level.

The new bullet reads, “In all FTR auctions, for each applicable auction round, total quotes (inclusive of buy bids, sell offers, and self-scheduled bids) for each effective FTR holder are limited to 10,000 MWh for each available auction period.”

Chmielewski said the FTR group will communicate the changes to the FTR Center, PJM’s tool that market participants use for submitting bids into the auctions prior to it going live. The information will be presented at the Tech Change Forum on Dec. 15.

A final vote is scheduled for the January MRC meeting.

Sotkiewicz asked why a limit is being proposed and why it was set at 10,000 MWh.

Chmielewski said it’s been PJM’s policy to maintain a 10,000 MWh bid limit so that the auction software would function properly. He said a limit had to be created to ensure the software would solve problems on time.

PJM has seen sub-accounts created in the last few years to get around the 10,000 MWh limit, Chmielewski said, with some corporate entities setting up multiple sub-accounts that are able to submit more bids and creating “inequities” among market participants.

Chmielewski said the concept was to memorialize the 10,000 MWh number in the manual language so it becomes a business rule everyone’s aware of and to also change the software so it won’t be possible to get around the limit by creating additional sub-accounts.

Sotkiewicz asked if it would be possible for PJM to look into further software solutions that would be able to handle higher limits and navigate through current programming constraints.

“With advanced software, don’t we think it’s time to move into the 21st century?” Sotkiewicz asked.

Chmielewski said PJM has committed to looking at stress testing the software and potentially increasing the limit.

UTC Uplift Changes

Stakeholders unanimously endorsed manual updates resulting from a recent FERC order addressing the allocation of real-time and day-ahead uplift to up-to-congestion (UTC) transactions.

Ray Fernandez, manager of market settlements development with PJM, presented the updates to Manual 28: Operating Agreement Accounting to conform with changes ordered by FERC regarding uplift charges on UTC transactions (EL14-37).

In its order issued in July, FERC determined that PJM’s current uplift allocation rules are unjust, unreasonable and unduly preferential because they do not allocate uplift to UTCs. (See FERC Orders Uplift Charges on PJM UTCs.)

PJM was directed by the commission to submit a replacement rate that revises the RTO’s current uplift allocation rules to allocate uplift to UTCs “in a manner that treats a UTC, for uplift allocation purposes, as if the UTC were equivalent to a [decrement bid] at the sink point of the UTC.”

Fernandez said UTCs will now be allocated for both real-time and day-ahead uplift.

December 8, 2020

Advocates Seek Bipartisan Support for Energy Efficiency

Decarbonization advocates said last week they hope energy efficiency is one issue that will attract bipartisan support in a narrowly divided Congress in 2021.

Bipartisan Energy Efficiency — U.S. Rep. Paul Tonko (D-N.Y.) | *ACEEE*

“Regardless of the outcome of the special [Senate] elections in Georgia, we are going to have some very narrow margins in both the House and the Senate,” U.S. Rep. Paul Tonko (D-N.Y.) told the American Council for an Energy-Efficient Economy’s (ACEEE) Energy Efficiency and Climate Policy Forum on Thursday. “It is my hope that with the weight of the White House, coupled with its executive agenda, we will be able to do more than you might expect.”

Tonko, chair of the House Energy and Commerce Committee’s Environment and Climate Change Subcommittee, said President-elect Joe Biden’s top priorities for 2021 should include getting the Department of Energy’s Office of Energy Efficiency & Renewable Energy (EERE) “back on track.”

“DOE will need more resources and personnel,” he said. “EERE’s employment levels are more than 180 [full-time equivalents] below fiscal year 2013 levels.”

Tonko also said he held out hope that Congress might approve some energy efficiency legislation before the lame duck session ends this month. “Currently people in both chambers are working to reach agreement on an energy package for an end-of-year bill. I don’t want to suggest that it will be the bold suite of clean energy priorities that I want to see advanced. And it is far from certain that anything will be able to be enacted. But the good news is energy conservation measures have always enjoyed strong bipartisan, bicameral support in Congress. So, if any energy policies move this month, there’s a good chance some efficiency and [research and development] provisions will be part of it.”

The daylong conference also included discussions on decarbonizing industry, transportation and buildings.

New York Moving on Building Emissions

Janet Joseph, senior vice president of strategy and market development for the New York State Energy Research and Development Authority (NYSERDA), noted that 70% of the state’s building stock was constructed before they were subject to energy standards. The impact? Space and water heating is the state’s single largest source of greenhouse gas emissions, she said.

In response, the state plans to electrify all heating and cooling, make buildings more energy efficient and incorporate more load flexibility into them, Joseph said. “This will become really significant, as we will need to accommodate an electric supply that is largely powered by intermittent renewable resources.”

Joseph said NYSERDA will release its “Carbon Neutral Buildings Roadmap” early next year. By 2030, more than half of heating systems installed in New York will need to be heat pumps; by 2050, nearly all new systems must be heat pumps powered by carbon-free electricity, Joseph said. “Air-source heat pumps, ground-source heat pumps, heat pump hot water heaters [and] high-efficiency systems that can work in cold climates.”

But despite providing heat pump incentives for several years and supporting pilot programs, only about 3% of the state’s homes are using heat pumps for heating. “So, we are clearly at the beginning of a major transformation in how we heat and cool our buildings,” she said.

In April, officials announced New York State Clean Heat, which will include almost $500 million in consumer incentives to be distributed by utilities. It also includes about $200 million in spending by NYSERDA to improve consumer awareness of improvements in heat pump technology and reduce their costs by 25% while increasing the pool of labor to install them by more than 14,000 workers.

The goal, Joseph said, is to position “the state for more affirmative regulatory action that will send a clear market signal for all-electric buildings in the future.”

“We will need regulatory changes through building and construction codes, appliance standards and/or greenhouse gas emission standards that set a clear market signal with a date certain to drive building electrification at the scale and pace we need to achieve our climate goals.”

She said the state also will launch a demonstration initiative next year focused on community-scale district geothermal systems. “We need heat pump solutions that can scale,” she said.

It is also partnering with the real estate industry in seeking decarbonization strategies for tall buildings in New York City and elsewhere, through the Empire Building Challenge.

“We will need low-cost capital, and lots of it, to support investments on the scale of what has been mobilized to support clean water infrastructure in this country. … We will also need continued innovation in these technologies to drive performance and cost improvements, and specifically getting at hard to electrify buildings. There will be some buildings, at least in New York state, that will be very hard to electrify.”

Building Codes

ACEEE Executive Director Steve Nadel also took up the subject of building codes, noting that the “energy use index” for commercial buildings has been reduced by about 50% since 1975, with somewhat smaller cuts for residential buildings, as a result of tightened state and local building codes. New model codes by the American Society of Heating, Refrigerating and Air-Conditioning Engineers and the International Energy Conservation Code (IECC) appear to require “significant” additional savings, he said.

But Nadel said legislation to tighten federal code goals have been opposed by homebuilders, whose dominance of the IECC has prevented faster progress.

New and existing residential and commercial buildings, 2020-2050 | *ACEEE*

“There may be some questions about whether the IECC process is fair or whether we need an alternative,” he said. “This year, the membership effectively overrode [the homebuilders]. We’ll see what the process is going forward and whether the IECC process is workable, or whether we need to be looking for alternatives.”

Decarbonizing Manufacturing

The conference also heard from Tom Dower, senior director of government relations for ArcelorMittal, a steel producer and mining company with industrial operations in 18 countries, who briefed ACEEE on the company’s commitment to net-zero emissions by 2050.

In Europe, where most of the company’s operations are located, it has pledged a 30% emissions reduction by 2030, a “very aggressive [goal] for a steelmaker,” Dower said.

He said the company was hoping to pioneer a carbon-neutral method for steel and ironmaking. But, he said, “new policy frameworks will be required to ensure the transition to carbon neutrality is both competitive and technically possible,” decrying the U.S.’ lack of a “coordinated, coherent climate strategy.”

“We’re working in industries that have long investment cycles, and it’s unclear right now whether the market will reward early movers. [It] can require a leap of faith for those who want to make the right steps towards decarbonization but are in a market environment today [in which they] may be harmed economically.

“Uncertainty,” he added, “is not helpful in terms of leadership and making difficult decisions.”

December 8, 2020

NY Utilities Diverge on Managed EV Charging

New York’s six local distribution companies split over whether to adopt “passive” or “active” approaches to managing electric vehicle charging in proposals submitted to the New York Public Service Commission last week (18-E-0138).

The PSC ordered the companies on July 16 to submit proposals for managed charging programs for mass market customers. (See NYPSC Approves $700 Million for EV Chargers.)

Orange and Rockland Utilities and Central Hudson proposed passive, or behavioral load control programs, such as time-of-use (TOU) rates to affect charging patterns. Consolidated Edison has been running a passive program since 2017.

National Grid’s Niagara Mohawk Power is proposing active managed charging, also known as direct load control.

Avangrid’s New York State Electric and Gas (NYSEG) and Rochester Gas and Electric (RG&E) are proposing use of both.

Niagara Mohawk said an active managed charging program will produce greater benefits than a passive program, including “avoiding timer peaks, shifting an even greater portion of EV charging off-peak, and anticipating other managed charging use cases envisioned to support a clean energy future.”

The utilities also differed over use of on-vehicle telematics — an onboard tracking system that sends, receives and stores telemetry data — or networked Level 2 (L2) chargers.

Level 1 chargers supplied with most EVs connect to a typical residential 120-V outlet and can deliver about 4 miles of charge per hour depending on the amperage rating of the circuit, enough to meet the needs of an EV driver whose round-trip commute is less than 30 miles daily.

L2 chargers, which require a 240-V outlet, are five times as powerful, providing 25 mph of charging, but a charger and installation can cost about $1,400.

NYSEG, RG&E

NYSEG and RG&E said they prefer data collection via telematics because it is cheaper than networked L2 chargers and allows collection of charging data, and the ability to initiate DR events, regardless of where the car is located within their service territories.

The companies also said residential L2 chargers can force distribution system upgrades due to their greater power requirements. “Typical residential L2 chargers have power ratings of approximately 7 kW, while a typical residential transformer is rated for approximately 25 kW and can serve five to 10 households. Wide scale deployment of unmanaged residential L2 charging would generate the need for the upgrade of, or installation of, additional transformers and potentially feeder upgrades depending on loading conditions,” they said.

New York EVs — Illustrative EV customer types, as identified by the Smart Electric Power Alliance | *Smart Electric Power Alliance*

The two utilities, which have almost 1.3 million electric customers, proposed three choices for EV drivers.

The “basic” level would require participants to provide the companies with limited demographic and charging behavior information, to enroll in their EV TOU rates, and to receive behavior prompts to charge during off peak periods. They would receive a $25 annual incentive.

Drivers choosing the “intermediate” option agree to allow the utilities to receive charging data via a telematics device they install in their EV or through their vehicles’ on-board telematic systems in return for a $50 annual incentive. They can receive an additional $50 per year if at least 90% of their charging occurs during off-peak hours. They must agree to enroll in demand response but are not required to respond to any event called by the companies; those that do would receive a $20 incentive for each event they opt-in to.

“Advanced” level participants will enroll in active managed charging in which they determine the level or state of charge required and the times their vehicle is available for charging. The companies’ managed charging algorithm will combine the charging power requirements and session duration to determine how much power to deliver each participant and when. Interaction between participants and the utilities will be automated through a web-based portal or mobile app. Incentives would be based on the energy and time requirements of each participant, ranging from $24 to $70 annually.

The companies based their proposal in part on NYSEG’s OptimizEV pilot, which began in March with 35 participants, equal to 10% of the EV owners in the company’s smart meter footprint in 2017.

The companies said initial results of the program indicate that managed charging can avoid the “timer peak” — when demand spikes in the first minutes of off-peak pricing under TOU rates. They proposed an $11.8 million budget for 2021-2025.

O&R, Central Hudson

Orange and Rockland (O&R), which has less than 233,000 electric customers in the state, proposed enrolling 100 participants per year in a three-year program costing about $800,000 as a supplement to its existing TOU rates.

It proposed a $150 enrollment bonus and up to $500 annually for participants who charge their EVs during off-peak periods: $5/month for using company-provided hardware or software to monitor charging behavior, $0.10 per kWh of charging during off-peak hours, and $20/month when they avoid charging during peak hours (2:00 pm to 6:00 pm) on summer weekdays.

Fortis’s Central Hudson also proposed building on the passive managed charging programs it has offered since 2019, a whole home TOU rate and an EV meter TOU rate.

The new program would require customers to procure a networked home charger allowing them to schedule their charging and participate in DR programs. They would receive a bill credit for charging during off-peak hours based on the difference between the average energy rate and the off-peak rate. The company said it would fund the credit through its revenue decoupling mechanism.

It also said it is considering the addition of active managed charging within the non-wires alternatives (NWA) program it began in 2016, which uses distributed energy resources including demand response to defer or eliminate infrastructure upgrades. “Primary considerations will be coincidence of baseline charging loads with locational peaks, magnitude of available curtailment, and cost of implementation and customer incentives,” it said.

The utility said it would not set “hard targets” for the initiative because of the limited number of registered EVs within its territory — 1,162 battery electric vehicles (BEVs) and 1,343 plug-in hybrid EVs (PHEVs) — and the recent decline in new EV registrations.

Consolidated Edison Company of New York

Con Edison’s SmartCharge New York program rewards EV owners with “off-the-bill” incentives for charging during off-peak hours. Initially limited to light-duty EVs, it was expanded in 2018 to medium- and heavy-duty EVs.

The program uses onboard vehicle telematics, smart charging stations, submetering and the FleetCarma connected car device, which most light-duty participants in the program use. The device, which plugs into the onboard diagnostics port of the vehicle, collects charging data, charging rate and total energy consumed during each charging session. EV owners receive cash incentives via PayPal.

Con Edison, which has 3.3 million electric customers, paid EV owners using FleetCarma $631,000 in incentives from Jan. 1 to Oct. 30 of this year, up from $65,000 in 2017. Light-duty EVs using FleetCarma have grown to 2,342 from 416 in 2017.

Light-duty EV owners using FleetCarma receive a $150 enrollment bonus, $5/month for at least one charging event in Con Edison territory and $20/month for avoiding summer peak charging.

The company said the flexibility of its program has resulted in increased enrollment. “For example, the program does not require the EV owner to install additional electrical equipment (such as a panel or meter) to participate in the program. SCNY participation is also not restricted to Con Edison account holders or home charging. Many Con Edison customers charge their vehicles at locations that are not associated with their Con Edison account and the person making the charging decision may be different from the one responsible for the electric bill. By allowing this flexibility, SCNY allows the company to manage EV load of any EV owner who charges in Con Edison’s service territory.”

It said it is considering new ways to enroll additional EV owners and lower per-vehicle acquisition costs, as well as new technologies for monitoring charging.

Niagara Mohawk

Niagara Mohawk, which has 1.7 million electric customers, proposed an active managed charging program to supplement programs it included in a rate case filing in July (Case #20-E-0380).

The new proposal would offer $500 rebates for purchasing L2 chargers and include telematics-based charging, which it said, “is expected to increase program enrollment and reduce the program cost-per-enrolled customer.”

It said most BEVs, including models from BMW, General Motors, Hyundai, Jaguar/Land Rover, Nissan, Tesla and Volkswagen/Audi, support active management.

The utility currently does only passive managed charging through its SC-1 variable time of use (VTOU) rate, which it said “has several hundred known EV drivers enrolled, a relatively small share of the total EVs in the company’s service area.”

National Grid’s affiliate in Rhode Island also has a passive managed charging program that provides enrollment incentives and per-kWh rebates. The company said preliminary results of an evaluation of the Rhode Island program showed a statistically significant increase in off-peak charging between participants that received off-peak rebates versus those that did not.

“For BEVs and PHEVs, there was a persistent amount of on-peak charging that participants who received the off-peak rebates still did not shift off-peak,” the company continued. “These results suggested, among other things, that for future programs and rate designs, the company should investigate technologies and incentives to mitigate and manage any timer or rebound peaks induced from time of use rates (e.g., charging peaks at 9:01 P.M. as the off-peak window begins).”

Niagara Mohawk’s proposal would provide EV owners using networked L2 chargers or vehicle-based telematics a flat monthly price for at-home off-peak charging: $20 for up to 225 kWh or $25 for 325 kWh of off-peak charging.

In addition to the $500 rebate for installations of new L2 chargers, it will offer $150 to participants using telematics or an existing networked L2 charger.

The company would manage at-home charging during the off-peak hours (11:00 p.m. to 7:00 a.m.) by default, requiring a customer to override the utility schedule to charge during on-peak hours at home.

Including both L2 chargers and vehicle telematics is essential to broad participation because “neither has universal market coverage,” the company said. “Telematics provide greater present-day market coverage; however, networked L2 chargers provide a pathway for nearly any EV driver to participate.”

The company proposed a $3.2 million budget for fiscal years 2022-2025, saying it “is sized to support nearly 20% of the EVs on the road under a sales trajectory that meets the company’s portion of the state’s” goal of 850,000 EVs by the end of 2025.

December 8, 2020

NEPOOL Participants Committee Briefs: Dec. 3, 2020

The NEPOOL Participants Committee on Thursday approved updates to Forward Capacity Market (FCM) parameters for the 2025/26 capacity commitment period during its final meeting of the year.

The values, which passed the Markets Committee last month, won 71.84% support in a sector-weighted vote.

ISO-NE had updated the FCM parameters’ values since the November MC meeting as it recalculated offer review trigger prices (ORTPs) to account for the combined effects of the supported amendments. Two of the amendments from the Union of Concerned Scientists reduced the offshore wind ORTP value to $0/kW-month.

The committee rejected the RTO’s original FCM parameters with only 18.33% of the sector-weighted vote, similar to its support at the MC meeting in November. (See “Amended Motion to Update FCM Parameters Passes,” NEPOOL Markets Committee Briefs: Nov. 9-10, 2020.)

The committee also rejected an amendment from Jericho Power on behalf of the New England Power Generators Association, with only 32.97% voting in favor. The amendment would have accounted for the impact net cost of new entry reference unit has on the Locational Forward Reserve Market (LFRM) clearing price by including the unit in the supply stack at its opportunity cost, which would have increased the net CONE value.

Energy Market Value Drops

ISO-NE COO Vamsi Chadalavada reported the energy market value for November was $197 million (through Nov. 23), down $42 million from October and down $142 million from the same month last year.

Natural gas prices were 4.7% higher from October to November, which pushed the average real-time hub LMPs to $27.10/MWh, up 0.8% from the prior month. Natural gas prices and LMPs were down 39% and 21%, respectively, from the same period last year.

Average day-ahead cleared physical energy during the peak hours as a percentage of the forecasted load was 99.6% during November, down from 100.8% during October, with the minimum value for the month of 95.3% posted Nov. 14.

Daily uplift, or net commitment period compensation (NCPC) payments, in November totaled $1.6 million over the period, down $1.2 million from October and down $2.1 million from November 2019. NCPC payments were 0.8% of the energy market value.

Cavanaugh Elected Chair

NEPOOL — David Cavanaugh, Energy New England | © *RTO Insider*

The committee elected Vice Chair David Cavanaugh, vice president of regulatory and market affairs for Energy New England, as its chair.

Previous Chair Nancy Chafetz of Direct Energy oversaw her final meeting and will remain one of the vice chairs. Other re-elected vice chairs included Doug Hurley, Synapse Energy Economics; Tina Belew, Massachusetts Attorney General’s Office; Frank Ettori, Vermont Electric Power Co.; and Michelle Gardner, NextEra Energy Resources.

Consent Agenda

The committee approved the consent agenda with one in opposition and some abstentions. It included support for ISO-NE’s plan for its third Order 841 compliance filing.

The RTO proposed Tariff changes to comply with three FERC directives. The first change removes Tariff language that could create a barrier to a storage resource’s market participation, effective in the first quarter of 2021. The second is the inclusion of four bidding parameters and a newly defined term that ISO-NE will use to account for the state of charge and duration characteristics in the day-ahead energy market. It would be effective Jan. 1, 2026.

The RTO was expected to file this compliance with FERC on Monday.

2021 Budget

The PC unanimously approved a 2021 budget of $6,220,600 for NEPOOL, down $90,000 (0.9%) from 2020’s spending plan. NEPOOL expects to spend $5,654,000 by the end of this year, $711,00 less than the approved budget. Most of the decrease comes from a $515,000 decline in committee meeting expenses amid the COVID-19 pandemic as all gatherings became virtual events. Committee meeting expenses for 2020 include amounts to be paid to consultants for assistance with ISO-NE’s Future Grid Initiative. The budget also assumes no in-person meetings for the first part of the year.

December 8, 2020

Consumer Panel Discusses ISO-NE ‘Visions of the Future’

The ISO-NE Consumer Liaison Group last week held its final quarterly meeting of the year where a virtual panel of regional energy experts wrapped up 2020 and attempted to cast a hopeful look to 2021 as New England continues its transition to clean energy.

Robert Rio, senior vice president of government affairs and counsel at Associated Industries of Massachusetts, served as moderator for “Clean Energy & Regional Markets: The New England States’ and Other Visions of the Future.” He said the RTO must provide reliable and cost-effective power to preserve the wholesale markets, “all the while navigating the political minefields that are the New England states.”

In October, ISO-NE confronted a joint statement from five of the region’s six governors (Connecticut, Maine, Massachusetts, Rhode Island and Vermont) calling for market design, transmission planning and governance reforms, saying the RTO is frustrating their efforts to reduce economy-wide greenhouse gas emissions. The New England States Committee on Electricity, which represents the collective perspective of the region’s six states in the NEPOOL stakeholder process, also released a vision statement that detailed specific reform measures. (See States Demand ‘Central Role’ in ISO-NE Market Design.)

NESCOE Executive Director Heather Hunt said the “concepts and concerns” in the vision statement should not come as a surprise; “If there were easy solutions … we would have solved them by now.” Hunt said the governors’ joint statement “underscored their interest in better aligning our regional markets with the achievement of their collective and individual decarbonization goals and mandates.”

David Cavanaugh, vice president of regulatory and market affairs at Energy New England, said NEPOOL has worked with ISO-NE and NESCOE through the stakeholder process on the Future Grid Initiative, which includes a reliability study and potential pathways, the latter of which “looks to identify a framework that may facilitate the entry of state policy resources, such that we can avoid the double-pay issues folks are concerned about.”

‘Figuratively Screaming’

Doug Hurley, principal associate at Synapse Energy Economics, said for the past 16 years he’s spent his “time working with or directly for state agencies in most of the New England states on the cost of the wholesale electric grid and how to integrate clean energy into that system as quickly as possible.” He said states have been “figuratively screaming” at ISO-NE for years about the issues in the NESCOE vision statement and hopes the RTO recognizes its gravity.

RENEW Northeast Executive Director Francis Pullaro echoed Hurley’s comments, saying it is “an impressive accomplishment to get six states that have different constituencies and different interests from time to time, to be able to come together with a detailed vision.” He said the current power system was “designed for a different era” and the capacity market is “very costly to consumers.”

Clockwise from top left: Robert Rio, Associated Industries of Massachusetts; Robert Either, ISO-NE; Francis Pullaro, RENEW Northeast; Doug Hurley, Synapse Energy Economics; Heather Hunt, NESCOE; David Cavanaugh, Energy New England | *ISO-NE*

The capacity market “was put in place for a variety of reasons and some of those reasons have evolved over time, but basically it never contemplated a world of renewable energy at this scale, and you have now a lot of renewables coming in and not being able to participate in the capacity market and states wondering why [they are] paying for duplicative resources,” Pullaro said. “I think the old ways are just not suited for the future.”

Robert Ethier, ISO-NE’s vice president of system planning, said he looks forward to “figuring out with the states” what it will take to interconnect all the renewables they are seeking to contract over the next several decades.

“Clearly, that’s not going to be a one-shot deal,” Ethier said. “It’s going to be an evolving plan as we learn more, as additional contracts are signed, etc.”

According to Ethier, a 2019 NESCOE economic study looked at how much offshore wind could interconnect to the current grid.

“And the short answer is about 8,000 MW before things start to get really expensive,” Ethier said, adding that “2,500 to 3,000 MW” in Cape Cod “could easily cost $300-plus million to interconnect it to the existing system.”

“I think we all have to be cognizant of the fact that it’s going to be expensive to interconnect all these renewable resources,” he said. “The costs are going to go up dramatically once we sort of hit the limits of our current system, and we have to start building large new 345-kV lines or large underground lines or underwater lines. While all of us are going to work together in good faith, and we are going to try to develop things at least-cost, it will cost money to integrate all these renewables in a useful way.”

Pullaro said while ISO-NE has been successful with competitive markets to bring costs down, “what we’ve seen over the last 10 years or so in New England” is that states putting out their renewable energy goals to a competitive bid has also reduced costs.

Word from an ‘Energy Nerd’

When Rio posed a question about distributed energy resources (DERs), Hurley answered that “the challenges are numerous, and it would be hard to list all of them.”

“I would say first and foremost as part of this overall transition, it wasn’t what we originally envisioned when the markets and all the planning procedures were created,” Hurley said. “We’ve made a number of adjustments to those planning procedures and the markets to try to incorporate [DERs] better.”

He added that DERs provide “a whole bunch of opportunity” for participation by people who have small amounts of resources available to them like solar, wind or storage.

“It allows the opportunity for private businesses who are aggregators of those smaller resources together because even as much of an energy nerd as I am, I’m not going to try and enroll my solar panels directly into the ISO system, and put them in every day,” he said. “That’s just not a good use of my time. Even I would put them into an aggregation from something that some other company runs and put mine together with all my neighbors and then get that into the ISO systems in whatever way is appropriate.”

Finding the Pathway

Looking to 2021, Rio asked panelists what they think would be “really helpful” for the energy grid next year.

Cavanaugh, incoming chair of the NEPOOL Participants Committee, said New England has been struggling “with this tension of integrating state policy resources.”

“If 2021 was to have a success statement, it would be to find the appropriate pathways that balance investment, as well as state policy resources and achieving state goals, because you have to have a balance,” Cavanaugh said. “You still want to have the signals to draw merchant investment in the region because you need it, but you also need the ability to represent and respect state policy, so if ’21 could deliver anything, it’d be identifying a pathway that’s successful in achieving that goal.”

Either added that, “if we can achieve it, that would be fantastic.”

Hunt said that 2021 “is a year for a fresh look at what we’re asking the markets to do and how we’re governing how the markets operate.”

Pullaro said he could not help but look for sources of hope during the pandemic.

“So [my thought] for 2021 is to try and enjoy the fact that we’re at a point where we’re not arguing whether to transition to a clean grid, but how to do it,” he said.

December 8, 2020

NY Seeks ‘Just Transition’ in Decarbonization Plans

The New York State Energy Research and Development Authority (NYSERDA) this month issued a request for proposals seeking contractors to conduct site reuse planning studies for retired power plants.

The $5 million solicitation is just one manifestation of the huge effort the state is mounting to implement the Climate Leadership and Community Protection Act (CLCPA), which requires the state to switch to 100% zero-emission electricity by 2040 and reduce greenhouse gas emissions to 85% below 1990 levels by 2050.

At least 10 state agencies have roles in the transition, led by NYSERDA, the state Department of Environmental Conservation and the Climate Action Council, a 22-member committee that will prepare a scoping plan for achieving the state’s energy and climate goals.

The council’s work will be informed by more than 100 stakeholders — including manufacturers, farmers, generators, labor unions, environmental groups and trade associations — in advisory panels for Agriculture and Forestry; Energy Efficiency and Housing; Energy-Intensive and Trade-Exposed Industries; Land Use and Local Government; Power Generation; Transportation; and Waste. The RFP is related to the work of an eighth group reporting to the council, the Just Transition Working Group, which is considering issues of displaced workers, environmental justice and economic redevelopment.

At a meeting last week, the working group reviewed a straw proposal for the principles the state should follow, which it will present to the council on Dec. 15. In addition to the redevelopment of industrial communities, the 10 principles include topics such as “stakeholder-engaged transition planning”; preservation of culture and tradition; equitable access to “high quality, family-sustaining jobs”; climate adaptation planning; and protection of natural systems and resources.

Support for Power Plant Communities

The RFP is expected to result in $4.75 million in spending on consultants providing affected plant-site municipalities with technical assistance and $250,000 for a site reuse “toolkit” that could be used by other communities.

The deadline for responding is 3 p.m. Jan. 13; an informational webinar for prospective bidders will be held at 10 a.m. Dec. 15. NYSERDA expects to invite communities to apply for assistance in the first quarter of next year.

At the Just Transition Working Group’s meeting Thursday, Steve Ryan, director of business engagement for the state Department of Labor, briefed the panel on the department’s Rapid Response program, which offers résumé development, interview coaching and training opportunities.

New York Decarbonization — Workforce for New York’s traditional power generation (2016-2019) | *New York Just Transition Working Group*

The department had deployed the program for workers at the Somerset Operating Co., the state’s last coal-fired generating plant, which retired in March, and Indian Point nuclear plant, which shut down Unit 2 in April and will close its remaining unit next spring.

Ryan said the laid off workers appreciate the help. “We provide that hope. Because many of them have no idea where their next employment is going to be,” he said.

James Shillitto, president of the Utility Workers Union of America Local 1-2, which represented 400 workers at Indian Point, said site redevelopment is an easier challenge than retraining laid off workers and finding them new, well paying jobs. “Retraining workers is a little bit more difficult because you have people in various levels of their lives. You have the ones that need to hang on for five or six more years to retire, and the ones that are going to work another 20 to 25 years.”

The state Worker Adjustment and Retraining Notification (WARN) Act requires businesses to give 90 days’ advance notice for large layoffs or plant closures. “Typically, what happens with Rapid Response is it’s triggered by a WARN notice. But in these cases, as with Indian Point, we’re going to know well in advance what’s coming so we should have a framework where we can begin that process without waiting for a WARN notice,” Labor Commissioner Roberta Reardon said. “We need a long runway: as long a runway as we can get with both the employers and the workers to do the kinds of negotiating … or training to really have the best impact.”

Deliverables

Public Service Commission Chairman John B. Rhodes said the working group has two main deliverables, including an inventory of power plants at risk of closing, an effort to identify issues affecting plant site reuse.

The second deliverable is identification of problems and opportunities presented by site reuse. Among the problems: the local economic effects of lost salaries and reduced property tax revenues for local governments and schools. Also to be considered: environmental remediation and restoration.

Plant sites — often on lakes or rivers because of the need for cooling water — can be repurposed as parks or commercial or mixed-use developments. Their access to transmission lines and cooling water has also made them attractive to data centers — a use the owners of the Somerset plant are pursuing. They can also provide interconnection points for new renewable generation.

Jobs Mapping

The state also has begun early work on an assessment of job-loss-threatened power plant workers’ skills to identify retraining paths and match them with job openings in clean energy and elsewhere.

As of 2019, the state had 800 workers in oil-fired generation, almost 5,400 in natural gas and more than 3,800 in nuclear. It also had more than 65,000 workers in transmission and distribution.

As of 2018, 76 of New York’s 106 gas turbines (2,356 MW) were older than 46 years; nationally, 95% of such units have deactivated by this age. Similarly, 95% of steam turbines nationally retire by age 62.5. By that measure, 11 out of 46 units (866 MW) are at retirement age. By 2028, more than 8,300 MW of gas and steam turbine-based capacity in New York will hit retirement age.

About 35% of the state’s generating capacity has been added since 2000. “There’s been in recent years about 2,000 MW of natural gas combined cycle generation [added],” Emilie Nelson, executive vice president for NYISO, told the working group. “The plant staffing required for those types of facilities tends to be lesser than some of the older plants. We have about 2,000 MW of large-scale wind on the system. A lot of the solar that we have thus far is behind the meter, so [it requires] a little different type of support from a job perspective.”

Policy Drivers

In addition to the CLCPA, New York’s transition is being driven by Regional Greenhouse Gas Initiative regulations adopted Dec. 1 to reduce the carbon dioxide emissions cap by 30% from 2020 to 2030. The changes also expand the program to cover peaking units above 15 MW, a reduction from the current 25-MW threshold.

The Department of Environmental Conservation’s “peaker rule” will be phased in between 2023 and 2025, affecting 3,300 MW of capacity. The rule has two compliance options for plants that cannot meet emission limits on pounds of NOx per megawatt-hour: stopping operation during summer ozone season, or replacing their output with energy storage or renewable generation at the same interconnection.

The 2020 NYISO Reliability Needs Assessment identified transmission security needs beginning in 2024 and resource adequacy needs by 2027. The ISO’s first quarterly short-term assessment of reliability (STAR) report found an additional transmission security need in New York City for 2023. In addition, city regulations will bar combustion of Nos. 6 and 4 fuel oil by 2020 and 2025, respectively, affecting 2,946 MW.

“This is manageable if we’re thoughtful and look ahead,” Rhodes said.

Putting it All Together

Lara Skinner, executive director of The Worker Institute at Cornell University, which performs research and education on current labor issues, noted that the Labor Department’s Rapid Response program was created to respond to individual business closures. “When we think about this transition to a zero-carbon economy, we’re taking about a massive transition. A major economic transition with significant labor, social, community impacts — economic impacts,” she said.

Skinner suggested panel members review U.S. Sen. Tammy Duckworth’s (D-Ill.) proposed “Marshall Plan for Coal Country Act,” which would modify bankruptcy rules to require companies that shut down to provide health care and pension benefits to former workers and give free tuition at public colleges for their children.

“Today’s meeting demonstrates to me that there’s some really great thinking happening around the broader impact of the transition in New York state,” Skinner said. “For me, it raises the question of how do we link all of this up? And how do we think bigger and broader about this transition and make sure that our approach to the transition is going to be comprehensive and cohesive?”