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November 5, 2024

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Vermont Energy Plan Targets 100% Zero-emission Car Sales by 2035

Vermont has released a draft comprehensive energy plan (CEP) for the state that aims to facilitate a clean energy transition in an equitable manner while keeping electric sector costs down.

Among the draft’s recommendations is to make all light-duty vehicles sold in the state zero-emission by 2035.

The plan would expand the state’s “aggressive” renewable energy target and adopt the state’s greenhouse gas reduction requirements, said TJ Poor, director of the Vermont Department of Public Service’s (DPS) Efficiency and Energy Resources Division.

“We also recognize that currently the burdens and the benefits of energy policy in the state have not been equitably distributed across the state or its people,” he said during a public stakeholder meeting for the CEP on Thursday.

The DPS must update the state’s energy plan every six years, and it will provisionally adopt the CEP in January after taking public comment on the draft by Dec. 20.

EV Sales

In the 2016 CEP, DPS set a goal of having 10% of vehicles in the state powered by electricity by 2025. By the end of 2015, there were slightly more than 1,000 electric vehicles registered in the state. The total in-state passenger vehicle registrations at the time was 550,000.

By 2017, passenger vehicle registrations had risen to 578,000, and by the end of 2020, just fewer than 4,000 were EVs, according to the Energy Action Network’s 2020/2021 Annual Progress Report for Vermont. And new passenger vehicle sales, the report said, averaged 38,500 annually between 2012 and 2020.

Of the vehicles sold in that period, a steadily increasing number were light passenger trucks or sport utility or crossover utility vehicles, reaching 85% in 2020. The state will face specific challenges in transitioning sales in those vehicle categories to zero-emission technologies in the near term.

All-electric SUVs and CUVs currently on the market range in price from $40,000 to $100,000, and light-duty trucks are yet to arrive. The draft CEP acknowledges that Vermont’s zero-emission vehicle goal is dependent on the national vehicle market, and the state should re-evaluate the EV sales goal regularly. It also suggests that Vermont can influence the national market by adopting California’s ZEV standards, which will help put pressure on vehicle manufacturers to produce more EVs.

In addition, Vermont’s state-level incentives for EVs are not available for models that cost more than $40,000.

“This presents a particular problem in rural areas of the state where [all-wheel drive] vehicles are a necessity,” the draft CEP said. “Higher incentive amounts will help accelerate the [plug-in EV] market, encouraging consumers to purchase EVs sooner than they might otherwise do so.”

Vermont also needs to incentivize development of a fast-charging network in advance of the passenger fleet’s ability to sustain it. The state is “a long way” from having the charging units needed to support electrification of the transportation sector, according to the draft CEP.

“To the extent funding is available, Vermont needs to substantially up its investment in [EV infrastructure],” the draft says. “This may need to include funding to operate fast-charging stations at unprofitable sites for a period of years until the market share of [plug-in EVs] increases enough to make these stations profitable.”

Other options in the draft plan for reducing transportation sector emissions include:

  • establishing an incentive program for electric medium- and heavy-duty vehicles;
  • determining the viability and cost-effectiveness of converting the state’s diesel transit bus fleet to electric;
  • encouraging utilities to include utility load management for home and workplace EV charging; and
  • encouraging utilities to offer rates that relieve fast-charging load from traditional demand charges.

Climate Plan Alignment

DPS staff worked closely with the Vermont Climate Council this year to ensure that the updated CEP would be in line with the council’s first Climate Action Plan (CAP). (See related story, Vt. Climate Council Adopts ‘Initial Climate Action Plan’.)

The council adopted its initial CAP on Dec. 1, but Poor said the CEP and CAP “are distinct plans.”

Both plans target GHG reduction requirements set by Vermont’s 2020 Global Warming Solutions Act. And while they shared energy sector analyses and public engagement during development, the CAP addresses energy and non-energy sector emissions.

The CEP and CAP also share recommendations to:

  • adopt California’s Clean Cars II regulations;
  • expand existing state weatherization programs (The CAP target is 90,000 homes by 2030, while the CEP target is 120,000 homes by 2030.);
  • consider a clean heat standard;
  • expand the state’s 75% renewable portfolio standard to 100% carbon-free power (The CAP target is “no later than” 2030; the CEP target is by 2032.); and
  • continue to work with other jurisdictions on implementing the Transportation and Climate Initiative Program and consider participating in it.

Equity

For the first time, the CEP seeks to “root out and redress” inequities in the energy system that “continue to disproportionately impact many of Vermont’s communities,” Poor said.

A chapter on equity and injustice issues in the state leverages the work of the Vermont Climate Council’s Just Transitions Subcommittee in preparing the CAP.

The subcommittee’s work “really grounded the energy plan,” Poor said, noting that the draft CEP recommends that equity be centered in decision-making alongside cost and environmental issues.

Among the CEP’s recommendations for a just transition is a call for the DPS to develop a diversity, equity and inclusion strategy.

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OGE, CenterPoint Complete Enable’s Disposal

OGE Energy (NYSE:OGE) and CenterPoint Energy (NYSE:CNP) said last week that midstream energy company Energy Transfer Partners (NYSE:ET) has completed its acquisition of their Enable Midstream Partners gas-gathering partnership.

The $7.2 billion all-equity transaction was announced in February. (See Energy Transfer to Acquire Enable Midstream.)

OGE, which owned about 79% of Enable’s common units together with CenterPoint, will keep approximately 3% of Energy Transfer’s outstanding limited partner units with the transaction’s consummation. CenterPoint received about 201 million common units of Energy Transfer and $5 million in cash for its common units of Enable and general partner interest.

OGE CEO Sean Trauschke said in a statement that the acquisition “is an important step in OGE’s plan to become a pure-play electric utility.”

“We are now firmly on an accelerated path to reducing our exposure to the midstream industry,” CenterPoint CEO David Lesar said.

Enable was created in 2013 by merging OGE’s Enogex midstream subsidiary with CenterPoint’s pipeline and field services businesses. OGE held a 25.5% limited partner interest and a 50% general partner interest in Enable; CenterPoint owned 53.7% of the common units representing Enable’s limited partner interests.

In early 2020, OGE and CenterPoint took major earnings hits when Enable halved its quarterly distributions to investors and cut its capital expenditures for 2020 by $115 million. The cost reductions came during a global slump in petroleum demand and the COVID-19 pandemic. (See Enable Losses Slam CenterPoint, OGE Energy.)

Energy Transfer now owns and operates more than 114,000 miles of pipelines and related assets in all major producing regions in the U.S. and markets across 41 states.

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Michigan ROFR Bill Approved, Sent to Governor

LANSING, Mich. — Legislation granting incumbent transmission owners the right of first refusal to build and operate transmission lines in Michigan is on its way to Gov. Gretchen Whitmer (D) for signature after winning final legislative approval.

SB 103, which would benefit ITC Holdings and American Transmission Co., was sent to Whitmer by the Michigan Senate Thursday after the House approved the bill in a 71-29 vote late Wednesday.

Whitmer’s administration has said nothing about the legislation, which had bipartisan sponsors, including Democratic Sen. Curtis Hertel Jr., who succeeded Whitmer in the Senate. It was opposed by only a few Democrats.

Most of the 29 opponents in the House were the most conservative of the majority Republicans.  The most conservative Republicans opposed the bill in the Senate, which is also controlled by Republicans.

ITC-Michigan-Tx-Map-(ITC-Holdings)-Content.jpgITC Holdings’ ITC Transmission and Michigan Electric Transmission Co. serve most of Michigan’s Lower Peninsula through a network of about 8,700 circuit miles. The companies have made $5.5 billion in capital investments in the state since 2003. | ITC Holdings

The bill was unchanged by the House from the version passed in the Senate in October. (See Mich. Senate OKs Transmission ROFR for Incumbent TOs.)

The bill would apply to “regionally cost-shared” transmission projects, such as those resulting from MISO’s Transmission Expansion Plan. It takes advantage of the exception under FERC Order 1000 that allows states to create a ROFR. The order prohibited such rights in tariffs filed with the commission in a bid to create competition, although some incumbents have recently urged FERC to reverse the prohibition in the commission’s Advance Notice of Proposed Rulemaking proceeding. (See FERC Tx Inquiry: Consensus on Need for Change, Discord over Solutions.)

With the legislature pushing to finish the 2021 session this week, the House Energy Committee reported the bill on Tuesday, and it was rushed through its final readings on the House floor before passing.  There was no debate on the bill in the House.

John Dulmes, executive director of the Michigan Chemistry Council, blasted the legislation, calling Michigan’s electric costs a major barrier to attracting investments and jobs. “That’s why it is disappointing to see today’s vote to support the interests of a monopoly energy company instead of ratepayers. Our policymakers need to get serious about competitive energy policies and the high bills paid by our businesses and residents,” Dulmes said in a statement.

The state’s utility costs — some of the highest in the region — were cited as a reason Ford Motor Co. (NYSE:F) announced in September it was locating a major new electric vehicle factory in Tennessee.

The Chemistry Council was one of only a few vocal opponents to the bill.  The measure was backed by as many as a dozen groups, including labor groups and the Michigan Chamber of Commerce.

When the bill passed the Senate, the chief sponsor Sen. Wayne Schmidt (R ), said the state’s efforts to reduce carbon emissions through electrification will require more transmission in the state. The bill will help ensure a more orderly system to develop transmission, he said.

Whitmer will have 14 days to sign or veto the measure once she receives the proofed and printed version of the bill.

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Clements: FERC, States Need to Work Together

<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686783230.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

FERC Commissioner Allison Clements

” data-credit=”© RTO Insider LLC” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: left; width: 200px;” alt=”Clements-Allison-2018-01-23-RTO-Insider-FI.jpg” align=”left”>FERC Commissioner Allison Clements | © RTO Insider LLC

FERC Commissioner Allison Clements told the ISO-NE Consumer Liaison Group on Wednesday that the country’s energy sector is facing a “system challenge” from a rapidly changing resource mix that requires intelligent transmission planning and investment as part of the energy transition.

Any system problem needs a system solution, said Clements, who is focusing on ensuring that the commission and states work together “to embrace the full portfolio of solutions to unprecedented and formidable challenges.”

Clements said there is a “once-in-a-generation opportunity” to invest in new transmission that can contribute to cost-effective and reliable facilitation of a changing resource mix. When asked about the uncertainty surrounding the New England Clean Energy Connect (NECEC) transmission line, which would supply hydropower from Hydro-Québec to the New England grid through a 20-year supply agreement with Massachusetts utilities, Clements called it a “clear example” of the challenges related to siting new transmission.

On a subsequent panel, Michael Giaimo, Northeast regional director for American Petroleum Institute, said policymakers should not be so quick to retire existing fossil fuel infrastructure.

“My parents taught me that if you leave a job, make sure you have another job,” Giaimo said. “So, the analogy here is if you want to ensure a reliable power system at a minimum, you shouldn’t retire infrastructure until you are certain.”

Given New England’s policies intended to stimulate solar, wind and electrification, Giaimo said the region needs to have resources in times when renewables aren’t available and to account for the increase in nightly load for electric vehicle charging and residential heating. Additionally, he said, it’s essential to consider that existing gas infrastructure can help facilitate low-carbon fuels, like green hydrogen, in the future.

Dale Bryk, director of state and regional policies at the Harvard Environmental and Energy Law Program, said the region “can’t say ‘no’ to things when we don’t have a plan.”

“But we also can’t use the absence of a plan as a weapon to prevent ever changing anything,” Bryk said. “We have to stop digging the hole and stop investments in fossil fuel infrastructure that we know we have to abandon and build the solutions in a timely way so that we do have a just, equitable and orderly transition.”

“This transition is happening,” Clements said. “It’s not the commission’s job to plan it. It’s the commission’s job to facilitate it and protect customers and contribute to the assurance and reliability while it’s happening. That’s exciting. It’s like we’re the underlying nuts and bolts that are allowing the implementation to take place.”

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Entergy LA, NOLA Add Ida-related Debt

FERC last week authorized Entergy Louisiana and Entergy New Orleans to assume more than $15 billion in debt and securities to help recover losses incurred from Hurricane Ida’s destruction (ES22-7, ES22-8).

The orders allow Entergy Louisiana to issue up to $13 billion in long-term debt, $450 million in short-term debt and $300 million in preferred securities. Entergy New Orleans can issue up to $1.24 billion in long-term debt, $150 million in short-term debt and $40 million in preferred securities.

FERC said the long-term interest rate cannot exceed 6.775% and the short-term interest cannot exceed 4.5%.

Additionally, the Entergy subsidiaries can also issue $170 million and $25 million in letters of credit to post collateral and secure their participation in MISO’s markets.

Entergy said the late August hurricane inflicted anywhere from $2-$2.4 billion worth of damage to its Louisiana utility arm and $120-$130 million in damages to its New Orleans affiliate. The repair costs caused the utilities to surpass their debt ceilings ahead of their mid-July 2022 conclusion.

Entergy affiliates usually simultaneously file requests with FERC to issue debt, making the out-of-cycle requests unusual.

The new debt authorizations went into effect Dec. 1 and end Oct. 13, 2023.

Entergy reported damage to approximately 500 transmission structures, more than 225 substations, more than 210 transmission lines and nearly 6,000 transformers. Repairs to 30,500 distribution poles and nearly 36,500 spans of distribution wire were also necessary, the company said.

The staggering restoration costs led two commissioners to issue a warning of the increased financial damage related to climate change that ratepayers will bear.

FERC Chair Richard Glick and Commissioner Allison Clements wrote a separate concurrence urging their fellow commissioners to consider transmission investment as a means to hedge increasingly steep repair estimates.

Glick and Clements said while they agreed with Entergy’s need to issue debt and securities, they were writing “to underscore that this is another clear example of the deep costs of climate change and extreme weather, which will ultimately be borne by customers.”

The two pointed out that according to Entergy, the costs inflicted by Hurricane Ida were more than the combined costs of Hurricanes Katrina, Ike, Delta and Zeta.

“Hurricane Ida is just one of 18 climate-related disaster events with losses exceeding $1 billion that has affected the United States this year,” Glick and Clements wrote. “We expect that restoration costs following climate-induced extreme weather events will continue to grow, and for that reason, the commission should consider how prudent investments in transmission system planning can ultimately save customers money.”

Entergy Louisiana CEO Phillip May has rejected the idea that a more resilient transmission system could have withstood Ida’s ravages any better than the existing grid. (See Entergy Fends Off Calls for Tx, Solar, Microgrid Investment.)

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MISO to Test Long-range Tx Allocation Benefits

MISO has commissioned a study meant to demonstrate that long-range transmission projects built in the Midwest won’t deliver benefits to the South.

The grid operator has tapped The Brattle Group to test its hypothesis that benefits from long-range projects built in either MISO Midwest or MISO South won’t cross its subregional transmission constraint. Brattle is using hypothetical and past projects from MISO’s 2011 Multi-Value Project portfolio to study a systemwide benefit spread.

The RTO plans to include the results in its FERC filing for a separate-but-equal postage stamp cost allocation that splits the system into MISO Midwest and MISO South for cost-recovery purposes. MISO hopes that the allocation will be temporary, and it plans to explore other long-range design options in 2022.

Speaking during a Dec. 3 Regional Expansion Criteria and Benefits Working Group, MISO’s Jeremiah Doner said staff will share the study report with stakeholders when it’s completed.

Some stakeholders asked whether MISO was deliberately creating a seam within its own borders with the first allocation design.

East Texas Electric Cooperative representative Paul Kelly said that some stakeholders already have performed analysis that show high-voltage, long-range transmission can deliver benefits systemwide despite the subregional transfer limit between the Midwest and South.

Stakeholders asked whether MISO would allow retroactive cost recovery in MISO South if Midwestern project benefits are shown to help the South and whether staff will again test for benefit flows once they finally recommend specific projects.

Currently, MISO won’t estimate how much the first group of recommended projects could cost. It has said its first transmission planning scenario shows a need for upwards of $30 billion worth of projects, but those are expected over multiple years.

“I just can’t help but ask … is there a plan in place if that scenario actually does show significant benefits to the South?” said Sam Gomberg of the Union of Concerned Scientists.  

MISO’s Aubrey Johnson said if study results show noteworthy benefits flowing to the South, staff would reopen cost-allocation discussions for the first Midwestern projects to emerge from the long-range transmission plan.

Johnson was asked whether MISO would then be unmoored on a singular cost-allocation design and propose allocation that could vary project-to-project or cycle-to-cycle. He said staff will not alter cost-allocation decisions once made but will use what it learns on benefits flowing Midwest to South to inform future allocation designs.

With the Brattle analysis, MISO once again delayed a FERC filing date for cost allocation, pushing it back from mid-December to mid-January. (See MISO Schedules Cost-allocation FERC Filing.)

The RTO’s long-range transmission plan has evolved meeting-to-meeting, with postponements and temporary reductions in scale announced near-monthly.

The grid operator first told stakeholders it would advance an initial subset of projects based on its most conservative 20-year transmission planning scenario with December’s approval of the 2021 MISO Transmission Expansion Plan. It then said it needed until March. Planners now say they won’t have project proposals ready for a board vote until late spring. (See MISO Postpones 1st Cycle of Long-range Projects.)

MISO is not tackling Southern projects until sometime in 2023, leaving MISO South transmission needs out of the study’s first cycle. Louisiana and Mississippi regulators have threatened to leave the grid operator if the first round of long-range projects’ cost allocation extends to their utilities’ ratepayers.

Stakeholders Tee Up 2022 Allocation Design Debate

Looking ahead to next year’s debates on long-range cost allocation, MISO South members and regulators resubmitted for consideration their allocation proposal first presented in the summer.

The plan prescribes costs be directly assigned to project beneficiaries from either increased reliability, economic gains, or attained policy goals. It would have only states with decarbonization goals splitting project costs that further their clean energy aims. (See Tensions Boil over MISO South Attitudes on Long-range Transmission Planning.)

Clean Grid Alliance’s Natalie McIntire said state goals that split transmission project costs are similar to MISO’s current participant-funded project type, where market participants can construct a project so long as it doesn’t harm the system. She said elements of the South proposal already are available as options in the MISO tariff.

Some stakeholders said the South proposal wouldn’t pass at FERC because it proposes different allocation types for a single project class.

MISO’s Environmental Sector countered the South proposal with a design that asks the RTO to incorporate all benefit metrics it has deemed acceptable, including improved public health from less pollutants. The sector also asked for a two-step cost assignment, with some costs assigned to the parties receiving quantifiable, economic benefits and the remainder spread evenly across a subregion to recognize the broad reliability benefits that high-voltage lines deliver but are difficult to calculate.

Sustainable FERC Project attorney Lauren Azar said the Environmental Sector’s proposal clamps down on free ridership. She said her sector would also like to see benefits assumed over a 40-year horizon, noting most transmission remains energized for about 60 years, making projects undervalued when their benefits are initially measured.

MISO has said its system will not be able to function reliably in a future with a changing resource mix without new, large transmission projects (See MISO Analyses Show Reliability Woes Without Transmission Builds.) Currently, more than 95% of its members have carbon-emissions reduction goals.

Both MISO South regulators and Entergy representatives have questioned the amount of renewable penetration the RTO forecasts in future planning scenarios. They have suggested states with clean-energy goals pay a larger share of transmission construction costs.

The grid operator said it may need more than a dozen 345-kV additions, a handful of 500 kV and 765 kV lines, and even a massive footprint-wide network of DC lines as part of its the long-range planning package. (See MISO Reveals Contentious Long-range Tx Project Map.)

Based on MISO’s annual MTEPs, the footprint could see more than 5,000 miles in new transmission lines come online over the next decade. Only about 200 miles of the new lines will be rated at 345-kV and greater.

MISO has not approved any large economic transmission projects since it changed their cost allocation in 2020. (See MISO Cost Allocation Plan Wins OK on 3rd Round.) The RTO had framed the new allocation as key to getting more Market Efficiency Projects approved.

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NEPOOL Participants Committee Briefs: Dec. 2, 2021

Tx Planning Tariff Changes Approved

ISO-NE stakeholders Thursday approved tariff changes that incorporate a new transmission planning process focused beyond the RTO’s current 10-year planning horizon.

The revisions, which the NEPOOL Participants Committee passed unanimously with one abstention, are part of a multiphase effort. The initial phase establishes the rules to enable the New England States Committee on Electricity (NESCOE) to request that the RTO perform longer-term, scenario-based transmission planning studies on a routine basis.

The present processes do not support state-requested transmission analysis based on state-developed scenarios, inputs and assumptions. The new approach includes the development of high-level transmission concepts and cost estimates, if requested, to meet the state-identified requirements.

The second phase, to begin in early 2022, will address the rules to enable NESCOE to consider potential options for addressing the identified issues and cost allocation for associated transmission improvements.

2021-2022 Winter Outlook

ISO-NE COO Vamsi Chadalavada presented the region’s 2021-2022 winter outlook during his monthly report, with the 50/50 and 90/10 winter peak demand forecasts both lower than last winter’s.

The 50/50 forecast of 19,710 MW is 456 MW (2.3%) lower, while the 90/10 forecast of 20,349 MW is 2.2% lower (457 MW). Chadalavada said that if this winter is similar to the last, the RTO anticipates reliable power system operation without the need for emergency procedures. It is assuming no significant generation or transmission outages and limited fuel replenishment in this profile.

Energy Market Value Falls

Chadalavada added that ISO-NE’s energy market value for last month (through Nov. 22) was $375 million, down $185 million from October but up $130 million from last November.

Natural gas prices were 6.1% higher than in October, while gas prices and LMPs were up 154% and 112%, respectively, over the same period last year. Average day-ahead cleared physical energy during the peak hours as a percentage of the forecasted load was 98.6% during November, down from 99% during October, with the minimum value for the month of 93.9% posted Nov. 22.

Daily uplift, or net commitment period compensation (NCPC) payments, in November totaled $2.5 million, down $1 million from October, though $600,000 higher from November 2020. NCPC payments were 0.7% of the energy market value.

Two projects totaling 213 MW were added to the interconnection queue since Chadalavada’s last update. They consist of one battery project and one solar project, and each has in-service dates of 2024. In total, 300 generation projects are currently being tracked by the RTO, totaling approximately 31,947 MW.

2022 Budget

The PC unanimously approved — with abstentions — a 2022 budget of $6,587,000 for NEPOOL, up more than $350,000 from 2021’s spending plan. However, NEPOOL expects to spend $5,974,600 by the end of this year, $246,000 less than the 2021 approved budget.

The decrease mostly comes from declining committee meeting expenses amid the COVID-19 pandemic, as all gatherings were virtual events until October. Budget increases for 2022 include an increase in committee meeting expenses to $725,000, up from an approved figure of $510,000 in 2021 and 10 times the current forecast of $75,000.

Cavanaugh Re-elected Chair

PC Chair David Cavanaugh, vice president of regulatory and market affairs for Energy New England, was re-elected for 2022. Vice chairs were also re-elected include Tina Belew of the Massachusetts Attorney General’s Office; Frank Ettori, Vermont Electric Power Co.; and Michelle Gardner, NextEra Energy. Sarah Bresolin of ENGIE North America and Aleks Mitreski of Brookfield Renewable Energy Group were also elected vice chairs.

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FERC Upholds ROE Refund Obligation for Mississippi TO

FERC last week said a MISO transmission owner cannot duck refunds stemming from the commission’s recent decision to implement a 10.02% return on equity (ROE) for the grid operator’s other TOs.

In a Dec. 1 order accepting the TOs’ compliance filing for MISO’s new ROE, the commission said Mississippi’s Cooperative Energy cannot evade its refund obligation by shortening its refund period (ER17-215).

MISO’s ROE has been a carousel of numbers for years. FERC in 2020 enacted a 10.02% ROE for transmission rates effective September 2016, superseding the 9.88% and 10.32% ROEs approved in 2019 and 2016, respectively. Those figures were intended at different times to replace the 12.38% ROE established in 2002, which FERC deemed excessive years ago. (See FERC Stands by 10.02% ROE.)

The TOs’ compliance filings in question date back to 2016, reflecting the 10.32% ROE. FERC accepted them and ordered them updated to the TO’s current ROE of 10.02%, including incentives not to exceed 12.62%.

But the docket’s bigger point of contention came from Cooperative Energy, which argued that it shouldn’t have to provide refunds for the full refund period FERC prescribed.

FERC ultimately ordered TOs to refund customers for the 12.38% ROE from Nov. 13, 2013-Feb. 11, 2015, and Sept. 28, 2016-Dec. 23, 2020. (See MISO, TOs: More Time Needed for ROE Refunds.)

Cooperative Energy argued that it wasn’t obligated to issue refunds until mid-2015. That’s the date it began receiving a 50-basis point adder for its participation in MISO, despite it having been a non-public utility TO in MISO and using the MISO ROE since December 2013.

Other MISO TOs bristled at Cooperative’s interpretation of refund periods, leading them to register a limited protest of their own compliance filing.

FERC pointed out that Cooperative’s RTO adder was conditioned on its agreement to provide ROE refunds should the commission lower the rate. FERC said the TO should use its 2013 entrance into MISO as its effective refund date.

The commission found Cooperative’s arguments that forcing more refunds would amount to retroactive ratemaking to be baseless.

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NYISO Updates Grid in Transition Work and Plan for 2022

NYISO on Thursday updated stakeholders on several market changes in the works to accommodate thousands of megawatts of state-solicited renewable resources coming online in New York over the next decade.

The measures range from carbon pricing and buyer-side mitigation to distributed energy resource participation models, including for storage, hybrid and co-located resources, all part of the ISO’s Grid in Transition initiative announced two years ago, NYISO Principal Economist Nicole Bouchez told the Installed Capacity/Market Issues Working Group.

The ISO also posted the final version of its 2022 Master Plan for managing the changes in the energy, ancillary services and capacity markets.

The state’s Climate Leadership and Community Protection Act (CLCPA) and other statutes set ambitious clean energy targets staggered every five years from 2025 to midcentury, with strict emissions limits that regulators recently cited in denying air quality permits to two gas-fired generator proposals in the Hudson Valley and New York City. (See NY Regulators Deny Astoria, Danskammer Gas Projects’ Air Permits.)

“This path of Grid in Transition is focused on market enhancements under three different areas, the first one being aligning competitive markets in New York with the state’s clean energy objectives,” Bouchez said. “The second one is valuing reserves for resource flexibility, and the third one is improving capacity market valuation.”

NYISO retained The Brattle Group to forecast future resource mixes and help inform planning for reliability and market design over the next two decades, with the final report presented in June 2020. (See ‘Astonishing’ Buildout Needed for Clean NY Grid.)

Stakeholders expressed concerns about how fast the ISO is able to incorporate new events and regulations into its capacity processes. For example, the gas-fired projects were turned down, but state agencies have approved two separate projects totaling 2,550 MW to bring solar, wind and hydropower south to the city, as well as offshore wind projects totaling 4,300 MW. (See Two Transmission Projects Selected to Bring Low-carbon Power to NYC.)

In addition to the projects proposed, the ISO also presented an update on leading indicator metrics, with the most recent data provided in September, Bouchez said.

Supporting Studies

In looking at what changes to the markets are needed to face a growth in intermittent resource penetration, the ISO relied on several studies it has conducted over the past few years, including the following:

Aside from work on buyer-side mitigation tests and capacity accreditation, the ISO deployed a software-defined wide area network (SD-WAN). Separately, the NYISO is developing a billing and settlement system and billing simulator code. The remaining code for the DER participation model will be developed in 2022, with deployment also scheduled for next year.

The ISO expects to implement its hybrid co-located model in mid-December and will work to integrate the rules and software needed to enable large‐scale weather-dependent and energy storage resources to participate as co‐located resources (CSR) behind a single interconnection point. FERC in March accepted the ISO’s rules allowing an energy storage resource to participate in the wholesale markets with wind or solar as a CSR, and NYISO has since been working on the market software. (See FERC Approves NYISO Co-located Storage Model.)

A regulation service project completed in September last year updated requirements, and the ISO will continue to monitor fleet changes and appropriately update statewide regulation procurement requirements in the future.

New Resource Integration

One critical area is related to new resource integration projects, Bouchez said.

She listed three: the DER participation model, the hybrid aggregation model — which is scheduled for a functional requirements specification in 2022 — and internal controllable lines, “obviously something that we need to work through,” she said.

The ISO anticipates starting to review the real-time market structure to start in 2025, “but we’re thinking that it might not be a bad thing to start those discussions [next year] about the existing structure and different ideas for what changes should be considered and why,” Bouchez said.

Reliability Risks

The ISO on Friday released its Comprehensive Reliability Plan (CRP), the culmination of the 2020-2021 Reliability Planning Process. The report concludes that the state’s bulk power system will meet all applicable reliability criteria from 2021 through 2030 for forecasted system demand in normal weather.

Balancing-Challenge-(The-Brattle-Group)-Content.jpgThe figure shows typical load profiles with typical generation profiles for wind and solar resources; while there may be enough energy overall to meet demand, it will be necessary to shift the generation from the afternoon to the morning and evening hours. | The Brattle Group

But it also “demonstrates that our reliability margins are thinning to concerning levels beginning in 2023,” Zach Smith, vice president of system and resource planning, said in a statement. “We have to move carefully with the Grid in Transition in order to maintain reliability and avoid the kind of problems we’ve seen in other parts of the U.S.”

The CRP recommends monitoring and tracking transmission projects and other risk factors in order to mitigate risks to BPS reliability. In addition, system margins are expected to narrow to such a level that warrants review of current reliability rules and procedures.

NYISO said it will administer its short-term reliability process to address generator deactivation notices and other system changes on a quarterly basis, and continuously evaluate on a forward-looking, five-year basis.

“The potential risks to reliability identified in the analyses may be resolved by new capacity resources coming into service, construction of additional transmission facilities, and/or increased energy efficiency, integration of distributed energy resources, and growth in demand response participation,” NYISO said.

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FERC Reverses Course on Transmission Rights Resettlement in ComEd

Reversing course, FERC on Thursday ruled that PJM did not have to pay an Illinois wind farm $10 million under a resettlement of incremental capacity transfer rights (ICTRs) to the Commonwealth Edison locational deliverability area (LDA) (EL18-183).

ICTRs — available to interconnection customers that are required to fund a transmission facility — are awarded based on how much the improvement increases the transmission import capability into an LDA. ICTR holders receive revenues if the LDA in question is constrained in subsequent capacity auctions. The rights are good for up to 30 years.

The commission ordered the resettlement in April 2020 in response to a complaint by Radford’s Run Wind Farm, which said PJM unfairly denied ICTRs for funding an upgrade identified in its system impact study (SIS) to mitigate a thermal overload on the 345-kV Loretto-Wilton Center line.

In a subsequent compliance filing, PJM determined that Radford’s Run was entitled to almost $10 million for the 2019/20 delivery year. Crediting the wind farm required offsetting charges to the load-serving entities in the ComEd LDA associated with their corresponding CTR reductions. (See PJM Announces $10M Resettlement in ComEd LDA.)

In Thursday’s order, however, the commission said it now concludes the wind farm wasn’t entitled to ICTRs at the time of the 2016 Base Residual Auction for 2019/20.

Agreeing with challenges by PJM and Exelon’s Commonwealth Edison (NASDAQ:EXC), FERC said its earlier rebilling directive was “incompatible” with the PJM tariff’s definition of ICTRs because the wind farm did not become “obligated to fund” its upgrades until after the 2016 BRA.

The commission said PJM’s tariff is “ambiguous as it does not expressly state when the obligation to fund must occur.”

It concluded that the tariff requires that the resource either execute an interconnection construction service agreement with collateral or reimburse the transmission provider for the costs of the customer-funded upgrades prior to the BRA to qualify for the ICTRs for the associated delivery year.

The 306-MW wind farm in Macon County, Ill., went into service in December 2017. Neither the wind farm’s owner, RWE Renewables Americas, nor its attorney, Bruce Grabow of Locke Lord, responded to requests for comment.

PJM spokesman Jeff Shields said the RTO will comply with the order. “We don’t have any further details at this time,” he said.