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July 28, 2024

MISO to Focus on LRTP, Congestion for MTEP 24

CARMEL, Ind. — MISO this week said the bulk of its 2024 Transmission Expansion Plan (MTEP 24) will look much the same as last year’s, with an emphasis on long-range transmission planning and near-term congestion studies in addition to its usual round of annual studies.

MISO took stakeholder suggestions in early fall on what additional planning studies it may undertake as part of MTEP 24. However, planning staff warned that MISO is limited next year in what it can accomplish because it’s performing extensive analysis under its ongoing long-range transmission plan.

The Municipals, Co-ops and Transmission-Dependent Utilities Sector requested MISO perform a study centered around the potential effects of widespread energy storage additions and analyze grid-enhancing technologies’ ability to provide flow control.

MISO said it will consider energy storage and grid-enhancing technologies over the course of its regular MTEP studies, but not under a dedicated analysis. The RTO said it’s always open to considering non-transmission alternatives to projects.

“We don’t see the need for a standalone study. We see where the annual MTEP process can address that,” MISO’s Jeremiah Doner said at a Nov. 15 Planning Advisory Committee meeting.

However, MISO said a continuation of this year’s near-term congestion study is on the table as part of MTEP 24. (See MISO May Use Inaugural Near-term Congestion Study to Plan Smaller Tx Upgrades.)

Doner said MISO hasn’t settled on a scope for the near-term congestion study.

“It’s too early to say what that study is going to produce,” he said.

MISO previously said the study again will be exploratory and likely won’t result in project recommendations.

Some members of MISO’s Environmental Sector have expressed disappointment that MISO will take another year of hypothetical testing before it recommends small projects that alleviate congestion.

MISO said it needs more time to refine its transmission planning model to solve congestion on a five-year horizon instead of in the long run. Planners said they are open to tweaking the scope and study assumptions based on stakeholder requests.

Some stakeholders have said MISO already has a template for studying regional congestion and cost allocation with its Targeted Market Efficiency Projects with PJM. But MISO said the MTEP interregional process is materially different.

MISO planners have said that if any market participant is concerned about congestion in the near term, they can pursue a market participant-funded transmission project.

Winter is Coming; SPP Says It Has No Concerns

SPP says it has not identified any concerns within its 14-state footprint this winter that it is not capable of resolving. 

Bruce Rew, senior vice president of operations, told stakeholders Nov. 13 the RTO also does not expect any fuel-supply or resource issues across its fleet. 

“We are, however, continually performing studies to assess system changes and to develop ways to mitigate problems should any study indicate the potential for those to occur,” Rew said during SPP’s annual winter preparedness workshop. “Extreme weather can and has stressed our system from a capacity perspective, but we have procedures in place to ensure the grid remains stable.” 

He said SPP will take preemptive actions to prepare for worst-case scenarios should extreme weather occur, as has happened in each of the two previous winters. In February 2021, Winter Storm Uri forced the grid operator to shed load for the first time in its 80-year history. (See ERCOT, MISO, SPP Slough Load in Wintry Blast.) 

Rew said this year’s winter assessment forecasts a peak load of 46 GW, just below last December’s record peak of just over 47 GW. The assessment looked at typical load levels with normal expected outages. 

SPP staff are forecasting near-normal temperatures in the central and southern portions of its region and above-normal temperatures in the North. They say a strong Arctic outbreak is less likely but that there is an increased chance of winter precipitation in the South, thanks to the El Niño weather pattern’s strong subtropical jet stream. 

MISO Says Overloads and Congestion Loom Without 2nd Long-range Tx Portfolio

CARMEL, Ind. — After completing its initial economic and reliability analysis, MISO has found that numerous overloads and congestion await its system if it doesn’t recommend a second long-range transmission plan (LRTP) portfolio.

“Keep in mind this is the start of the analysis. There’s much more work to do to translate these studies into transmission lines. So, expect to hear overloads today, not transmission projects,” Executive Director of Transmission Planning Laura Rauch told a Nov. 15 Planning Advisory Committee meeting.

That said, MISO found “significant” overloads and congestion on the system when it applies its envisioned 2042 resource mix in studies. Rauch said she expected the study results to show problems in the system.

Rauch said the second LRTP portfolio likely will shape up to be a “more complex solution” than the first, $10 billion LRTP portfolio. She said MISO’s analysis by 2042 found lines reach stability limits instead of just thermal limits and foresees a greater need for reactive power.

Rauch said MISO may have an idea of some projects by early spring.

“I would say at this point, all solutions are still on the table,” Rauch said of project sizes and voltages.

Rauch said MISO’s West Region — Minnesota, Iowa, Wisconsin, North Dakota and portions of South Dakota, Montana and Michigan’s Upper Peninsula — showed a need for higher-voltage transmission facilities to “support large power transfers and enable generation resources from remote areas to be delivered to load centers.”

By 2042, MISO found 20% of the facilities in the West Region will be overloaded, with annual generation curtailments exceeding 15%.

On the other hand, MISO said its Central Region — most of Illinois and Indiana and portions of Kentucky and Missouri — will be instrumental to supporting system transfers. It said about 10% of the Central Region’s facilities will be overloaded by 2042 without significant transmission expansion.

Rauch also said she expects MISO will have “additional challenges to solve” in the Central Region based on anticipated weather patterns and expanded transfer needs.

Finally, MISO’s East Region —most of Michigan’s Lower Peninsula — will need increased import and export capabilities by 2042. By then, MISO said about 10% of the East Region’s facilities will be overloaded, with annual curtailments surpassing 15%.

Rauch said the overloads and binding constraint hours uncovered in MISO’s initial studies will form the foundation of its list of transmission needs for the second LRTP portfolio.

“We may not solve all of them, but all of them will be considered,” Rauch said.

Rauch also said MISO has been sharing the results of its LRTP analyses with the Independent Market Monitor, who has voiced concerns with the future energy mix MISO predicts by 2042. (See MISO Promises Analyses on Long-range Tx; Stakeholders Divided on IMM Involvement.)

The second LRTP cycle again zeroes in on MISO Midwest; the third portfolio will pay attention to MISO South needs, and the fourth will address power exchange limits between the Midwest and South regions. MISO has said while the first, $10 billion portfolio is an “important start, further work is needed to ensure reliability.”

Meanwhile, the Organization of MISO States again has hired RLC Engineering to independently assess future projects in the second LRTP portfolio. For the first portfolio, RLC arrived at a 1.4:1 benefit-to-cost ratio for projects, smaller than MISO’s overall projection of 2.6:1.

MISO will hold an LRTP workshop Dec. 1 to dedicate more discussion to its initial findings.

“We’re just getting started and looking forward to the journey,” Rauch said.

NERC Expecting Packed 2024 for Standards Actions

NERC’s Standards Committee can expect a packed year of reliability standards development in 2024, Vice President of Engineering and Standards Soo Jin Kim said at the committee’s monthly meeting Nov. 15.

Updating members on NERC’s Reliability Standards Development Plan (RSDP), Kim said there are 11 standards development projects the ERO considers high-priority — meaning they must be adopted by NERC’s Board of Trustees by the end of 2024. These include the following projects, some of which are targeting earlier approval dates:

    • 2021-07 (Extreme cold weather grid operations, preparedness and coordination) — to be approved by February
    • 2016-02 (Modifications to CIP standards) — February
    • 2023-03 (Internal Network Security Monitoring) — May
    • 2023-02 (Performance of inverter-based resources) — October
    • 2023-07 (Transmission system planning performance requirements for extreme weather) — December
    • 2020-02 (Modifications to PRC-024 (Generator ride-through)) — December
    • 2021-04 (Modifications to PRC-002 (Data sharing)) — December
    • 2021-03 (Modifications to CIP-002) — December
    • 2023-04 (Modifications to CIP-003) — December
    • 2023-06 (Physical security) — December
    • 2022-03 (Energy assurance with energy-constrained resources) — December

An additional 14 medium- and low-priority projects are targeting board adoption in 2025 and beyond, Kim said, and will not be posted for formal comment or ballot periods in the first half of 2024 in order to allow industry stakeholders who are part of the ballot body to focus on the most pressing projects. Kim clarified that these projects will still move forward during this time and be allowed to hold informal postings to solicit industry feedback on their progress.

NERC also considers FERC’s order last month that the ERO develop standards on the reliability of inverter-based resources (IBR) a high priority, Kim said, adding that the commission’s mandate “threw us for a loop” because it meant revising the draft RSDP to account for it. (See FERC Orders Reliability Rules for Inverter-Based Resources.) While no standard authorization requests (SAR) have been created yet for the order, NERC’s Engineering department is working with other groups in the organization to create a plan for tackling FERC’s directive.

Standards Actions Approved

Later in the meeting, the committee voted to move forward with two standards projects.

First, members agreed to post proposed revisions to NERC’s glossary for the terms “IBR” and “IBR unit” for a 45-day formal comment period. The changes were suggested by the standards development team for Project 2020-06 (Verifications of models and data for generators) after it received stakeholder requests to provide clearer definitions for terms used in its proposed standards.

The changes would define an IBR unit as a device or group of devices that use a power electronic interface such as an inverter or converter, capable of exporting real power from a primary energy source or energy storage system. An IBR would be defined as a source of electric power connected to the transmission, sub-transmission or distribution system and that consists of one or more IBR units operated as a single resource at a common point of interconnection.

Both definitions finished an informal comment period last month. The formal comment period, as approved by the committee, will begin Nov. 16 and conclude Jan. 4, 2024.

Committee members also accepted a SAR proposed by the SDT for Project 2023-07, meant to address FERC’s June order directing NERC to update its rules to require responsible entities to plan for extreme heat and cold weather events (RM22-10). (See FERC Approves More Extreme Weather Rules.) The new SAR will allow the Project 2023-07 team to decide whether to draft a new standard or revise TPL-001-5.1 (Transmission system planning performance requirements).

The committee deferred action on accepting another SAR intended to address risks posed by extreme weather, electric-natural gas interdependencies and disturbances impacting distributed energy resources. Members agreed to delay a vote on the SAR until the committee’s December meeting, to be held at NERC headquarters in Atlanta, after several attendees noted that the proposed SAR would also assign this effort to the 2023-07 team and expressed concern about the possibility of overloading the project.

NJ Commits Millions for EV Vans, College Campus Decarbonization

New Jersey’s mass transit agency, NJ Transit, will spend $3.8 million on 19 electric vans, and the Board of Public Utilities (BPU) is offering grants of up to $5 million to entice colleges to launch decarbonization programs as the state seeks to push deeper emission reductions. 

The transit agency’s purchase, which the board approved on Nov. 8, is part of its slow but steady foray into electrification. The vans will be used to help seniors and disabled residents and an on-demand shuttle service that will link Route 9, a main artery through Central Jersey, to residential areas. 

The BPU’s campus initiative, which the agency opened on Nov. 1, creates a pilot program to reimburse colleges, universities and higher education institutions for up to 100% of the cost of putting together a plan to cut carbon emissions through energy efficiency, electrification, EV chargers and storage, among other methods. 

To be eligible, institutions must have multiple buildings and produce a plan that covers the entire campus. The program also offers $1,000/ton of carbon dioxide equivalent reduced. 

“Unlike traditional energy-efficiency programs, the decarbonization pilot is designed to explicitly target [greenhouse gas] emissions reductions,” the program participation guidelines said. 

Together, the initiatives address two of the state’s largest sources of emissions: transportation and buildings. The program is “designed to encourage colleges, universities and educational institutions to support New Jersey’s clean energy future by taking actionable steps toward decarbonization,” the BPU said in announcing the pilot. 

“We all have a role in protecting the environment and reducing carbon emissions,” the BPU said. “This program assists educational institutions in achieving their decarbonization goals.” 

Sustainability Goals

NJ Transit President Kevin Corbett said the purchase of EVs and their integration into the mass transit system will be critical to modernizing the agency. 

“This purchase not only helps our local communities transition to electric vehicles to support the state’s sustainability goals, but it also advances our mission to provide accessible transportation for all New Jerseyans,” he said. 

The agency will use eight of the vans to provide community services in Essex, Middlesex and Somerset counties so that it can offer transportation for populations including seniors, people with disabilities, veterans, job seekers and rural residents. “This type of service can potentially serve residential customers at lower cost, with more operational and customer flexibility than is provided by limited, fixed-route “branch” services,” NJ Transit said in a release. 

Another eight vans will be used for an on-demand shuttle service that will “test the feasibility” of creating an on-demand microtransit shuttle to connect mainline commuter bus corridors to lower-demand residential areas, the release said. 

The state’s 2019 Energy Master Plan included directives for NJ Transit to implement an electric bus program and introduce a battery-electric train prototype by 2025. The state’s Global Warming Response Act (GWRA) report, which outlined legislative and policy initiatives to confront global warming, called for 10% of NJ Transit’s new buses to be zero-emission by Dec. 31, 2024, and all new bus purchases to be zero-emission by 2032. 

But a second vote at the NJ Transit board of directors’ monthly meeting last week highlighted the difficulty of electrifying an agency that operates 263 bus routes, three light rail lines and 12 commuter rail lines. NJ Transit calls itself the “nation’s largest statewide public transportation system.” 

Before the board backed the purchase of the 19 electric vans, it approved the purchase of 550, 40-foot diesel buses and 200, 60-foot diesel buses for a cost of $686 million. The buses will replace vehicles in the agency’s existing fleet, which has more than 1,300 buses, many of which are “over age and due for replacement,” according to the board’s purchase resolution. 

The resolution said NJ Transit expects the purchase of the new buses will be the “last diesel bus procurement contingent on the successful advancement of the bus modernization program to completely convert to a zero-emission bus fleet.” The new buses, although they are not fueled by clean energy, will be fitted with “the latest technology to significantly reduce vehicle exhaust emissions,” the resolution says. 

The purchase approval comes just over a year after the agency put into service its first electric bus. The bus is part of a pilot program that will put eight electric buses costing $9.5 million into service from the Newton Avenue Bus Garage in Camden. The agency converted the South Jersey garage to handle electric buses at a cost of $9.5 million. (See NJ Transit Advances with EV Bus, Sustainability Plans.) 

The agency in October approved additional design work for the conversion of the Hilton Garage in Maplewood. The agency also is assessing the condition of two other garages in Westwood and Newark for possible conversion to handle EVs. 

Nevada Geothermal Auction Fetches $1M for BLM

As part of its efforts to lease land for renewable energy production, the Bureau of Land Management (BLM) auctioned leases for 33 geothermal parcels in Nevada on Nov. 14, fetching just over $1 million.

The sale offered 45 parcels totaling 134,866 acres in 12 counties. Bids were received for 33 parcels, covering 96,605 acres.

The leases went to eight bidders, according to results published by BLM. TLS Geothermics Corp. won leases for eight parcels. The French company also won leases for five Nevada parcels in a geothermal auction last year.

Zanskar Geothermal and Minerals won leases for six parcels. Zanskar’s mission is to discover geothermal energy faster using big data, the Utah-based company’s website states.

Ormat Technologies and Photosol US each won five leases. Norte Geothermal won leases for four parcels, and FLHN 1 LLC won three.

Rodatherm Energy Corp. and Baseload Power U.S. won leases for one parcel each.

BLM issues geothermal leases for 10 years. Following the auction, the winning bidders must submit site-specific proposals before energy development can begin.

Nov. 14’s auction, which earned $1.025 million, was smaller in scope than BLM’s Nevada geothermal lease auction last year. The bureau’s competitive auction in August 2022 brought in $3.3 million for 66 Nevada geothermal parcels totaling 192,912 acres.

And those results are a far cry from a BLM auction in June that raised a record-breaking $105 million. That auction was for four parcels in the Amargosa Desert in southern Nevada for solar development. (See BLM Holds Record-breaking Solar Auction in Nevada.)

Still, Nov. 14’s auction will help meet the Biden administration’s goal of permitting 25 GW of solar, wind and geothermal production on public lands by 2025, BLM said in a release.

“Issuing geothermal leases is an important piece of the dynamic energy portfolio in Nevada,” Justin Abernathy, BLM Nevada deputy state director of energy and minerals, said in a statement. “BLM carefully analyzed these parcels, and this successful lease sale is the initial phase to developing new, clean energy sources.”

BLM has tentatively scheduled its next competitive geothermal lease sale for October 2024.

Nevada has 26 geothermal power plants in 17 locations, and the state’s geothermal generation capacity of 827 MW is second only to California, according to the Nevada Division of Minerals.

Ormat has several geothermal power plants operating in Nevada. The Reno-based company submitted the highest per-acre bid in Nov. 14’s auction of $130 for a 2,494-acre parcel in Mineral County.

Ormat’s projects include a geothermal power plant in North Valley, Nev., whose completion was announced in May. The project included construction of a 58-mile transmission line in addition to the 25-MW power plant.

But another project Ormat is planning in Nevada has hit a roadblock: A group of plaintiffs filed a complaint in U.S. District Court in January challenging BLM’s approval of Ormat’s geothermal exploration project near the town of Gerlach.

The town is a gateway to the annual Burning Man festival, and plaintiffs in the case include the Burning Man Project, which runs the annual event, as well as the Summit Lake Paiute Tribe of Nevada and Friends of Nevada Wilderness.

The plaintiffs said BLM didn’t consider in its environmental review the potential impacts to “inimitable” hot springs in the area. The defendants also failed to consider impacts of “the future but inevitable large-scale geothermal production project,” the complaint said.

In addition to BLM, the Department of the Interior and Interior Secretary Deb Haaland are named as defendants. The federal defendants have denied the allegations. Parties in the case continue to file briefs.

NYISO Stakeholders Advance Rules on Ambient Ratings, Internal Controllable Lines

RENSSELAER, N.Y. — NYISO’s Business Issues Committee on Wednesday approved tariff revisions to align day-ahead market (DAM) congestion settlement procedures with ambient-adjusted ratings (AARs). 

FERC Order 881, issued in December 2021, mandated transmission providers evaluate their transmission capacity based on real-time environmental conditions, such as air temperature, wind speed and solar radiation (RM20-16). The order requires transmission providers to use AARs for short-term transmission requests — 10 days or less — for all lines impacted by air temperature. Seasonal ratings will be required for long-term service. (See FERC Orders End to Static Tx Line Ratings.) 

NYISO’s proposed revisions aim to resolve inconsistencies between AAR rating limits used in the DAM and those assumed in transmission congestion contract (TCC) auctions.  

This included changes to calculations of the congestion rent impacts of uprates and derates and the creation of a new category of qualifying events resulting from differences in the DAM ratings required by Order 881 and those assumed in TCC auctions.  

FERC partially rejected NYISO’s initial July 2022 compliance filing, saying that some of the ISO’s revisions fell outside Order 881’s scope, certain terms were inadequately defined and the ISO was non-compliant with the timeline requirements of the order. (See FERC Approves Batch of Line Ratings Compliance Filings.) NYISO is awaiting a decision on its second compliance filing, submitted in June 2023. 

NYISO’s ability to adjust its transmission line ratings in real time has become increasingly important to maintaining grid stability and efficiency, especially as the grid integrates more intermittent energy sources and climate change leads to more variable weather patterns. 

The proposed changes now move to the Nov. 29 Management Committee for final approval. The ISO plans to implement the changes alongside its compliance proposals already accepted by FERC.  

Internal Controllable Lines

The BIC also voted Nov. 15 to recommend the MC’s approval of energy market, capacity market and market mitigation rules for new “internal controllable lines” (ICLs).  

Clean Path New York (CPNY), a 175-mile, 1,300-MW HVDC line, will be the first ICL in the New York control area. CPNY, which was selected under the New York State Energy Research and Development Authority’s Tier 4 renewable energy certificates program, will deliver renewable power generated upstate into New York City. 

The ISO’s revisions will optimize ICL flows based on economic dispatch to serve loads at the least as-bid cost. Bilateral energy market transactions will not be permitted to source to or sink from an ICL. 

The lines will be eligible for day-ahead bid production cost guarantee (BPCG) payments and for real-time BPCGs only if they are dispatched out-of-merit for reliability. They also will be eligible for day-ahead margin assurance payments when scheduled out-of-merit or derated for system security or to permit the ISO to produce additional operating reserves. 

ICL bids will include an operating range and up to an 11-step dollar/MWh curve based on CPNY’s willingness to be paid or to pay to transmit energy between its two terminals. They will be limited to a maximum bid of $1,000/MWh and a minimum bid of -$1,000/MWh. 

Both day-ahead and real-time settlements will be based on the price differentials between the injection and withdrawal buses, and line losses. 

The ISO said it is proposing a flexible capacity market design without tying supply to specific generators. An ICL must hold unforced capacity delivery rights to be a capacity supplier; it would transmit pooled capacity, sourcing in the NYCA and sinking in a locality. 

Because HVDC lines can ramp up and down as fast as 1,000 MW per second — versus the 10-20 MW per minute averaged by a typical 1,000-MW generator — ICLs’ ramp rates may be subject to limits to protect system stability. 

No new market mitigation measures will be required for ICL’s functionality but the ISO will develop a new conduct test for uneconomic production.  

Mark Younger, president of Hudson Energy Economics, asked about NYISO’s proposal to set ICL deviation charges — fees assessed to market participants for differences between their scheduled and actual energy generation or consumption — at 1.5% of the ICL’s upper operating limit. 

Michael Swider, senior market design specialist at NYISO, explained that the deviation tolerance was reduced from 3% because the operations team determined the lower threshold to be more appropriate.  

Assuming approval by the MC, NYISO plans to file its revisions with FERC in early 2024. 

BIC Election

The BIC elected Timothy Lundin, transmission regulatory policy manager for LS Power Grid NY, as the committee’s new vice chair.  

Lundin currently chairs the Electric System Planning Working Group’s but will leave that position at year’s end.  

October Market Operations

NYISO Senior Principal Economist Nicole Bouchez presented the October market operations report, noting significant declines in natural gas and distillate prices and average monthly energy costs. 

October’s average energy cost was 56% lower than the previous year, falling from $89.47/MWh to $39.44/MWh. Natural gas and distillate prices saw year-over-year reductions of 72.2% and 27.2%, respectively. The month’s LBMP also decreased to $28.10/MWh, lower than September’s $36.92/MWh and last October’s $53.11/MWh. 

Bouchez mentioned the delayed development of an operating protocol for the Long Mountain phase angle regulator (PAR) installation, also known as the Dover PAR, due to ongoing court challenges (2023-50796). The timeline to complete an agreement for this 345-kV intertie between NYISO and ISO-NE remains uncertain. 

Project Prioritization Proposal

At the Nov. 15 Budget & Priorities Working Group meeting, Kevin Lang, partner at Couch White representing the City of New York and Multiple Intervenors, proposed major changes to NYISO’s project prioritization process that seek to shorten the process, improve stakeholder coordination and enhance overall efficiency. 

Lang suggested shifting project prioritization to later in the year to allow for more accurate assessments of project costs and resource availability and facilitate a smooth transition into the subsequent year’s work. He acknowledged this could increase NYISO staff workloads but said the benefits would outweigh the extra effort 

The proposal was well received, with both Younger and Anthony Abate, lead energy market advisor for the New York Power Authority, commending Couch White for striving to improve these processes. They agreed that more information would enable better decision-making.  

Lang encouraged stakeholders to send comments or suggestions to klang@couchwhite.com. He said he plans to present an updated proposal that incorporates submitted feedback in January 2024. 

Stakeholder Soapbox: Let the Market Determine the Fate of EVs

Advocates of various energy technologies have long argued that major barriers, either government or market derived, stifle the development of their favored technology. They then infer that the current level of their preferred technology is suboptimal, necessitating some form of governmental intervention.

That seems to hold true for New Mexico Gov. Michelle Lujan Grisham, who wants state tax credits and mandates on the purchases of electric vehicles (EVs). New Mexico already has a stringent clean car rule that requires that by 2031, 82% of all new vehicles delivered to the state be zero emission. Her agenda is a double whammy for gasoline/diesel-powered vehicles: make EVs more economically attractive with taxpayer-funded subsidies and restrict the number of gasoline/diesel-powered vehicles New Mexicans can buy. She is essentially forcing EVs on New Mexicans faster than what they prefer.

Perhaps the most pathetic part of her agenda is that she hopes to trim down the number of gasoline/diesel-powered vehicles in the state without knowing whether that is what the residents of New Mexico want. (Car owners are wary of EVs for various reasons, including: their high upfront costs; range anxiety, i.e., their fear of not making it to the next charging station; and their inherent skepticism of new technologies.) How arrogant is that? She is telling New Mexicans that as governor, she knows better what types of vehicles they should purchase than they do. She is ignoring the wishes of her constituents to purchase different vehicles: Today, only about 1% of the vehicles in New Mexico are EVs.

She desires to fundamentally reshape the car industry via regulations, mandates and subsidies. Added to the insult is her requirement that taxpayers pay for her “all-electric” scheme when the majority of residents don’t stand to benefit.

So far, purchasers of EVs are mostly in the high-income category, and that will likely hold for the foreseeable future. That means tax credits and other subsidies will benefit the well-to-do and be paid for by folks who are less financially well off. One study remarked that “The US academic literature indicates that up to 90% of EV purchase incentives adopted by the federal government have flowed to the richest one-fifth of households.”[1] This also suggests many of the purchasers would have bought an EV in the absence of government incentives. This behavior means (1) the reduction in greenhouse gas (GHG) emissions attributable to the incentives are overstated and (2) the incentive is essentially a windfall gain to higher-income households paid for by less-well-off ones.

And what is in it for the residents of New Mexico and other jurisdictions inducing EV purchasers with subsidies and mandates? Zilch! What almost always gets ignored is the fact that no matter how many EVs New Mexicans or people in other jurisdictions buy, the effect on climate change is negligible.

A mandate to require that a certain percentage of vehicles be EVs represents a policy with intrinsic distortions. It is a highly blunt instrument, draconian and expensive relative to other ways to mitigate GHG emissions (which is the manifested rationale for the governor’s all-electric mandate).

Probably most serious, banning or artificially restricting goods or services reflects governmental action that dictates consumers find a substitute that presumably is inferior to the alleged objectionable product that is banned, or else such action would not be necessary. A ban forces consumers to do something they otherwise would not do. For example, vehicle owners could hang on to their old, less fuel-efficient vehicles longer than otherwise — a perverse outcome that could lead to higher GHG emissions.

By reducing options for vehicle owners, driving will become more expensive in New Mexico. Perhaps this is the intent of those who are anti-car. As warned by energy expert Mark Mills of the Manhattan Institute, “they’re coming for your cars.”

Government controls over GHG emissions directly affect goods and services, such as electricity and transportation, whose costs will likely escalate. If controls include banning or severely restricting fossil fuels like gasoline, the costs could be substantial. We have an abundance of fossil fuels at affordable prices, which explains why over 80% of the world’s energy still comes from fossil fuels. This raises the question of whether we want to or can wean ourselves from fossil fuels over the next two or three decades without suffering severe economic consequences.

The governor’s actions presume that EVs are a winning technology — but this is highly presumptuous, as there is much uncertainty over the future of EVs. Mandates carry risks. Mandates require policymakers to pick winners and losers, which is inherently almost impossible, and often results in failure, given the limited knowledge of policymakers (which, of course, they don’t want to acknowledge) and their propensity to serve special interests. The problem is particularly acute for new technologies with a high level of uncertainty over cost and performance. For example, a policy that mandates EVs as a preferred option can turn out disastrously if the price of gasoline falls sharply or if EVs fail to develop economically and technically as advocates hope.

A better way to make EVs more attractive to consumers is to have them compete against gasoline/diesel-powered vehicles. When regulating or legislating away their main competition, it becomes more likely that EVs will continue to be inferior to gasoline/diesel-powered vehicles. This is just one example of the unintended consequences sprung from a policy whose prime intent is to promote a particular technology.

What is particularly perplexing is the rationale behind the governor’s intent to accelerate the purchase of EVs by New Mexicans through tax credits and mandates. She argues that the tax credits will make EVs more affordable to middle- and low-income households. But one cannot ignore the evidence showing that the subsidies will disproportionately benefit the wealthy at the expense of those less well off. So far, 90% of EVs in the U.S. have been purchased as a second or third car by high-income households. [2]

It’s not even clear that replacing gasoline/diesel-powered vehicles with EVs will have a positive environmental effect. Similar to many other batteries, the lithium-ion cells that power most electric vehicles rely on raw materials (like cobalt, lithium and rare earth elements) that have triggered grave environmental and human rights concerns. Cobalt has been especially problematic. The environmental effect, of course, also depends on what energy sources are used to produce electricity. Currently, much of the electricity generated at night (when charging occurs for most EVs) comes from fossil fuels.

Even if EVs lower GHG emissions, studies have shown they are an inefficient way in terms of the costs per unit of avoided emissions. Other alternatives, such as nuclear power and natural gas are more cost-effective. One study claimed that EVs are among the most expensive tools government can use to lower GHG emissions, measured as dollars spent to achieve a given amount of GHG reduction.[3] What would seem to be a preferred social policy is to impose an efficient tax on GHG and tailpipe emissions.

I believe that what is driving EV frenzy is the anti-fossil fuel agenda or virtue signaling (by both EV purchasers and EV advocates). EV advocates probably know EVs would have a minuscule effect on climate change but long to see the extinction of fossil fuels; I can’t think of a more plausible explanation.

To wit, most climate activists view fossil fuels as a barrier to achieving deep-decarbonization targets deemed essential to protect against alleged catastrophic climate change. They consider electrification of buildings and transportation with clean energy sources as part of a policy portfolio to achieve these targets. What they don’t say is that their proposals for government intervention will fail a cost-benefit test and are regressive by benefiting the well-to-do at the expense of others. How can they then defend their pro-EV advocacy with such anti-social results?

I want to conclude by saying that I think EVs are a remarkable technology that I hope will succeed on its own without government assistance. Both for equity and economic-efficiency reasons, government inducements — whether to hasten the number of EVs or charging stations through perverted policies — are a bad idea. Governments can better spend taxpayers’ monies. EVs have a promising future. Technological advancements in batteries and the other sides of production, as well as in charging stations, will ultimately decide the fate of EVs, as they will determine consumers’ demand for EVs and manufacturers’ profits from EVs. Their success is more likely if government steps out of the way and allows EV providers to address market demands to lure consumers with price reductions and better vehicle performance — not with subsidies and mandates.

Kenneth W. Costello is a regulatory economist and independent consultant.

 

[1] Fraser Institute, https://www.fraserinstitute.org/sites/default/files/review-of-electric-vehicle-consumer-subsidies-in-canada.pdf.

[2] Energy Institute at Hass, https://energyathaas.wordpress.com/2021/09/20/three-facts-about-evs-and-multi-vehicle-households/.

[3] International Monetary Fund, https://www.imf.org/en/Publications/fandd/issues/2019/12/the-true-cost-of-reducing-greenhouse-gas-emissions-gillingham.

Northeast States Detail Early Efforts on Interregional Tx Collaborative

States in the Northeast are working together to expand interregional transmission with a focus on coordinating the connection of offshore wind facilities to the grid, according to speakers on a Wednesday webinar hosted by Advanced Energy United. 

Representatives from states working on the Northeast States Collaborative on Interregional Transmission spoke about the first months of their work since the effort was launched in June with a letter to the Department of Energy. 

“We still are in early days of the collaborative,” said Jason Marshall, deputy secretary of the Massachusetts Executive Office of Energy and Environmental Affairs. “But I think with as much expertise as we have in the room, focused in one place, we really do have a unique opportunity to chart a path forward toward greater interconnectivity.” 

While the collaborative has a focus on helping to connect offshore wind, Abe Silverman, director of the Center on Global Energy Policy’s Non-Technical Barriers to the Clean Energy Transition initiative at Columbia University, said the benefits of transmission go well beyond that. Transmission has helped regions better manage recent reliability events such as last December’s winter storm, he noted. 

“This is about money at the end of the day for a lot of folks,” Silverman said. “And so, as we think about building this coalition between various states — both states with really aggressive carbon policies and states with less interest in that — we really need to talk about the money piece of it, and transmission can be enormously cost saving as well.” 

The initial letter was signed by the six New England states, New York and New Jersey, which all have similar energy policies, but some of their neighbors are very different. Preethy Thangaraj, who advises New Jersey Gov. Phil Murphy (D) on energy policy, said that the states in PJM have very diverse energy policies — ranging from states like hers with strong net-zero goals, to West Virginia, where no such laws are on the books. 

The best example for multistate transmission expansion is MISO’s Multi-Value Projects, where every state got some kind of benefits, which helped connect a lot of wind power to the grid, said Silverman. 

“But it was really looking at all of this sort of value stacking of benefits that transmission gives you,” he added. 

MISO is a very large RTO, but it is a single region, while the states in the planning effort stretch across three separate markets: ISO-NE, PJM and NYISO. That means they will need to go through interregional planning, which, despite Order 1000 being on the books for a decade, has not taken off. 

Most interregional transmission lines have been backed by specific developers to ship renewables long distance, while those that have cleared the FERC planning processes have dealt with really “crisp issues,” such as the loop flows around Lake Erie more than a decade ago that impacted reliability across several markets, Silverman said. 

“The amount of true interregional planning, where you sort of look at the needs of one region and optimize it by building transmission to another region and look at their benefits and costs as well, is a relatively new concept, or at least it hasn’t really been activated,” said Silverman. “So, we talk about it a lot, but what we really need is for FERC, and to some extent the DOE, and I think the states, to come together and say: ‘OK, you know, we’ve talked about this for a while, we now need to go ahead and actually do it.’” 

The New England states especially have worked together on energy issues several times in the past, but really focusing on the transmission needed to help reliably and affordably to meet their clean energy goals is a new effort, said Bruce Ho, senior policy adviser for the Connecticut Department of Energy and Environment. And this time they need some help. 

“Ensuring this effort is successful really does critically depend on the support and interactions we have with the federal government and particularly the Department of Energy,” Ho said. “The transmission vision buildout we’re thinking of crosses state borders; it’s inherently federal.” 

ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel

ISO-NE presented the final stage of its Operational Impact of Extreme Weather Events study to stakeholders at the NEPOOL Reliability Committee (RC) on Nov. 14, shedding light on how changes to the 2032 resource mix could affect reliability in the region.

The analysis built upon findings for the winter of 2032, which were originally presented to the RC in August. The new results stemmed from additional tests — or “sensitivity analyses” — based on stakeholder requests, which included adjustments to the load profile, clean energy additions, and fossil fuel and nuclear retirements.

The sensitivity analyses assessed the 2032 grid under a worse-case scenario based on historical weather patterns from a 21-day stretch in the winter of 1961, which had the highest average system risk of all similar periods considered.

The analysis used the 2023 Capacity, Energy, Loads and Transmission (CELT) report’s load forecast for 2032, with a resource mix built around the results of Forward Capacity Auction 17. It assumed the presence of the New England Clean Energy Connect transmission line, which is under construction in Maine but has faced extensive legal and political challenges.

The results “reveal a range of energy shortfall risks and highlight the increasing energy shortfall risk between 2027 and 2032, said Stephen George of ISO-NE. George qualified that the findings “are useful for highlighting directional changes in energy shortfall risk under various assumptions; [the] results should be considered in the context of the specific assumptions made and the attributes of the Jan 22, 1961, 21-day event.”

The baseline case and the sensitivity analyses looked at shortfall with and without the Everett LNG import terminal in service. (See FERC, NERC Leaders Voice Concern About Loss of Everett Marine Terminal.) Counterintuitively, the modeling indicates that the presence of Everett marginally increases energy shortfall by enabling greater injections of LNG into the gas network and causing the region to run out of its LNG stockpile more quickly.

However, ISO-NE has cautioned that this aspect of the model should not be considered a perfect representation of future LNG stockpiling behavior.

The analysis found that replacing 1 GW of fossil resources with additional offshore wind capacity reduced the projected shortfall by 37 to 42% compared to the baseline scenario. In contrast, limiting the total offshore wind capacity to 1,600 MW — compared to the 5,600 MW assumed in the baseline scenario — increased the shortfall by 165 to 193%.

The offshore wind industry in New England has seen several major project cancellations over the past year, and industry experts have expressed their worry that this could push the in-service dates of the next wave of projects in the region into the 2030s. (See Long-term Optimism Meets Short-term Concern at Offshore WINDPOWER 2023.)

The study found that replacing a gigawatt of fossil fuel generation with onshore wind and utility-scale solar also improved reliability, but to a lesser degree. Onshore wind was associated with a 25% reduction in shortfall, while solar was associated with a 3 to 5% shortfall reduction. However, replacing the same amount of fossil fuel generation with two-hour-duration storage was associated with an 11 to 19% increase in shortfall.

The analyses modeled only two-hour-duration battery storage resources; ISO-NE received requests from stakeholders to look at longer durations but was limited by the study’s time constraints.

“Future modeling enhancements will enable the incorporation of longer-duration storage,” George said.

The baseline scenario did not include nuclear retirements, but the sensitivity analysis found that retirements would increase shortfall in all scenarios considered. Replacing all nuclear capacity with the same amount of renewable qualified capacity led to a 50 to 76% shortfall increase. George noted that retiring nuclear resources without corresponding renewable replacements would also significantly increase the region’s reliance on oil and LNG.

Regarding fossil fuel resources, the study found residual fuel oil (RFO) resources to be especially helpful to maintaining grid reliability. Replacing all RFO resources with the same amount of renewable qualified capacity led to a 19 to 36% increase in shortfall.

“Energy from resources that burn stored fuels will continue to be important in terms of minimizing energy shortfall as the region transitions to higher penetrations of renewable resources,” George said.

The study found that the retirement of 1.5 GW of gas-only generators had minimal effects on the projected shortfall because of the limited amount of natural gas available during the study period. Replacing these retiring resources with an equal amount of renewable nameplate capacity decreased shortfall by 24%.

Increasing the level of electricity imports also made a significant dent in the projected shortfall; a 50% increase in imports coupled with the elimination of the cap on maximum transfer capability reduced shortfall by 66%. Demand response also boosted reliability; an added gigawatt of active demand response capacity cut shortfall by 38 to 39%.

Finally, changes to the overall load profile had a significant effect on the shortfall. Increasing the load by 10% led to a 156 to 192% increase in shortfall, while decreasing load by 10% reduced shortfall by 84 to 87%. A 20% increase in behind-the-meter solar reduced shortfall by 7 to 10%.

ISO-NE hopes to release a final report covering the results from all phases of the study in late November or early December. Following the final report, the RTO plans to use the results to begin work on a “Regional Energy Shortfall Threshold,” which will establish “the region’s acceptable level of reliability risk.”