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November 8, 2024

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Trucking Industry Estimates Massive Cost of Electrification

A new report by a research arm of the trucking industry quantifies challenges facing electrification of the sector, including the need for billions of dollars’ worth of chargers and vastly more power flowing through the grid.

Running every commercial truck on the road today with battery power instead of gasoline or diesel would consume 550 billion kWh per year, or 14% of the electricity now used in the United States, the American Transportation Research Institute (ATRI) said.

If most other U.S. vehicles also were electrified, as many climate-protection roadmaps call for, the demand would increase to 40% of present electrical consumption nationwide and as much as 60% in some states, the report concluded.

This growth would come as electrical demand from other sectors would be greatly expanding, at the same time that many power generators transition from polluting but reliable fossil fuel to clean but variable renewable energy.

On Dec. 5, ATRI released “Charging Infrastructure Challenges for the U.S. Electric Vehicle Fleet,” the second of two reports on zero-emissions trucking.

The new report flags several potential sticking points on the path to widespread use of electric trucks, including shortage of lithium for batteries and space for all the new truck charging stations that will be needed.

The report does not explicitly oppose wide-scale electrification of trucks, but in a news release announcing its publication, a member of ATRI’s board of directors suggests that the zero-emission mandates some states are pushing for heavy-duty vehicles cannot become an electrification mandate.

“The market will require a variety of decarbonization solutions and other powertrain technologies alongside battery electric,” wrote Srikanth Padmanabhan, president of the engine business of truck engine manufacturer Cummins.

ATRI is a nonprofit affiliate of the American Trucking Associations, which calls itself the largest trade organization representing the U.S. trucking industry.

Yellow Flags

The issues raised in the ATRI report primarily involve the heaviest trucks in long-haul service, rather than lighter trucks or those operating in a smaller radius. And they are offered with caveats, as it is impossible to quantify the impact of future technology and hard to generalize heavy-duty EV charging needs thanks to such factors as air temperature, battery state of charge, charging rate, age of battery and frequency of braking.

The yellow flags it raises boil down to scale: Staggering amounts of raw materials, electricity, time and real estate would be needed to build and charge electric versions of the 12 million fossil fuel-powered commercial trucks on the road today.

Simultaneous electrification of light-duty trucks and cars would ratchet up those challenges.

The report on the trucking industry’s challenges with electrification splits into three points of focus: Electrical supply and demand, electrical vehicle battery production, and logistical challenges to charging trucks.

It makes the following observations:

The interstate trucking industry must traverse 49 states and thousands of local jurisdictions. There are nearly 3,000 electrical utilities and more than 60 grid balancing authorities. This creates a patchwork of policies, prices, regulations and capacity.

Percent of Total Generation (American Transportation Research Institute) Alt FI.jpg

The percentage of each state’s present power generation output that would be needed to charge batteries if every vehicle registered in that state were electric. | American Transportation Research Institute

Roughly 3.93 trillion kWh of electricity was consumed in the U.S. in 2021. Had every internal-combustion vehicle in the nation been battery-powered, and if the study’s parameters are correct, those vehicles would have consumed an additional 1.59 trillion kWh. The 3 million heavy-duty tractor-trailers alone would have consumed 417 billion kWh.

Much of the infrastructure that would be called upon to generate and transmit this additional electricity dates to the mid- to late 20th century, during the last great period of expanded U.S. power consumption. Some of it is near the end of its useful life, and some is outdated. But with sufficient investment in generation and transmission, the necessary amount of power could become available.

Variable electric rates may be necessary to balance supply and demand in a given market, but they may hinder industry adoption of battery-electric trucks.

The existing shortage of truck parking will need to be addressed, but at much greater cost, because electric trucks need not only a place to park but an available charger at the parking spot.

Federal rules mandate truckers drive no more than 11 out of 24 hours, and an ATRI study found drivers already spend an average of 56 minutes a day looking for a place to park and go off duty. With truckers not allowed to be at the wheel more than half the day, it is economically unfeasible to have them sitting for hours charging or waiting to charge while on duty.

Battery-electric trucks weigh several tons more than their diesel-powered counterparts, meaning more trucks will be needed to carry the same amount of freight and remain under the 80,000-pound limit.

It takes a few minutes to pump 300 gallons of diesel into a heavy-duty internal combustion engine truck, enough to travel 1,800 miles. It would take more than four hours for a 210 KW charger to bring a 1,500-KWh battery to optimum 80% charge, and that would take a fully loaded tractor-trailer only about 500 miles.

To make widespread long-haul truck electrification possible, many hundreds of thousands of fast chargers are needed nationwide, at a cost that can exceed $100,000 each. (California estimates a need for 157,000 new chargers for medium- and heavy-duty vehicles within its borders by 2030, as it works toward all new trucks being zero-emissions by 2045.)

The authors said potential solutions include megawatt-level charging stations and wireless chargers embedded in roadways, both of which are currently in development; modular batteries that can be swapped out at a truck stop; and, in remote locations, off-grid charging.

The report also flagged thorny non-technical issues certain to arise, such as who will pay for installation and maintenance of the chargers, and noted that whatever cost increases truckers bear will trickle down to consumers of the goods they are hauling.

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Inslee Seeks Public/Private Cooperation on EV Charging Stations

Washington’s government should explore joining with businesses to build and share electric vehicle charging sites, Gov. Jay Inslee suggested last week. 

Inslee discussed the issue Wednesday on a video call with representatives from several state agencies to discuss their progress in trimming carbon footprints.

Part of the meeting covered installing fast chargers for EVs at state offices around Washington over the next decade. Inslee noted that state offices with lots of fast charging stations will likely see the chargers not being used for significant amounts of time, with private businesses finding the same.

The governor suggested that state officials connect with major businesses and organizations to jointly build charging areas and share their use. “I have to believe there are networking opportunities with larger groups,” he said.

Inslee is supervising government agency contributions to an overall state push to trim carbon emissions. A 2008 state law sets carbon-reduction targets of 45% below 1990 levels by 2030, 70% by 2040 and 95% by 2050. A 2021 Washington Department of Commerce report put the entire state’s carbon dioxide emissions at 99.57 million metric tons in 2018. The report shows that from 2016 to 2018, the transportation sector was the largest contributor, at nearly 45% of Washington’s emissions.

On Wednesday, Laura Watson, director of Washington’s Department of Ecology, said state agencies emitted 647,731 tons of GHGs last year, 13% below the goal set for 2020 and well below emissions of 879,036 metric tons in 2005.

The states ferry system — the largest in the U.S. — was the largest polluter last year at slightly more than 140,000 metric tons. The second and third largest emitters were Washington State University at 120,000 MT and the University of Washington at 100,000 MT.

The state agencies’ future goals are 483,470 MT in 2030; 219,759 MT in 2040; and 43,952 MT in 2050.

Last week’s meeting only covered charging station goals for Washington’s huge Department of Social and Health Services, which both owns and leases sites. DSHS goals for owned sites include 60 new charging ports on seven campuses by 2035 and 144 charging ports on more than eight campuses by 2040. The goals for the leased sites are 99 new charging ports on 59 campuses and 447 new ports on 99 campuses by 2035.

Inslee speculated that the state government could also help trim vehicle emissions by helping its employees install home charging stations. 

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NYISO Justifies Unpopular 10-kW DER Aggregation Min. Requirement

ALBANY, N.Y. — NYISO on Tuesday explained that its proposal to set a 10-kW minimum for distributed energy resource participation in an aggregation is necessary because the ISO’s software is not up-to-date and staff lack the capacity to audit potentially hundreds of individual DERs.

Harris Eisenhardt, NYISO market design specialist, told stakeholders allowing DERs of less than 10 kW would “require substantial amount of additional manual work” to complete the tasks to evaluate aggregation participation.

Staff are required to review the physical characteristics of DER applicants — which sometimes requires a site visit — verify proposed operational parameters and coordinate interconnection with distribution utilities, said Eisenhardt.

Software updates will eventually be able to automate many of these tasks, but NYISO has experienced unexpected delays, as it told FERC in its recently accepted extension request for Order 2222 compliance. (See FERC Gives NYISO Until 2026 to Complete Order 2222 Compliance.)

Stakeholders continued expressing displeasure with the proposal, claiming the requirement would exclude residential storage resources, ran counter to both FERC’s and the ISO’s objectives for DERs and placed barriers to aggregation participation. (See NYISO 10-kW Min for DER Aggregation Participation Riles Stakeholders.)

Aaron Breidenbaugh, director of regulatory affairs at CPower Energy Management, said he was concerned that the proposal “excludes all residential participation” and that there was no indication that the ISO would make any meaningful changes in the future.

Christopher Hall, of the New York State Energy Research and Development Authority, argued against the proposal, saying it “shuts out residential storage assets from participating because the average size of such assets is around 7 or 8 kW.” He asked the ISO where the 10-kW figure came from.

Eisenhardt responded that the number was the result of internal analysis and was set at the current threshold to “better understand initial penetration” of DERs and, considering NYISO’s incrementally based systems, the 10-kW value was seen as the “logical next step from 1 kW.”

Peter Fuller, on behalf of Sunrun, said NYISO is “misapprehending what Order 2222 is asking for,” and that the “administrative concerns” raised by the ISO could be solved with a change of mindset that focuses on enabling aggregations consistent of every resource.

Eisenhardt responded that NYISO appreciates stakeholders’ concerns, but he maintained that the proposed requirement would help the ISO get everything in place in a timely manner and ensure that the resources necessary to manage the initial set of DERs are in place.

One stakeholder asked why setting a lower minimum threshold, such as 5 kW, warranted software updates that would delay deployment.

James Pigeon, DER integration manager at NYISO, said the ISO is still unsure about how to treat differently structured aggregations and was not prepared to undertake additional manual bandwidth to evaluate individual, smaller-scale DERs.

Pigeon also said the ISO is not trying to shut the conversation down but is looking to get out the FERC-accepted model, learn more about initial DER deployment and avoid further delays in implementation. Pigeon told stakeholders that because NYISO now operates on a 2026 deployment timeline, there is still opportunity to find workable solutions.

Breidenbaugh told NYISO that it would be helpful if the ISO made tangible commitments to exploring more solutions, which Fuller followed up on by saying that without commitments to eliminate the proposed minimum, it will be hard for stakeholders to make future decisions or investments with confidence.

NYISO will present the draft tariff language at the Installed Capacity Working Group/Market Issues Working Group meeting Tuesday to seek approval from the Business Issues Committee and Management Committee in January.

Capacity Accreditation

Capacity Market Procurement Costs (NYISO) Content.jpgRevised capacity accreditation saves $390 million in capacity market procurement costs | NYISO

NYISO presented a timeline for the assignment of capacity accreditation factors (CAFs) and capacity accreditation resource classes (CARCs); implementation begins August 2023, and the first auction for the upcoming capability year starts in May 2024.

NYISO will post the CAFs for each CARC for the upcoming capability year to its website by March 1.

An updated consumer impact analysis the ISO is conducting on its proposed capacity accreditation method found that a revised analysis based on the recent 2022 Reliability Needs Assessment saved $390 million in capacity procurement costs when compared to existing approaches. (See “Capacity Accreditation of ‘Performance-based’ Resources,” NYISO Installed Capacity Working Group/Market Issues Working Group Briefs: Sept. 30, 2022.)

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Counterflow: Clean Energy Charging

tesla powerwallSteve Huntoon | Steve Huntoon

Just when you might have hoped for a respite from green/clean energy fantasies — like the miracle of Babcock Ranch I wrote about last month[1] — another one comes along.

Apple (NASDAQ:APPL) just rolled out “Clean Energy Charging” in iOS 16.1. (For tech dolts like me, that’s the latest iPhone operating system.)

The Claim

Apple says: “When Clean Energy Charging is enabled [which is the default] and you connect your iPhone to a charger, your iPhone gets a forecast of the carbon emissions in your local energy grid and uses it to charge your iPhone during times of cleaner energy production.”[2]

What’s going on here?

The Basics

To start with the basics, carbon emissions come from electric power plants fueled by fossil fuels (basically natural gas and coal). In order to get clean energy, power generation has to be shifted from fossil fuels to non-fossil fuels.[3] For what Apple claims to work, it has to change the time of charging iPhones from when fossil fuel generation otherwise would be running to when clean generation would run more because of the iPhone charging. This can only happen by changing the dispatch of electric generators “on the margin” (last to be turned on/first to be turned off) because only generators on the margin are affected by an incremental change in demand (in this case from the iPhone charging). With me so far?

To drill down on Apple’s claim, I’ll focus on PJM. An iPhone charges at about 5 watts.[4] There are about 24 million iPhones in PJM,[5] so we’re talking 120,000,000 watts (equal to 120,000 kWs, or 120 MWs, if all these iPhones are charging at the same time). This is a pittance in PJM, but let’s let that slide.

Clean?

Now let’s make an assumption that all the iPhones in PJM are charging at 5 watts at the same time — 120 MWs worth. But 87.8% of the time, the marginal generator in PJM is fossil fuel.[6] How does Apple know when to stop iPhone charging in order to resume charging during the other 12.2% of the time when it’s not fossil fuel generation on the margin?

Apple doesn’t tell its customers how it knows when that would be, and it did not respond to repeated requests to answer that mystery.[7] And even when non-fossil fuels are on the margin during a given hour, it is only for a fraction of that hour.[8] And even if Apple could somehow guess right on a given five-minute period (and on location wherever there is congestion), it may have to hold off charging for hours or days waiting for those minutes to come along — with 24 million irate iPhone users waking up to learn their iPhone didn’t charge last night because Apple was waiting for Godot.

By the way, that 12.2% doesn’t mean there’s a paucity of non-fossil fuel generation in PJM, which actually makes up 38.4% of all generation in PJM.[9] Instead it reflects the fact that non-fossil fuel generators have low variable costs (sometimes even negative because of the production tax credit), so they are dispatched first whenever they actually can generate. And so they usually are not on the margin.

Cleaner?

Now let’s assume Apple is only claiming “cleaner” energy rather than “clean” energy (despite this title for its new function). It might hypothesize that relatively low energy clearing prices are correlated with cleaner fossil-fuel generation. If that were the case, then Apple might use lower expected energy prices (such as from the day-ahead market) as a predictor of cleaner generation on the margin, and shift iPhone charging accordingly (such as from afternoon hours to wee hours). Although this hypothesis is theoretically possible, there are problems.

First, it appears that the marginal fuel has no material correlation with the time of day.[10] In other words, simply shifting iPhone charging from, say, afternoon hours to, say, wee hours wouldn’t necessarily make for cleaner energy.

Second, if the idea is to choose from time to time between natural gas and coal generation based on the lowest day-ahead prices, that in itself appears to be a crapshoot because the fuel costs of natural gas and coal generation tend to be close.[11] So if for a given next day, Apple goes with say the lowest cost hours of 2 to 4 a.m., there isn’t a solid reason to assume natural gas rather than coal will be on the margin.[12]

Third, data from ERCOT suggests no clear relationship between the generator offer price supply curve and generator emissions.[13]

Bottom line: Even if clean/cleaner charging of iPhones were possible, there’s no reason to think Apple is actually doing it.

We could use a little more virtue, and a little less virtue signaling.

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

[3] I’m assuming initially that Apple isn’t basing Clean Energy Charging on shifting iPhone charging from one fossil fuel like coal to another fossil fuel like natural gas. This would be misleading (i.e., not “clean”). But I’ll also discuss the prospect of merely “cleaner” generation later.

[5] There are about 65 million people in the PJM footprint, and about 37% of them have an iPhone based on national data (125 million iPhone users in the U.S. relative to 332 million total U.S. population).

[7] Macworld speculated that “Apple is probably partnering to get data from electric grid managers that shows the mix of energy sources powering the grid (for example, see the California ISO supply trend page), or with a third-party source like Watttime that seeks to measure when the electricity you use is powered by cleaner sources.” https://www.macworld.com/article/1065566/ios-16-clean-energy-charging.html.

[8] https://www.monitoringanalytics.com/data/marginal_fuel.shtml, picking any month and observing in the “Percent Marginal” column the fractions of hours for non-fossil fuel generation (principally wind).

[11] https://pjm.com/-/media/committees-groups/committees/oc/2022/20221208/item-15—fuel-supply-overview.ashx, slide 11 (These are in $/MMBtu so do not reflect the lower heat rate/higher efficiency of natural gas generation, but they make the point.)

[12] This observation is consistent with my own spot-checking of hourly generation/load reporting on PJM’s home page, www.pjm.com. Relative shares of coal and natural gas generation didn’t seem much correlated with total load.

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MISO, SPP Fall Short in 5th Try for Interregional Projects

After four joint studies by SPP and MISO last decade failed to turn up an interregional project, the RTOs began another effort in 2020 by searching for transmission projects that could solve congestion issues along their seam.

They have again come up empty.

“We basically have confirmed that we do not have any viable candidate projects this year,” SPP’s Neil Robertson told the RTO’s Seams Advisory Group on Friday, confirming what staffs have been warning stakeholders in recent months. (See Search for Small SPP-MISO Interregional Projects May be Fruitless.)

He declined to go into detail, saying he is saving that discussion for when the RTOs’ staffs present a “full” presentation to stakeholders during a virtual Interregional Planning Stakeholder Advisory Committee meeting Wednesday.

Robertson said no project met the RTOs’ criteria for qualifying as targeted market efficiency projects (TMEPs), a construct MISO and PJM use on their seam.

“We just wanted to go ahead and give that brief preview that we have not identified any good project candidates that we can recommend to the MISO or SPP board for approval,” he said.

The Joint Targeted Interconnection Queue study screened for possible TMEPs when market-to-market flowgates amassed $1 million or more in congestion costs over a two-year period. The RTOs catalogued seven permanent flowgates that met that criteria but failed others. (See MISO, SPP Identify Hotspots for Smaller Interregional Tx Projects and MISO, SPP Hunt for Small Interregional Tx Projects.)

Missouri PSC Grants CCN for NextEra Project

The Missouri Public Service Commission on Friday approved an agreement with parties involved in NextEra Energy Transmission (NEET) Southwest’s effort to secure a certificate of convenience and necessity to build part of an SPP competitive project (EA-2022-0234).

The PSC agreed with staff’s recommendations that the CCN be approved with certain conditions:

  • there’s a need for the transmission service;
  • NEET is qualified and has the financial ability to provide the proposed service;
  • NEET’s proposal is economically feasible; and
  • the service promotes the public interest.

The CCN is for a 9-mile segment of the 94-mile, single-circuit 345-kV transmission line between Associated Electric Cooperative Inc.’s Blackberry substation in Missouri and Every Kansas Central’s Wolf Creek substation in Kansas.

SPP granted the competitive project, its fourth, to NEET Southwest last year. The NextEra Energy (NYSE:NEE) subsidiary estimated the project will cost $85.2 million and be completed in 2025. (See “Expert Panel Awards Competitive Project to NextEra Energy Transmission,” SPP Board of Directors/Members Committee Briefs: Oct. 26, 2021.)

Kansas regulators awarded NEET a CCN for its state’s portion of the project in August. (See Kansas Regulators Approve CCN for Competitive Project.)

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MISO Board Week Briefs: Dec. 6-8, 2022

Market Platform Replacement to Spill over into 2025

ORLANDO, Fla. — MISO Chief Digital Officer Todd Ramey brought “good news and bad news” to Board Week about the ongoing effort to replace the RTO’s market platform.

Ramey said during a Dec. 6 Technology Committee meeting that while MISO can speed up the delivery of two real-time market applications, the overall work will likely stretch into 2025. Staff previously had ambitions to wrap up the project by the end of 2024, though it frequently cautioned that the timeline could run longer.

MISO will push approving factory acceptance testing and a vendor’s delivery of the day-ahead market-clearing engine into January, Ramey said. He said while staff could likely meet the original end-of-the-year target with long nights, overworking employees wasn’t the answer.

However, the grid operator will meet a Dec. 31 deadline to finish testing and begin parallel operations of its new energy management system. Staff will use the EMS to monitor and analyze the bulk electric system and fulfill MISO’s responsibilities to NERC as a reliability coordinator and balancing authority.

The RTO will launch its new day-ahead market next year and continue migrating data to its one-stop model manager.

MISO has said its “vision to retain one system of record for all models” requires members to review and reconcile discrepancies between data in the new model management system and its existing modeling outlets. It said it has been reaching out to members with discrepancies.

MISO Board Week at the Ritz Carlton Orlando (RTO insider LLC) Content.jpgMISO Board Week was held at the Ritz-Carlton’s Orlando Grande Lakes | © RTO Insider LLC

 

The RTO previously said it has some differences in data between lower voltage transmission representation, generation representations with a common connection point, common load representation, and accurate ownership designation of individual equipment.

Ramey said MISO should be able to quickly introduce a reliability assessment commitment tool and a future-looking commitment tool in 2023 and 2024, respectively.

Director Theresa Wise said the developments were “exciting progress.”

MISO will have to hike the project’s budget because of inflationary pressures and the nation’s tight labor market. The grid operator began the market platform project with a $130 million budget and a $30 million contingency; Ramey said it appears staff will use half of the contingency to finish the project.

Wise said the budget increase is “not a source of angst” because budget overruns are commonly impacting industries today.

The Technology Committee covered preventative cybersecurity and disaster recovery in a closed session.

Members Change Advisory Committee’s Leadership

Indiana Utility Regulatory Commissioner Sarah Freeman will chair the Advisory Committee when Manitoba Hydro’s Audrey Penner steps down at the end of the year.

Penner has served as the AC’s chair since 2015. MISO’s stakeholder relations group announced the transition during a committee meeting Wednesday.

Freeman said during a September Organization of MISO States’ meeting that she is interested in “growing the relationship between stakeholder sectors and the MISO Board of Directors.”

For two years, some stakeholders have pressed for less stage-managed interaction and more organic access to the board. (See MISO Members Request More Access to Directors.)

Michigan Public Service Commission Chair Dan Scripps said it makes sense for a member of MISO’s state regulatory sector to lead the AC in balancing “competing interests for the public benefit.” He said regulatory staff or Manitoba Hydro, the only coordinating sector member, seem best suited for the job.

MISO Welcomes 2 New Members

The board approved Missouri Joint Municipal Electric Utility Commission (MJMEUC) and Rainbow Energy Center’s membership applications.

The commission, a municipal joint-action energy agency, joins as a transmission owner. Rainbow Energy recently purchased the 1,150-MW Coal Creek Station in North Dakota from Great River Energy. Coal Creek delivers power to the Minneapolis area, and Rainbow is exploring fitting the plant with carbon-capture equipment.

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Lewis Upsets Boissiere for Seat on La. PSC

Davante Lewis, a progressive advocate for clean energy, unseated three-term incumbent Louisiana Public Service Commissioner Lambert Boissiere III on Saturday in a runoff election for a seat on the five-person commission.

Lewis won 59% of the votes from 738 of the PSC District 3’s 748 precincts, which stretch from Baton Rouge to New Orleans. He had 18% of the vote in last month’s primary, the highest among Boissiere’s four challengers; two of those later endorsed Lewis.

The 30-year-old Lewis is currently director of public affairs for the Louisiana Budget Project, which monitors and reports on public policy and how it affects Louisiana’s low- to moderate-income families. He ran on a platform of reaching 100% renewable electricity by 2035, hardening the grid against increasingly severe hurricanes, cracking down on excessive fees by utilities and instituting a Ratepayers’ Bill of Rights.

As an incumbent, Boissiere was saddled with an environment in which customer bills were rising after last year’s hurricane season left millions without power, some for weeks.

“Tonight, we have begun a new chapter for Louisiana,” Lewis told his supporters Saturday night at a Baton Rouge pub. “Tonight, the people of Louisiana start taking our power back. Tonight, Louisiana has a public service commissioner who’s unafraid to hold Entergy accountable, because I owe this victory to the people of Louisiana and their commitment to a brighter, cleaner and 100% renewable future.”

Lewis was supported by contributions from environmental groups, including a super PAC aligned with the Environmental Defense Fund that raised about $1.1 million after getting involved in the race during the primary. Boissiere, who was first elected to a six-year term on the PSC in 2004, drew support from utilities and lobbyists, Gov. John Bel Edwards (D) and U.S. Rep. Troy Carter (D), whose district encompasses much of the commission’s District 3.

Lewis and Boissiere are both Democrats; Republicans will hold a 3-2 edge on the commission.

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Western RA Program Secures First ‘Binding’ Phase Participants

Nearly a dozen utilities have committed to joining the “binding” iteration of the Western Resource Adequacy Program (WRAP), with more expected to sign on later this month, the program’s operator said last week.

The commitments by 11 participants, most of which are located in the Northwest, signal a show of confidence in the program, which was conceived to ensure that the Western Interconnection has sufficient capacity on hand to meet growing loads in both summer and winter. Concerns about resource adequacy have dogged the West as state greenhouse gas-reduction policies force early retirement of fossil fuel generation alongside an increasing reliance on variable renewable generation.

Administered by the Western Power Pool (WPP), the WRAP is currently operating in a “nonbinding” fashion in which participants are not penalized for falling short of their reserve requirements. Contingent on FERC’s approval of its tariff, the program in 2024 will enter a binding phase that will levy penalties for shortfalls.

“The critical next steps for the WRAP are securing the needed commitments from our participants and FERC approval of the tariff,” WPP CEO Sarah Edmonds said in a release Thursday. “The commitment of these 11 organizations puts us well on our way to accomplishing one of those steps. Addressing resource adequacy must be a regionwide collaboration, and we commend these first partners for their leadership and thank them for setting the tone for what’s to come.”

The utilities and power providers making commitments include Avista Utilities (NYSE:AVA), Calpine Energy Solutions, Chelan County Public Utility District, Clatskanie People’s Utility District, Eugene Water & Electric Board, PacifiCorp (NYSE:BRK.A), Portland General Electric (PGE), Powerex, Puget Sound Energy, Seattle City Light and Tacoma Power.

The 11 are among the 26 entities currently participating in the WRAP’s nonbinding phase, which also includes utilities from Northern California and the Southwest.

In a release PacifiCorp issued Thursday announcing its intention to join both the proposed extended day-ahead market (EDAM) of CAISO’s Western Energy Imbalance Market (WEIM) and the WRAP, the utility said it has “worked extensively” with the WPP and other prospective participants in developing the WRAP, “which is expected to provide regionwide reliability benefits to it participants by pairing regional diversity with common resource adequacy standards.”

“EDAM, WEIM and WRAP will work together to ensure the benefits and certainty needed to meet our customers’ growing demands for a reliable and clean grid,” said Stefan Bird, CEO of Pacific Power, a PacifiCorp subsidiary. “We are extremely excited to work with our partners to move the region forward into greater collaboration and secure even more benefits for customers.”

“Maintaining reliability is critical as we move forward with advancing decarbonization, and the WRAP would allow us to do this in a way that is most beneficial to our customers and manage costs,” PGE CEO Maria Pope said in a statement. “The WRAP will allow us to pool resources and share in the diversity of the region.”

The WPP filed its proposed WRAP tariff with FERC in August, hoping to win approval from the commission by the end of the year. Last month, FERC issued WPP a deficiency letter asking for more information about the program, including details about participation by members without market-based rate authority and WPP’s intention to hire an “independent evaluator to provide an independent assessment of WRAP’s performance.” (See FERC IDs Deficiencies in Western RA Program.)

Edmonds said at the time that the WPP knew such a development was possible and that she was confident the WRAP proposal will “ultimately gain approval.”

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MISO Members Say Speed Necessary to ‘Mind the Gap’

ORLANDO, Fla. — MISO members agreed that the future generation mix is arriving faster than previously thought during a “mind the gap” discussion last week.

The grid operator is particularly concerned about reliably navigating the resource transition’s next five years in what it has termed “mind the gap.” It foresees the potential for capacity deficits through 2027.

Jennifer Curran, senior vice president of planning and operations, told the Advisory Committee Wednesday that demand for sustainability means that the footprint is losing controllable thermal generation and trending toward variable intermittent resources. She said MISO could face severe reliability consequences if it doesn’t “close the gap well” and should not waste time in making decisions.

“I think it is happening a little faster than people thought it would happen,” said Constellation Energy’s John Orr, of the power marketers sector.  

Alliant Energy’s Mitch Myhre, representing transmission-dependent utilities, said the RTO’s viewpoint might be too pessimistic. He said MISO shouldn’t presuppose its access to flexible resources is completely drying up.

“I don’t think we should assume that technology isn’t going to evolve,” he said.

Myhre said staff should begin studying different power flows where resources are closer to their loads.

Michigan Public Service Commission Chair Dan Scripps said MISO doesn’t have a clear picture of how large its supply shortage might be because its resource accreditation is currently in flux.

Scripps suggested the grid operator’s messaging could be more optimistic. He said though MISO is currently on the “wrong side” of the one-day-in-10-years reliability standard, it doesn’t mean that it will be MISO’s fate throughout the transition.

“We need to make sure that we’re instilling a sense of confidence as we go forward and not an air of fear,” Myhre said in agreement.

The Union of Concerned Scientists’ Sam Gomberg said MISO sometimes “circles the wagons around the status quo,” pointing to demand management and its proposed 2030 adoption date to comply with FERC’s order to allow distributed energy resource aggregators into the wholesale energy markets. (See MISO Defends 2030 Completion for DER Market Participation.)

Illinois Commerce Commission Chair Carrie Zalewski said the RTO and state regulators should ensure that barriers are knocked down for DER aggregation and other new technologies.

North Dakota Public Service Commission Chair Julie Fedorchak added that the grid operator can only move as fast as the commercialization of new technology allows. She also warned MISO and members that “hope is not a strategy.”

Michelle Bloodworth, CEO of coal lobbying group America’s Power, asked staff to expedite their work on defining and requiring certain generation attributes. They have already identified six reliability attributes as necessary: availability, the ability to deliver long-duration energy at a high output, rapid start-up times, providing voltage stability, ramp-up capability, and fuel assurance. (See MISO Considers Resource Attributes as Thermal Output Falls.)

Bloodworth said those attributes and accredited capacity are being whittled away through resource retirements.

MISO has committed to reserving a full day and a half for its Resource Adequacy Subcommittee (RASC) meetings in 2023. The subcommittee works on resource adequacy initiatives, including availability-based resource accreditations, overseeing the move to seasonal capacity auctions, transitioning to a sloped demand curve in capacity auctions, and defining necessary resource attributes.

Some members debated whether MISO should spend $20-$30 billion in the second iteration of its long-term transmission portfolios to interconnect new generation. They said consumers have a limit to how much they’re willing to foot the bill for expensive, 50-year infrastructure.

“There will be a limit on what ratepayers are willing to pay, point blank,” said Clean Grid Alliance’s Beth Soholt, with the environmental sector.

Soholt said consumer advocates are getting more involved in putting up resistance to new rate cases, especially as utilities increasingly ask for double-digit hikes.

Multiple stakeholders said MISO should put more emphasis on its electrification load forecasting to ensure it’s not over- or under-building the system as the fleet transition plays out.

Scripps said MISO will undoubtedly shift away from the flat load growth of the last decade that was “exacerbated by the weirdness of [COVID-19].” He said staff should get load forecasting “as right as they can,” but added that the grid operator will never have perfect forecasting.

“You’re never going to get the load number right. You’re going to get it close,” Orr said. He said there’s a price for a one-in-10 standard versus a “one-in-never standard.” He said members should “educate the public on what they’ve bought, as what they want, and tell them the price of that.”

“We’re in a probabilistic business,” Orr said. “Not an absolute business.”

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SPP Board of Directors Briefs: Dec. 6, 2022

Staff Finalizing Mitigation Strategy for PRM-deficient LREs

SPP staff last week said they are finalizing a mitigation strategy for load-responsible entities unable to meet the grid operator’s new 15% planning reserve margin and developing several concepts that would make failure to meet the requirements “less costly or less punitive.”

Lanny Nickell (SPP) Content.jpgSPP COO Lanny Nickell | SPP

COO Lanny Nickell told the Board of Directors during its Dec. 6 meeting that the concepts include reducing the deficiency payment charge, extending the timeline to cure deficiencies and adding mechanisms to assure capacity.

Staff have been working on the mitigation strategy at the board’s direction since July. It became necessary when the board increased the planning reserve margin from 12% to 15%, effective next year, which left some members complaining they wouldn’t have enough time to meet the requirements. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

“We’re not looking to add that to the tariff on a long-term and permanent basis, but it would give some instant and interim relief,” Nickell said.

He said reducing the deficiency payment would reflect excess capacity’s value when a payment is required after a sudden increase in the PRM requirement. Nickell said the mechanism would incent long-term capacity planning and assess deficiency payments based on multiples of the cost of new entry to LREs that have not met the PRM.

The concept doesn’t relieve LREs of their obligation to comply with their resource adequacy requirements. However, it is applicable to deficient LREs for two years after the PRM change.

SPP is also proposing giving LREs more time to assess and cure their resource adequacy positions and better facilitate submissions on a virtual bulletin board to buy or sell power.

A 12-member strike team of directors, regulators and stakeholders has been meeting weekly since October to vet staff’s work. “We appreciate the fact that they were willing to help and willing to advise staff as we developed our further efforts on a mitigation strategy,” Nickell said.

The 22-person Members Committee unanimously approved staff’s concepts, with one abstention, with its advisory vote.

Staff plan to seek approval this week from the Regional State Committee of the mitigation effort’s applicable concepts. The board in October gave the committee, which comprises state regulators, the OK to file a tariff change with FERC that details how LREs can qualify for and receive exemptions from deficiency payments. (See SPP Board Bypasses Stakeholders on PRM Obligation Exemptions.)

SPP plans to file the tariff revision on behalf of the RSC this week. At the same time, it will draft a revision request for the mitigation concepts and bring that to the board and RSC in January.

Myers, Lang to Lead MOPC

The directors spent the bulk of last week’s meeting reviewing stakeholder evaluations of the board and organizational effectiveness, a stakeholder satisfaction survey, and SPP’s key performance metrics.

They also approved the consent agenda, which included several Corporate Governance Committee recommendations for the Markets and Operations Policy Committee’s leadership and other organizational groups.

As is SPP’s practice, Vice Chair Alan Myers, of ITC Great Plains, assumed the chairmanship previously held by Evergy’s Denise Buffington. The CGC recommended Omaha Public Power District’s Joe Lang as the new vice chair; both will begin their two-year terms on Jan. 1.

Buffington will fill a transmission-owning member’s vacancy on the Strategic Planning Committee. The term expires Dec. 31, 2023.

The CGC also put forward several nominations to serve two-year terms as organizational group chairs:

  • John Turner, Western Farmers Electric Cooperative, Modeling Development Working Group.
  • Tess Venetz, Xcel Energy, Settlements User Forum.
  • Calvin Daniels, Western Farmers Electric Cooperative, Economic Studies Working Group.
  • Derek Stafford, Grand River Dam Authority, Operations Training User Forum.
  • Jodi Hall, Evergy, Change User Forum.