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September 28, 2024

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FERC Considers Interregional Transfer Requirements

FERC commissioners and stakeholders offered their views on requiring minimum interregional transfer capabilities in a workshop last week that examined the contentious issue (AD23-3).

Winter Storm Uri lent new urgency to the conversation, commissioners said. The February 2021 storm blacked out much of ERCOT and resulted in the death of more than 200 Texans, showing the dangers of having too few transmission connections to support grid reliability in a crisis.

ERCOT has only 820 MW of transfer capacity with its neighbor SPP, and 436 MW of connections to Mexico, primarily for emergencies.

“We’ve been talking a lot about interregional transmission and interregional transfer capability. There’s an enormous reliability value,” FERC Commissioner Allison Clements said in the workshop’s first session Monday.

Clements cited several recent reports, including last year’s North American Renewable Integration Study (NARIS) by the National Renewable Energy Laboratory, that found interregional transmission expansion could generate up to $180 billion in net benefits through 2050.

A report released in August by researchers at the Lawrence Berkeley National Laboratory, and discussed by its lead author at the FERC workshop, found that 50% of transmission congestion value comes from 5% of hours, with “extreme conditions and high-value periods play[ing] an outsized role,” Clements noted.

And a Grid Strategies study published in February “found that each additional gigawatt of transmission ties between the Texas power grid and the Southeastern U.S. could have saved nearly a billion dollars for every additional gigawatt while keeping the heat on for hundreds of thousands of Texans” during Winter Storm Uri, she said.

“I’ve heard support from a very broad range of stakeholders for a minimum interregional transfer requirement, including the majority of participants in our FERC-NARUC-state task force,” she said, referring to the Joint Federal-State Task Force on Electric Transmission. (See States Back FERC Interregional Transfer Requirement.)

“Part of the appeal of a minimum transfer capability requirement, in addition to its specific reliability benefits, is that it could prove to be a mechanism for aligning regions around a clear goal, and then for unifying processes to reach that goal … so on the merits, specifically and more broadly, I’m a fan of this concept,” Clements said. “Of course, it raises real questions.”

For instance, she asked, what legal basis does FERC have for requiring minimum interregional transfers? And, “assuming that basis exists, how should the minimum be set between regions?”

PJM transferred electricity to MISO and MISO to SPP during Winter Storm Uri, limiting blackouts in MISO and SPP, Commissioner Mark Christie said.

“Those transfers were essential to keeping the lights on during that extreme weather event,” Christie said. ERCOT, which has sparse transmission connections with other grids to avoid FERC oversight, suffered the most.  

“We have interregional transfer capacity,” between regions such as PJM, MISO and SPP, Christie said. “The question is, is it enough? That’s the big question, and how can we get to that number of ‘what is enough?’”

Commissioner Willie Phillips said that in the months since FERC issued its Notice of Proposed Rulemaking on long-range transmission planning in April, “I have called for looking into whether the commission should require a minimum amount of interregional transfer capability.

“Interregional transmission picks from all of our big priorities,” Phillips said. “No. 1, reliability and resilience, because it strengthens the voltage and minimizes the likelihood of load shed. No. 2, affordability, because it allows ratepayers to access lower cost generation. And No. 3, sustainability, because it accommodates the demand for more clean energy.”

Many states and stakeholders have asked FERC to act on establishing interregional transfer requirements as they face the likelihood of more extreme weather events, he said.

Commissioner James Danly, who has expressed skepticism about FERC’s ability to impose transfer minimums, and Chairman Richard Glick, who has been supportive of the concept, did not attend Monday’s session.

Stakeholders Comment

Stakeholders took different positions on interregional transfers based largely on whether minimum requirements would benefit their regions or prove unnecessary and costly.

Neil Millar, CAISO’s vice president of transmission planning and infrastructure development, said the ISO depends on interregional transfers and sees the need for more transmission but believes its own transmission planning processes, including enhancements underway, will ensure CAISO has sufficient import capacity.

“Given our particular set of needs, the processes we have, as well as the issues that we’re trying to address by improving some of those processes, I’m afraid we’re not seeing a specific minimum interregional transmission capacity necessarily helping that conversation,” Millar said. “We would be prepared to put more emphasis on the existing processes and addressing the challenges within those processes.”

Georgia and other non-RTO states in the Southeast do not need FERC to impose a minimum interregional transfer capability, said Tricia Pridemore, chair of the state’s Public Service Commission.

“Georgia is an example to follow, not replace,” Pridemore said.  

“Existing state and FERC processes and rules have already been established, and they work,” she said. “The Federal Power Act expressly reserves [integrated resource planning] to the states, including transmission. In Georgia, we have a robust IRP process driven by short- and long-term planning research, hearings and commission-driven decisions.”

Before transmission plans go before the PSC, the Georgia Integrated Transmission System (GITS) develops proposals and works through potential conflicts, keeping “nasty cost-allocation, load-balancing and citing disagreements at bay,” she said.

GITS includes investor-owned utility Georgia Power; the Municipal Electric Authority of Georgia, the system operator for 41 electric co-ops; and Dalton Utilities, the “action agency” for the state’s 49 municipal utilities, Pridemore said. The entities also are active in the Southeastern Regional Transmission Planning (SERTP) process, which provides intra- and interstate collaboration, she said.

“Our bottom-up approach maintains reliability and does not put upward pressure on rates by constructing unnecessary or duplicative transmission assets,” Pridemore said. “This level of collaboration is a hallmark of Southeastern utilities.

“Georgia is better for maintaining a safe, reliable, affordable system all while not being told to do so from a top-down governance structure,” she said. “A minimum [interregional transfer] requirement may be right for an RTO state, but the processes, rules and collaboration I’ve outlined demonstrate there isn’t a need in a non-RTO state such as Georgia.”  

Liza Reed, research manager for electricity transmission at the Niskanen Center, said the Southeast and other regions remain vulnerable to crises because of their limited transfer capacity with neighbors.

The Washington D.C.-based “open society” think tank conducted a study that found most neighboring transmission planning regions in the U.S. have less than 5 GW of transfer capacity and some less than 1 GW, Reed said.

“These small values represent less than 10% and often less than 5% of the peak load in each region,” she said.   

Transfer capacity is 1% to 3% of peak load between SPP and ERCOT, PJM and NYISO, WestConnect and SPP, and between the non-RTO Southeast, including Florida, and adjoining regions, the study found.

Reed said that 15% is a “pretty standard resource planning margin” and recommended that 15% of peak load be used as a “starting level” for transfers between transmission planning regions.

“There’s ample evidence from the last few years alone that interregional transfer keeps the lights on and saves lives,” she said. “I encourage the commission to consider ways in which ERCOT can be consulted and involved in a minimum transfer requirement that does not leave the good people of Texas out in the cold again.”

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FERC Rejects PJM Intelligent Reserve Deployment Proposal for Second Time

FERC has once again rejected PJM’s proposal to shift from its current “all call” method of responding to synchronized reserve events with an Intelligent Reserve Deployment (IRD) methodology (ER22-1200).

In its request for rehearing of an August order ruling against the proposal, PJM argued that the commission had misapplied Section 205 of the Federal Power Act (FPA), which allows approval of a proposal based on whether it is just and reasonable, rather than whether “that proposal is more or less reasonable than alternative approaches.” PJM contended the commission’s ruling required “a standard of perfection for forecasted information that is simply not attainable.” (See FERC Rejects PJM’s Reserve Deployment Proposal)

“By effectively retaining the status quo, which no party supported, and basing its decision on the Market Monitor’s proposed alternatives, the commission departed from its usual Section 205 standard of review. Such action, selectively applied in this case, is arbitrary and capricious and does not exhibit application of precedent and reasoned decision-making,” PJM’s request for rehearing states.

The rehearing request was automatically denied after FERC declined to act on it within 30 days. In its Dec. 5 order addressing PJM’s arguments, the commission said its August ruling judged PJM’s IRD proposal on its own merits and noted that it did not require the RTO to accede to any alternatives put before FERC by other parties.

“By the same token, because the only proposal before the commission under FPA Section 205 was the IRD proposal itself, which the commission evaluated on its own merits, pointing out purported shortcomings in the existing all-call approach did not cure the deficiencies in the IRD proposal that rendered it unjust and unreasonable,” the order states.

The core of the proposal would be a real-time security-constrained economic dispatch simulation to evaluate the impact of the loss of the largest generation unit on the grid during a synchronized reserve event. The current procedure is to issue an “all call” message to market participants to have them deploy their full resources.

PJM said the current approach misaligns pricing and dispatch instructions, is imprecise and results in periods of under- and over-response.

The commission’s order argued that the IRD construct would not model “actual system conditions” because it assumes the largest generation contingency has occurred at the onset of each synchronized reserve event “notwithstanding the undisputed record that this will be untrue in the majority of cases.” Instead, most emergencies would be smaller in scale and would not require the deployment of reserves on the magnitude of the largest online generator.

Commissioners were also unconvinced that the proposal would not, as PJM claimed, result in artificially inflated prices and said the RTO did not identify any reliability concerns to justify moving away from current practice. 

Commissioner James Danly echoed his dissent against the August order, saying that the IRD proposal sought to “institute a coherent plan to address dispatch and pricing issues arising from reserve deployments during system emergencies.” He also wrote that FPA Section 205 grants utilities significant discretion, which he was satisfied that PJM’s proposal met.

In his original dissent, Danly said reserve shortages indicate that the system is “dangerously exposed to a subsequent reliability event.”

“I do not see how modeling the single largest reliability contingency during a reserve shortage ‘artificially inflate[s] prices,’” he said.

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Who Will Control the Political Narrative on IRA Implementation?

WASHINGTON — Implementation of the Inflation Reduction Act, and its $369 billion in clean energy funding, will be a major focus for Democrats and Republicans in the upcoming Congress, and both parties were present and rehearsing their talking points at the American Council for an Energy-Efficient Economy’s Energy Efficiency Policy Forum on Thursday.

Delivering the programs to be funded with IRA dollars was the central theme for White House National Climate Adviser Ali Zaidi, who called on conference attendees “to recognize the sense of urgency that is in front of us” to curb greenhouse gas emissions and the impacts of climate change.

“This is the decisive decade, and that means delivery,” Zaidi said in his opening keynote. “That means steel in the ground; it means retrofits made, not just anticipated and planned.”

Echoing President Biden’s midterm stump speeches, Zaidi also framed clean energy as an opportunity to create jobs and cut families’ utility bills. The IRA is “about meeting the American people where they are, which is a sense of anxiety and angst about what the future brings in terms of energy costs and helping put them in control of their energy futures by [providing] access and affordability to technologies that help them bend the curve on their personal family energy budget and reroute those dollars to things they probably want to spend money on: their kids; their futures,” he said.

The convergence of energy efficiency and electrification will be a key driver for IRA implementation, the law’s “moonshot,” Zaidi said, and accountability and corporate and community engagement will be critical because “we just can’t afford to screw up.”

On the Republican side, the political narrative will focus on whether the Department of Energy, EPA and other federal agencies are up to the task of rolling out the billions of dollars in incentives and tax credits in the IRA and Infrastructure Investment and Jobs Act (IIJA). With the House of Representatives in Republican control, “the waste, fraud and abuse angle, I think, it’s going to be really important,” said Mary Martin, chief counsel for the House Energy and Commerce Committee and its incoming chair, Rep. Cathy McMorris Rodgers (R-Wash.).

“These are historic amounts of dollars,” Martin said during an afternoon session previewing the upcoming Congress. “So that’s why there are heightened senses of concern in terms of keeping track of the dollars [and] figuring out where they are going. These departments and agencies have never had to handle that level of money before, and some of them don’t have the experience with giving out the grants that they’re going to have to give out. …

“I mean, some of these are four times the annual budget of these departments and agencies, so it’s a huge amount of money for any entity to have to deal with and take in and spend and do so in a wise and above-board manner,” she said.

Energy security and diversity are high priorities for McMorris Rodgers and other Republicans, who will be scrutinizing implementation of the IRA, Martin said. They will have “an eye towards making sure that, to the extent possible, this stuff is tech-neutral, fuel-neutral, so we’re not sort of putting all our eggs in one basket with the dollars,” she said.

The China Card

An outspoken critic of Biden’s clean energy policies, McMorris Rogers will likely also continue to raise concerns about the U.S. solar, battery and electric vehicle industries’ dependence on Chinese supply chains. While acknowledging the IRA’s tax credits and subsidies that promote U.S. clean energy manufacturing, Martin said Republicans will be “looking for ways to potentially improve upon some of those things … again looking at China and trying to control the influence of the CCP [Chinese Communist Party] in our energy and transportation systems.”

Underlining a strong GOP focus on China, House Minority Leader Kevin McCarthy (R-Calif.), the Republican nominee to be speaker of the House, announced Thursday the formation of a new China Select Committee, calling the CCP “the greatest geopolitical threat of our lifetime.”

While not officially announced, Republicans have also signaled that they will close down the House Select Committee on the Climate Crisis, chaired by Rep. Kathy Castor (D-Fla.).

As reported in The Hill, following the midterm elections, Rep. Garret Graves (R-La.), ranking member of the committee, said, “We don’t see a scenario where the ‘Climate Crisis Committee,’ a creature of [House Speaker Nancy] Pelosi, will continue to exist.”

While such comments suggest that implementation of the IIJA and IRA will become increasingly politicized, Rick Kessler, senior adviser and staff director for Democrats on the E&C Committee, cautioned that however carefully federal programs are designed, “fraud and abuse do happen.”

“All you can do is do your best to prevent it,” Kessler said. “Hire the best people, and if it happens, go back and say, ‘How did this happen? What can we learn?’ — and try to implement that.”

Rick Kessler Mary Martin 2022-12-08 (RTO Insider LLC) Alt FI.jpgAt the ACEEE Policy Forum, Rick Kessler, Democratic senior adviser for the House E&C Committee (left), and Mary Martin, Republican chief counsel for the committee, preview the upcoming Congress with the GOP in control of the House of Representatives. | © RTO Insider LLC

Zaidi also stressed the need for Democrats to keep the narrative positive and focused on action.

“The same folks who invested in climate denial, in climate delay, are investing in fomenting a sense of cynicism, that no matter what you do, these problems are incorrigible,” he said. They say, “‘we can’t tackle this mega challenge that’s on our doorstep; we can’t take on energy security in a bold way; we can’t lift up everybody as we do.’

“They’re wrong,” he said. “And we’ve got to prove that by delivering results in this decisive decade.”

Permitting Reform

With Congress focused on passing a budget and legislation with strong bipartisan support during its lame-duck session, potential areas for cross-party collaboration on energy issues appear limited.

Permitting reform is certainly a common area of interest, but the sidetracking of Sen. Joe Manchin’s (D-W.Va.) proposal has created a high level of friction on the issue. On Wednesday, the Democratic leadership excluded Manchin’s bill from the must-pass National Defense Authorization Act, and Manchin has taken flak from both Republicans and environmental activists. (See related story, Manchin Presses Permitting Proposal Excluded from Defense Bill.)

In a “fireside chat” with ACEEE Executive Director Steven Nadel at the forum, Manchin said opposition to his proposal is largely personal, with Republicans still mad at him over his behind-closed-doors work on the IRA.

Manchin argued that the IRA does reflect bipartisan concerns on energy development, for both fossil fuels and renewables, and will reduce inflation by lowering gas prices, home energy prices and prescription drug prices. “It’s working, and it’s popular, and it’s going to work even more,” he said. “So, this is the payback coming directly to me.”

Environmental groups have opposed Manchin’s proposal because it includes a go-ahead for completion of the Mountain Valley natural gas pipeline, which the senator argues is needed and already 80% complete. The project website says Mountain Valley is 94% complete.

Manchin also maintained that the bill is clear on cost allocation, and that it would not have states paying for transmission lines that are built across their land but do not provide direct benefits or energy to them.

“Read it; just read the damned language!” he said. “The grid system has to be connected and energized, and we’ve got to able to [do it] and get this smarter. …

“You can’t even build what you need; you can’t even finish what you’ve got to have. I would tell the American public, if people are putting politics above policy because it’s good for the country but may be bad for your personal politics, then maybe you’re in the wrong profession.”

Responding to a question about Republicans’ views on permitting reform, Martin did not specifically mention transmission. Rather, she said, Republicans have developed an agenda for security and energy, which includes ideas on “dealing with natural gas pipeline permitting or nuclear licensing reform, hydropower licensing reform, critical minerals [and] issues at the DOE.”

But Kessler said that any effort to pass permitting reform will require getting both parties and all the stakeholders at the table.

“It will never succeed unless we are all in it together, working and listening to each other,” he said. “You can sit in a room by yourself and come up with the perfect package. But what happens is you roll that out, and no one has any vested interest in that, and other people have their idea of the perfect package. And that may be very different. … It involves inclusiveness.”

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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.