A three-judge panel of the D.C. Circuit Court of Appeals on Tuesday upheld FERC’s decision requiring Ameren Illinois to refund inappropriately recovered costs related to transmission construction.
The utility improperly included costs for construction-related supplies and materials in the same filing that was meant to recover the cost of transmission plant materials and supplies, when the construction supplies were not eligible to be recovered under the formula rates Ameren Illinois was using at the time.
“The commission found that Ameren Illinois had misreported materials and supplies costs on Form 1 and ordered Ameren Illinois to pay approximately $11.5 million in refunds to its customers, based on ten years of misreporting,” the court said (20-1277).
Ameren filed for rehearing, which was rejected by FERC (ER20-1237). The company appealed to the D.C. Circuit, which said that FERC has broad statutory authority to grant refunds.
“Upon finding that Ameren Illinois failed to correctly record certain materials and supplies costs in the annual Form 1 report, the commission reasonably determined, based on a balancing of the equities, that refunds were warranted,” the court said.
Ameren argued that FERC issued its customers a “windfall” and failed to perform a required balancing-of-equities test in granting the refund, but the court disagreed.
The utility said reporting construction-related costs in the wrong line was a common industry practice before FERC found Duke Energy Progress doing the same and put the industry on notice that it needed to stop the practice. That means it should not be bound its formula rate, Ameren said.
“No justification is offered for that position,” the court said. “The utility’s view that the misreporting was a mere technicality ignores the fact that such costs, if properly reported at line 5, could not have been passed on to customers under Ameren Illinois’s formula rate.”
Rather than giving customers a windfall, Ameren’s error resulted in a windfall for itself to the tune of $11.5 million. That amounts more than a ministerial error, the court said.
Just because FERC has not issued a refund order for every other utility that listed the construction-related costs under the wrong item does not mean the refund order to Ameren was unjust and unreasonable, the court said.
As the California Air Resources Board moves closer to adopting a regulation requiring truck fleets to transition to zero-emission vehicles, the agency is looking at how to handle situations where supporting infrastructure is not available.
The CARB board held a hearing on the regulation, known as Advanced Clean Fleets (ACF), in October. The regulation is expected to return to the board for final adoption this spring.
The proposed regulation covers three types of fleets: drayage trucks; state and local government fleets; and federal and high priority fleets, defined as fleets of 50 or more trucks or owned by a business with $50 million or more in annual revenue.
The regulation would require new trucks added to drayage and high priority fleets to be zero emission starting in January 2024. For state and local fleets, half of new trucks could be gas-powered until January 2027, at which time all fleet additions would need to be zero emission.
But CARB recognizes that some fleet operators might not be able to acquire the new ZEVs on schedule — or have infrastructure in place to charge them — due to factors beyond their control.
“If the infrastructure is not available, it doesn’t matter how many vehicles we have in our parking lot,” CARB Vice Chair Sandra Berg said during an ACF workshop this month. “Likewise, if the vehicles aren’t available, it doesn’t matter how many we can plug in at the facility.”
CARB held the workshop to discuss expanding exemptions to ACF when vehicles or infrastructure aren’t available.
In cases where a ZEV is not commercially available in the configuration needed, the draft regulation would allow a fleet operator to buy a gas-powered vehicle instead. If a ZEV is ordered a year ahead of the compliance deadline but delivery is delayed, the operator can keep using their internal combustion vehicle until the ZEV arrives.
On the infrastructure side, a compliance extension of up to two years would be offered in cases where there’s a construction delay. That might be a change in general contractor, unexpected safety issues, or a shipping delay for the zero-emission charging or fueling equipment.
The two-year extension is an increase from the previously proposed one year. The extension would be available if construction started at least a year before the compliance deadline.
Utility Delays Considered
And in a new proposal discussed during this month’s workshop, a compliance extension of up to five years could be granted if a contract has been signed with a utility to power the infrastructure, but the utility needs more time to finish the job. The provision would apply to power needed for electric charging or, in the case of hydrogen fuel cell vehicles, electrolyzers to produce the hydrogen.
Another new proposal from CARB is to post online details on granted extensions, such as the reason for the extension and its length, the city where the fleet is located, and the number of ZEVs involved.
Some workshop participants said CARB should allow compliance extensions in a wider variety of situations. One example is when infrastructure installation is delayed due to prolonged negotiations with a landlord over site improvements. Delays due to California Environmental Quality Act issues was another example.
Others said there should be no time limit on the exemptions.
“The infrastructure exemption should last as long as needed. What happens if you hardwire-in two years into the rule and it doesn’t happen?” said Jon Costantino, a consultant representing the California Council for Environmental and Economic Balance. “There needs to be an opportunity to deal with … the outliers.”
But “we can’t have an open-ended process of extensions,” Berg said.
“We have to put the marker in the sand,” she said. “It has to be clear. It has to be enforceable. And it has to have provisions for flexibility that work within the guidelines.”
Speeding the ZEV Transition
Advanced Clean Fleets is a complement to CARB’s Advanced Clean Trucks regulation, adopted in 2020, which requires manufacturers of medium- and heavy-duty trucks to sell an increasing percentage of zero-emission vehicles starting in 2024.
Several other states, including Washington, Oregon, Massachusetts, New Jersey, New York and Vermont, have adopted an Advanced Clean Trucks regulation, and other states are considering doing so.
ACF tackles the ZEV transition from a different angle, targeting truck fleets that could transition to zero-emission vehicles relatively soon, the agency said.
“The proposed ACF regulation attempts to strike a balance between moving the market quickly to ZE while recognizing fleets more suited for electrification should lead the way for smaller fleets,” CARB said in its initial statement of reasons for the rule.
The proposed ACF regulation would require all medium- and heavy-duty trucks sold in the state to be zero-emission starting in 2040, and all drayage trucks to be ZEVs by 2035.
At the Oct. 27 hearing on ACF, CARB board members asked staff to fine-tune the regulation, including changes to better address delays in availability of ZEVs or charging infrastructure.
Since then, the agency has held a series of workshops on proposed modifications. Another workshop is scheduled for Feb. 13.
CARB then plans to release a package of changes to the proposed regulation for a 15-day comment period before ACF goes to the board for final approval.
New England transmission owners have asked FERC to dismiss a RENEW Northeast complaint that seeks to shift the burden of network upgrade operations and maintenance costs off interconnection customers.
In the complaint, the renewables group argued that ISO-NE
is the only U.S. region in which interconnection customers are directly assigned costs for the capital and O&M needed for network upgrades, an “exemption” from FERC policy that RENEW said is unjust and unreasonable. (See Renewable Group Asks FERC for Interconnection Cost Changes in NE.)
In its response, ISO-NE asked to be dismissed from the complaint because the provisions under discussion are transmission rate terms under control of the transmission owners and in which the grid operator doesn’t hold any financial interest.
The transmission owners offered a more substantive answer, arguing that the complaint “fails to meet RENEW’s [Federal Power Act] Section 206 burden of proving that the tariff rate on file is unjust and unreasonable.”
The TO’s argue that generators paying for network upgrades is part of a “grand bargain” that also includes “free and unlimited open access to regional network transmission service on the ISO-NE system.”
It’s a deal that has been subject to FERC review several times and been repeatedly accepted by the commission, the TOs wrote.
They also argue that altering a single aspect of cost allocation for the region’s system could place the entire structure in “jeopardy,” which is why FERC has a “stated policy against unilateral changes to a single aspect of a comprehensive negotiated rate structure.”
Other Corners Respond
New England’s generators, unsurprisingly, backed the RENEW complaint.
The New England Power Generators Association (NEPGA) described in its commentsthe “negative impact this unlawful assignment of O&M costs has on competitive market outcomes.” NEPGA noted that market participants can’t recover the O&M costs in the capacity or energy markets.
“The shifting of costs RENEW highlights creates broad negative economic consequences both for resources that rely on markets to produce economic outcomes and those that pay for their services,” the association wrote.
Likewise, in a joint comment, the renewable and clean energy groups Advanced Energy United and the Northeast Clean Energy Council supported RENEW’s complaint, saying the direct assignment charges at issue “unduly burden interconnection customers” that are currently most heavily represented by renewable and storage developers.
“Directly assigning O&M network upgrade costs to interconnection customers clearly violates FERC’s O&M cost policy and the ‘beneficiary pays’ rule of cost allocation and should not be sustained,” the groups wrote.
Among those weighing in against the RENEW complaint were the New England states (as represented by New England States Committee on Electricity) and newly appointed Massachusetts Attorney General Andrea Campbell. Both argued that the complaint would shift costs unfairly onto ratepayers.
“RENEW seeks to replace long-settled rules that put development risks and costs on interconnection customers with a one-sided bargain that shifts 100% of those costs to consumers,” NESCOE wrote in its comment. “The commission should reject that myopic approach, as both bad policy and a matter of law.”
Campbell’s commentpointed to precedent, including past commission rulings and failure of a similar proposal in the NEPOOL process, to argue against the complaint in addition to expressing worries about the costs for consumers.
“New England ratepayers … already pay higher transmission costs than customers in any region in the United States,” the AG wrote. “To grant RENEW’s cost shifting remedy would only exacerbate New England ratepayers’ already high transmission rates.”
Staff from NERC and the Texas Reliability Entity commended ERCOT in a webinar Tuesday for its “extremely proactive approach” to mitigating the challenges exposed by the Odessa disturbances of 2021 and 2022, while reminding listeners that more work is needed across the ERO Enterprise to overcome the underlying issues.
The webinar was part of Texas RE’s monthly “Talk with Texas RE” series, in which presenters from the regional entity discuss ongoing and emerging reliability challenges in both the Texas Interconnection and the broader bulk electric system. Patrick Gravois, an electrical engineer at ERCOT, and Rich Bauer with NERC’s event analysis division joined David Penney of Texas RE in a discussion that built on the report that NERC and the RE released last year on the 2022 Odessa disturbance. (See NERC Repeats IBR Warnings After Second Odessa Event.)
The Odessa events occurred about a year apart near the town of Odessa, Texas. Both were initiated by faults at synchronous generation plants and resulted in the loss of significant amounts of solar PV and synchronous generation, with a reduction of 1,340 MW in 2021 and 2,555 MW in 2022.
In their report on the second event, NERC and Texas RE staff pointed out that most of the solar PV sites that responded abnormally in 2022 also did so in 2021. However, the cause of reduction for most of the facilities in the 2022 report was different from that recorded the previous year; many of these had implemented changes intended to prevent the causes of reduction in 2021.
The report concluded that addressing the performance issues of solar plants and other inverter-based resources is a “paramount” priority for the ERO that also requires the assistance of stakeholders including FERC, ERCOT, and electric utilities.
Gravois reviewed the risk mitigation measures that ERCOT undertook following last year’s disturbance. The first step was to convene discussions with generator owners (GO), original equipment manufacturers (OEMs) of the inverters involved in the incident, Texas RE, and NERC to investigate the root causes of the inverter tripping.
Following these meetings, the ISO ordered the affected GOs to submit mitigation plans and timelines within three weeks for correcting the identified issues. After the utilities submitted their plans, Gravois said ERCOT “followed up with them continuously … to make sure they were meeting the timeline [and] when we can expect these corrective actions to be implemented.”
Although the utilities have only had “the better part of fall 2022” to put their mitigation plans in place, Gravois said they are “getting really close” to completion. One of the few remaining measures needed on a widespread basis is a firmware update to inverters manufactured by Toshiba Mitsubishi-Electric Industrial Systems to address the DC voltage imbalance observed at three facilities.
“They had this ready to go at the time of the Odessa 2022 event, they just hadn’t implemented it yet,” Gravois said. “So they … will be implementing this in the rest of the facilities with these inverters throughout Texas as well, [and] ERCOT’s going to be reaching out to these facilities as well to make sure they’re working … to get this implemented.”
Further activities planned by ERCOT for 2023 include requesting GOs of affected facilities to update and resubmit their dynamic models to verify that they match the equipment’s field settings. The ISO also plans to contact all facilities, whether “operational or in the commissioning phase … to make sure they’re also proactively implementing all these corrective actions we’ve identified so they don’t trip off for future events.”
ERCOT’s longer-term goals include improving the interconnection process to check for known issues during commissioning and developing automated tools to look for small trips that might be signs of larger developing issues. Gravois said there also “really needs [to be] some discussion within ERCOT to look into running some kind of systemwide validation” to make sure GOs’ updated models are accurate.
The proposed Beacon Wind I project drew unanimous public support Tuesday during public hearings on the transmission line needed for the 1,230-MW wind farm planned off the New York coast.
The New York Public Service Commission held virtual comment sessions as part of its review process for the certificate of environmental compatibility and public need the developers must secure.
Many other state and federal approvals are needed before Equinor and BP can begin construction in 2025 in a 128,000-acre tract of ocean 60 miles east of the southeastern tip of Long Island.
Tuesday’s hearings officially centered on the 115-mile underwater export cable running the length of Long Island Sound, plus a short overland cable and substation where it will make landfall in Astoria, Queens, in the northwestern corner of Long Island.
But everyone who spoke — activists, residents with no stated affiliation, business owners, and elected, union and neighborhood leaders — was in favor not just of permitting the cable but the entire project, and offshore wind in general.
The written comments submitted to the PSC were similarly supportive.
The level of public support for zero-emission wind power in and near the Astoria neighborhood is not surprising; the area has been dubbed Asthma Alley for its concentration of fossil fuel power facilities, past and present.
A subsidiary of NRG Energy (NYSE:NRG) had initially proposed to refurbish the Astoria Generating Station, a 558-MW peaker plant, prompting vigorous protests from neighborhood and climate activists.
The state Department of Environmental Conservation rejected a plan to install a new 437-MW turbine generator on-site, saying it would not meet the emissions limits set in the Climate Leadership and Community Protection Act.
So instead, Astoria Gas Turbine Power opted to sell the site to Beacon Wind Land and demolish the power station.
Equinor told RTO Insider via email Tuesday that the purchase of part of the complex is complete, and the developers would share more of their plans for the site in coming weeks.
Among the speakers Tuesday:
Casey Petrashek of the New York League of Conservation Voters said: “Beacon Wind I will bring significant environmental and economic benefits to New Yorkers.”
Kayli Kunkel, founder of the Earth and Me ecologically themed stores in Queens, said: “Clean, renewable energy and air and water quality are rights that we deserve as New Yorkers, and considering the diverse makeup of our borough, this is also an environmental and racial justice issue.”
Edwin Hill Jr., of the International Brotherhood of Electrical Workers, said the union appreciates Equinor’s commitment to organized labor on the project. “Equinor has made a significant commitment of $52 million in social investments in New York state,” he added.
Fred Zalcman, director of the New York Offshore Wind Alliance, urged the PSC to grant the certificate of compliance and need. “The Beacon Wind project is a critical component of New York’s nation-leading effort to power its economy based entirely on clean, renewable and carbon-free energy resources.”
Marc Schmied, a volunteer with 350Brooklyn.org, contrasted the impact of constructing offshore wind farms with that of continued reliance on fossil fuel. “I understand and respect the concerns of both the local residents and the commercial fishermen who will be temporarily inconvenienced by the construction of Beacon Wind’s transmission line,” he said. “Offshore wind is by far the lesser of two evils here.”
State Assemblyman Zohran Mamdani, a Democrat who represents Astoria, said: “Our neighborhood has been on the front lines of the climate crisis but also on the front lines of fighting back, and last year we successfully beat back NRG’s proposal to build a fracked gas power plant, and the approval of this permit will ensure that very same site that the plant would have been built will instead become an interconnection site.”
Richard Khuzami, representing the Old Astoria Neighborhood Association, said: “The Astoria waterfront, home to three major [public housing complexes] has long been afflicted by increased rates of asthma and other environmentally related afflictions, and this project will have a direct positive impact and improve quality of life.”
Innovation Hub
As the developers push through the regulatory process, they are also taking steps to set up a supply chain, with construction of a tower manufacturing facility on the Hudson River in upstate New York and construction/support hub on the New York City waterfront.
Equinor and several partners on Tuesday announced the opening of the Offshore Wind Innovation Hub in Brooklyn, which will help startups develop innovation in the offshore wind industry.
In a news release Tuesday, Lyndie Hice-Dunton, executive director of the National Offshore Wind Research and Development Consortium, said:
“We are delighted to be a part of this exciting partnership. The Accelerator Program is a unique opportunity to help support innovative solutions for offshore wind in the U.S., as well as help build strategic partnerships within this growing industry. We are looking forward to working with this outstanding group of leaders to achieve our mutual goal of accelerating offshore wind innovation.”
Dominion Energy is backing legislation in Virginia that critics say would limit the State Corporation Commission’s ability to set its rates, while the utility has claimed it would save consumers millions.
Senate Bill 1265 also initially included language that would have made energy shopping by large commercial and industrial customers “nearly impossible,” according to the Retail Energy Supply Association, but that was removed as it advanced through a Senate subcommittee last week.
“As Virginians face historic inflation and rising energy costs, there is broad agreement that consumers need relief on their power bills,” a Dominion spokesperson said. “The proposed legislation would provide immediate and ongoing rate relief to our customers. It would provide strong state regulatory oversight. And it supports our mission of delivering reliable, safe, affordable and clean energy to our customers.”
The bill, sponsored by Sen. Richard L. Saslaw (D), cleared the Energy Subcommittee by a 4-1 vote, and it still must clear the full Commerce and Labor Committee before it can be voted on by the Senate. A House version of the legislation, HB 1770, has not moved forward yet.
Ever since Virginia decided against moving forward with retail restructuring back in 2007, state law has required the SCC to set Dominion’s rates based on a group of its investor-owned peers in the Southeast.
The bill would eliminate the SCC’s ability to remove the two highest returns on equity and two lowest returns from that peer group when setting Dominion’s rates. In return for that, it would shift some costs from riders to the firm’s base rates and make it go through rate cases every two years instead of every three.
Eliminating those riders would save $300 million annually effective July 1, which would save the average customer bill about $5 to $7 per month.
While the bill removed any language dealing with electric shoppers, at a Senate Energy Subcommittee hearing last week lawmakers indicated that they want to hear from the SCC on whether shopping shifts costs to remaining customers. That is an issue in California’s capped power market, where cost shifts from customers leaving utility service are covered through a mechanism called the power charge indifference adjustment.
“Our rates have been below the national average for some time,” Dominion Senior Vice President of Corporate Affairs Bill Murray said at last week’s subcommittee hearing. “This is a way for us to keep our rates below the national average, while having the certainty we need to raise a great deal of capital to build needed infrastructure, whether its generation, transmission or grid-hardening.”
The current peer group on which Dominion’s rates are based is made up of about 10 utilities in the Southeast, and Dominion has the lowest rate of return on equity among them, Murray said. That peer group has shrunk from about 20 when the legislature first set it up 15 years ago because of industry consolidation, so removing two highest returns and two lowest has a much bigger impact on Dominion’s rates than it usSBed to.
If Dominion wanted to offer customers $300 million in savings, the firm could do so on its own without any legislation, Southern Environmental Law Center’s Will Cleveland said at the hearing.
“This legislation does not let the Virginia commission set the rate of return for the Virginia monopoly utilities — that is our concern,” Cleveland said.
Walmart lobbyist Kenneth Hutcheson told the subcommittee the retailer appreciated the removal of changes to the state’s shopping rules, but he said the peer group should be expanded to include vertically integrated utilities from the Midwest and Gulf Coast.
Attorney Will Reisinger testified at the hearing on behalf of Clean Virginia, saying it would remove the ability of the SCC to independently set Dominion’s rates.
Eventually all the investments Dominion is making, including projects to meet the goals of the Virginia Clean Economy Act such as the 2.6-GW Coastal Virginia Offshore Wind project, would be impacted by any higher rates of return Dominion is able to get under the legislation, Reisinger said in an interview.
“It’s pretty extraordinary for a monopoly utility to try to set its own rate of return via legislation,” Reisinger told RTO Insider. “This is exactly what public utility commissions were designed to do — set the utility’s ROE at the correct level.”
The Dominion-backed legislation isn’t the only bill under consideration.
Senate Bill 1321, sponsored by Sen. Jennifer McClellan (D) and Sen. Creigh Deeds (D), and House Bill 1604, sponsored by Del. R. Lee Ware (R), would allow the SCC to lower a utility’s base rates if it finds they result in “unreasonable revenues in excess of the utility’s authorized rate of return.” The bill has also been assigned to the Senate subcommittee.
Generation owners are attacking PJM’s filing asking FERC to approve a change to the parameters of the RTO’s 2024/25 capacity auction, calling it a tariff violation and an attempt to intervene on behalf of buyers.
But utilities and state advocates argue that the potential impact of the auction’s results on ratepayers justifies the action.
In two filings last month, PJM laid out how a mismatch between the resources used to calculate the reliability requirement for the DPL South (DPL-S) locational deliverability area (LDA) — centered on the Delmarva Peninsula — and those that actually participated in the auction led to a fourfold increase in clearing prices compared with the previous year’s auction (EL23-19, ER23-729).
Describing the outcome as an artificial inflation in prices, the filings asked the commission to allow PJM to revise the reliability requirement to remove those generators that did not enter the auction as an additional step in the optimization algorithm run after bids have closed. (See PJM Decides Against Posting Indicative Capacity Auction Results.)
The core argument of the generators’ protests is that PJM’s tariff requires it to close the auction and post the results as soon as possible and that the RTO lacks the authority to hold it open while making a filing with FERC.
Former FERC Chair Joseph Kelliher submitted an affidavit in support of the PJM Power Providers (P3) protest to PJM’s filing, saying that granting the RTO’s request would violate the filed rate doctrine, which prohibits the charging of rates different from those filed with FERC, and the rule against retroactive ratemaking.
In rebutting PJM’s argument that changing the auction parameters would not violate the rules because the auction has not been completed, Kelliher compared the auction results to Schrodinger’s Cat. He noted that the RTO has stated that the results are preliminary and incomplete, but relies on the figures to estimate the impact to clearing prices in DPL-S.
“[T]he auction process appears to be final, except for the ministerial step of posting the auction results that PJM apparently has in hand but refuses to formally post — are the auction results final or preliminary?” he wrote.
Kelliher also argued that granting PJM’s requests would be bad policy, undermining confidence in capacity auctions and the commission.
“The commission has consistently recognized the importance of assuring market certainty and maintaining market integrity, even to the extent of opposing the re-running [of] RTO auctions to provide refunds as remedies in FPA Section 206 complaint proceedings and in response to court remands, where [the] commission has discretion to order re-running of markets, on the grounds that doing so would ‘undermine confidence in markets,’” he said.
NRG Argues Price Jump was Predictable Months Before Auction
In its protest, NRG Energy said it had relied on the market information and price estimates based on them to make “irreversible commercial decisions.”
“In its determination to retroactively revise the auction results to avoid politically unpalatable results dictated by the rules in effect when the auction was conducted, PJM blithely ignores the substantial and actual reliance interests of the NRG Companies and other market participants and proposes to change the rules after-the-fact,” the company wrote.
It also argued that PJM should have been aware of the likelihood that the reliability requirement would lead to elevated prices in DPL-S, as the company had previously reached out to PJM to inquire about the 12% increase for the LDA. The RTO responded that historical winter forced outages and expected increase in solar resources increased the risk of loss of load in the winter, leading to the higher reliability requirement.
Based on those parameters, the company estimated that the LDA would clear at around the cap of $426.17 MW/day and instructed traders to rely on PJM’s parameters after receiving its response, leading the company to reject capacity purchase offers on the grounds that it expected higher prices.
EPSA Worries About Reliability Impacts
The Electric Power Supply Association (EPSA) noted that the reliability requirement for LDAs looks at existing resources and projected resources expected to be in service, rather than at resources with Reliability Pricing Model (RPM) commitments. For that reason, EPSA contended, revising the reliability requirement to exclude resources not offered into the Base Residual Auction (BRA) would create a “false equivalence between the reliability needs of an LDA and the supply and demand in the LDA in an RPM auction.”
Drawing on information in an affidavit by Paul Sotkiewicz, president of E-Cubed Policy Associates, EPSA argued the effect would be dramatic differences in clearing prices depending on whether resources participated in auctions, regardless of whether those resources are actually available during the delivery year.
“The prices PJM would determine might not be high enough to attract future new resources to take on an RPM commitment especially knowing PJM is willing to put its finger on the scale to reduce prices even in the face of reliability needs with its proposal,” Sotkiewicz wrote.
AMP, Public Citizen Argue PJM Doesn’t Go Far Enough
American Municipal Power argued that FERC approval of PJM’s filing is necessary to avoid ratepayers paying a “Locational Reliability Charge that is unjust, unreasonable and unduly discriminatory.” The nonprofit, whose members include the Delaware Municipal Electric Corporation, said the RTO’s solution could leave future BRAs open to similar issues and called on FERC to establish a technical conference to explore long-term solutions.
In particular, AMP argued that the small size of many LDAs within PJM can cause price volatility through changes in load forecasts, uneven growth in resource development and generators not participating in auctions.
“It is therefore critical that LDAs in PJM be sized large enough that the failure of one resource or a small set of resources to participate in RPM auctions, or the inability to site new generation, does not drastically increase the auction clearing price,” AMP wrote.
The nonprofit power supplier also questioned PJM’s proposal to trigger the process of recalculating the reliability requirement to remove resources not participating in the BRA when the parameter increases more than 1% over the previous year. It noted that a 400% increase in clearing prices could be attributed to the 12% increase in the requirement. A 1% increase in the threshold would still correspond with a 33% rise in prices should the impact prove to be linear, AMP said.
Public Citizen argued that FERC should approve PJM’s requests, establish a refund date and investigate whether market participants engaged in intentional capacity withholding. It also wrote that future BRA results should be filed as standalone Section 205 rate filings to allow for public inspection of rates with the ability for comments and protests to be submitted before rates go into effect.
“Setting the matter for hearing and subjecting the capacity auction to refunds is the statutorily appropriate path for the commission to pursue, rather than PJM’s proposed ‘do over’ which does not appear to be permitted by its tariff. Subjecting the auction results to a hearing with refund authority will protect consumers and ensure accountability for any generators that engaged in capacity withholding,” the organization wrote.
Delmarva Zone Parties, ODEC Support PJM Approach
In its comments supporting PJM’s filings, Old Dominion Electric Cooperative said that actions being proposed are justified given the “artificially increased and unreasonable clearing price” that ratepayers would pay without any added benefits from the higher costs.
“The fact that prices are being increased and LSEs (and, thereby, consumers) will pay for an inappropriately calculated Reliability Requirement is in and of itself sufficient basis for the commission to take action to prevent the imposition of unjust and unreasonable capacity prices for the DPL-S LDA. When there are no discernable benefits from increased prices, the rates cannot possibly satisfy the requirement that customers receive benefits that are at least roughly commensurate with costs,” the cooperative wrote.
Several Delaware, Maryland and Virginia public organizations also supported PJM’s filings and said whatever solution FERC may approve, priority should be given to ensure that further delays in the BRA are avoided. Jointly filed by the Delmarva Zone Parties, the comment was signed by the Delaware Public Service Commission, Delaware Division of the Public Advocate, the Delaware Municipal Electric Corporation, Maryland Public Service Commission and the Virginia State Corporation Commission.
“Avoiding further delays in the BRA timeline is particularly critical as PJM stakeholders seek to reestablish the three-year forward procurement of capacity resources that has already been delayed by various proceedings before the Commission. Instead, in an effort to minimize disruption to the BRA process, PJM proposes to prospectively include a new element to its optimization algorithm that would allow it to reflect more accurately supply and demand levels while evaluating Sell Offers before determining capacity awards,” the parties wrote.
WASHINGTON, D.C. — In 2022, sales of electric vehicles, including plug-in hybrid models, accounted for close to 6% of U.S. new car sales, according to figures from Kelly Blue Book, which means 94% of new cars hitting the road last year were running on gas-powered, internal combustion engines.
The Washington, D.C., Auto Show, now underway at the city’s Walter E. Washington Convention Center, puts these uneven statistics into perspective: The vast majority of shiny, sleek new models that automakers are promoting here are ICEs.
EVs are on the floor, but by no means the main attraction, and much confusion and uncertainty remain about how fast automakers will be able to adjust or build out their supply chains for new EV models and which EVs will and won’t meet the Inflation Reduction Act’s U.S.-made content requirements.
“I think, over time, you will actually — even in the short term — see automakers moving quite quickly to make adjustments” to their supply chains, said Michael Berube, deputy assistant secretary for sustainable transportation at the Department of Energy. “Some of the new [U.S. content] requirements phase in over time; they don’t all hit on Day One, to allow automakers time to do it.”
Berube was one of a list of government and industry officials speaking at the auto show’s Public Policy Day on Thursday, where the focus was on the apparent collision between President Joe Biden’s ambitious goals for transportation decarbonization, the complicated provisions of the IRA’s EV tax credits, and market and economic realities.
The IRA’s requirements that 40% of critical minerals in EV batteries be sourced in the U.S. or from a country with which the U.S. has a vaguely defined “free-trade agreement” have become a particular flash point for European automakers, said Stavros Lambrinidis, the European Union’s ambassador to the U.S.
The EU supports the “IRA’s ambitions,” Lambrinidis said, during a panel on U.S. competitiveness. But Europe is “very concerned with some of these provisions that discriminate against European cars and other provisions that deal with critical minerals. …
“At the end of the day, if we’re going to be reaching our climate goals, we need to have consumers being able to select the cars they prefer from all the available options among countries that compete fairly in trading,” he said. “And if we cut that off, what you have is probably cars that cost more … so we basically undermine our capacity to meet our climate goals.”
The IRA’s domestic content provisions have also become a bump in the road for consumers, who are confused about which EVs will meet the requirements and qualify for a full $7,500 credit for a new car or $4,000 credit for a used car. EVs that don’t meet the provisions could only qualify for a partial credit — $3,750 for new cars and $2,000 for used vehicles.
EV tax credits are also tied to a vehicle’s manufacturer’s suggested retail price (MSRP) and a buyer’s income level, and right now, everyone is waiting on the Internal Revenue Service, which has delayed the release of guidelines on domestic content until March. (See Treasury Delays Key Rules for IRA’s EV Tax Credits.)
A single person buying an EV can earn no more than $150,000 per year to qualify for the tax credits, and the EV they buy cannot cost more than $55,000 for a sedan or $80,000 for an SUV.
Omar Vargas, vice president and head of global public policy at General Motors, called on the IRS and other regulators implementing the EV tax credits to “think like a business and put the customer first.” Consumers are seeing conflicting information on window stickers on EVs at dealerships and information on the IRS website, Vargas said.
IRS and other regulatory guidelines should be aligned with the federally mandated information on window stickers, he said. The details there cover where the different parts of the car were manufactured and assembled and what percentage of content was sourced in the U.S. or Canada.
Alex Laska, senior policy advisor for Third Way, a “center-left” policy think tank, said the IRS will need “to strike a balance between making sure we’re respecting the letter of the law absolutely, but also making sure that implementation is done in a way that sets us up for success in the long run.”
But Berube defended the domestic content and other provisions of the EV tax credits, even if certain models may not qualify in the near-term. Looking ahead five years, he said, “We will look back at this moment and, I think, everyone will see the wisdom in the structure of that tax credit. … This isn’t a short-term move. We are fundamentally changing the entire automotive platform; powertrain is the heart and soul of the cars. That tax credit is really going to help with that longer move.”
On the Show Floor
Biden wants 50% of all new light-duty vehicles — passenger cars and pickup trucks — sold in the U.S. to be electric by 2030, and he has also ordered conversion of the federal fleet of 640,000 vehicles to electric, with EVs accounting for 100% of new vehicle acquisitions by 2027.
But based on the EVs and plug-in hybrids on display at the D.C. Auto Show, the industry is preparing for a gradual transition. Rolling out electric and plug-in hybrid SUVs and pickups seems to be the top priority for many automakers, both domestic and foreign. The MSRPs for these vehicles trend toward the low $40,000s and up.
Luxury brands, such as Lamborghini and Bentley, have hybrid models, but both companies unveiled high-end gas-powered SUVs in D.C.: the Lamborghini 2023 Urus, with a $230,000 price tag, and the Bentley Bentyaga, with a minimum price of $167,000. The Bentyaga is available in hybrid and ICE models.
Lamborghini is not planning to release a full-electric vehicle until 2028, according to a recent report from electrek, an online publication tracking vehicle electrification in the U.S. Bentley is promising a full electric fleet by 2030, with its first EV planned for 2026, as reported in Automotive News.
On the fun side, Hyundai promoted its popular Ioniq 5 crossover electric SUV with a mini-speed track laid out on the convention center floor. Attendees could ride along with drivers obviously well-trained in showing off the car’s quick acceleration on a short straightaway and cool performance on a couple of hairpin turns.
Toyota’s big reveal at the show was its redesigned fourth-generation Prius Prime, a plug-in hybrid, with the company mentioning its bZ4X electric SUV, released last year, only in passing. While Toyota is planning a full line of bZ (beyond Zero) models, it is marketing its hybrids and plug-in hybrids as all part of its “electrified fleet.”
Jason Keller, Toyota’s director for dealer policy, claimed that the minerals used for a battery in one EV could produce six plug-in hybrid vehicles or 90 hybrids.
“Our approach is to provide a comprehensive portfolio of carbon-reducing powertrains so that no customer is left behind,” Keller told the Policy Day audience. “So, it is not simply focused on how many vehicles of a certain technology we can put on the road, but rather how we can reduce carbon the quickest.”
Out on the convention center floor, Andre L. Welch, director of government relations at Ford Motors, said the company has “bold, ambitious goals” for leading the industry transition to EVs, pointing to a fire-engine red model of its electric F-150 Lightning pickup. But, he said, “We’re not starving our ICE business. We love our ICE vehicles.”
A couple hydrogen fuel cell vehicles were on display, such as the Hyundai Nexo, a fuel cell SUV. But Berube doesn’t see these cars as successfully competing with battery electric vehicles in the light-duty class, given the falling price of batteries.
Rather, he said, long-haul trucking will be “the sweet spot where we see hydrogen playing a huge role in helping to decarbonize transportation. … When you need to move those really long distances, really heavy weights, the refueling time for the amount of energy you need becomes a huge factor. With hydrogen you can refuel quickly.”
Waiting for Guidelines
The wait for federal guidelines is affecting the rollout of both the IRA tax credits and federally funded EV chargers, under the $5 billion National Electric Vehicle Initiative (NEVI) program, authorized in the Infrastructure Investment and Job Act.
While still working on the domestic content guidelines, the IRS has an online list of EVs and plug-in hybrids it says are qualified for a $7,500 tax credit. Popular U.S. brands — including the F-150 Lightning, Chevy Bolt and Tesla’s Model 3 and Model Y — are on the list. But, the IRS says, many foreign automakers have “entered into a written agreement with us to become a ‘qualified manufacturer’ but [haven’t] yet submitted a list of specific makes and models that are eligible.”
The IRS has provided an opening for foreign models that are leased by individuals. In a recent fact sheet, the agency identifies leased vehicles as eligible for the commercial EV tax credit, which is not subject to the domestic content requirements of the IRA.
EU Ambassador Lambrinidis welcomed the leased vehicle provisions but warned that with both the EU and the U.S. putting billions into transportation decarbonization, “the biggest mistake that governments can do is to get into a subsidy war. …
“That’s a danger because the IRA, the way it’s structured, in a sense is endangering investment in Europe. It is sucking away investment potential, especially at a time of very high energy prices,” he said. “Nothing could be worse for the strength of the U.S. economy and U.S. companies than a weak European economy.”
Rather than subsidy wars, Lambrinidis called on the U.S. and EU to look “at our markets as a unified supply chain.”
The issue also created tension at the recent meeting of the World Economic Forum in Davos, Switzerland, where European government officials labeled the domestic content provisions in the IRA as discriminatory and protectionist, according to The New York Times.
Officials also called for a European version of the IRA, with subsidies to support the expansion of clean energy technologies and supply chains. Outside the official meetings, “the phrase ‘trade war’ came up more than once,” the Times reported.
The installation of federally funded chargers is also moving slowly. Gabe Klein, executive director of the Joint Office of Energy and Transportation, which oversees the NEVI program, reported that states are holding off issuing requests for proposals for their first chargers until the upcoming release of final technical guidelines. While all 50 states, Puerto Rico and D.C. have submitted plans and received their first formula-based NEVI allocations, only a few have opened their application processes, Klein said,
Ohio, for example, opened bidding for NEVI funds in October, and Pennsylvania announced its NEVI funding opportunity on Jan. 6.
The IIJA also includes $2.5 billion for “discretionary” grants to states, cities and local organizations to install chargers in underserved and remote areas. The application process for those funds should be announced in the next few weeks, Klein said.
The draft guidelines for the NEVI funds, issued in June, set requirements for all chargers to be 150-kW DC fast chargers, but Klein appeared to signal that the discretionary funding could be used for Level 2 chargers.
“You’re probably looking at definitely some [DC] fast chargers, but you’re going to have a lot of Level 2 chargers” from the discretionary funds, Klein said, “Level 2 chargers are much easier to procure. They are very available; they’re much less expensive, and they’re easier to install and easier for utilities to deal with because there is less draw on the grid.”
While charger installation should start this year, Klein does not expect to see “a lot of chargers going out” until 2024 and 2025.
Transition not Seen Before
The incremental pace of the transition is affecting White House goals for converting the federal fleet to electric, according to Crystal Philcox, assistant commissioner for travel, transportation and logistics at the General Services Administration. “We want more and more and more electric models,” she said. “We have more demand than we can fill.”
The agency leases about 227,000 vehicles and is the main source of new vehicles, totaling about 216,000, across other agencies, Philcox told NetZero Insider during an interview between sessions at the Policy Day forum.
“We would normally replace 40,000 to 45,000 on a year, out of that [total],” she said. “Last year we just got really lucky to even be able to replace just under 35,000.
“We could replace vehicles in the fleet more quickly, and we would love to have access to more electric vehicles because we are really the primary way that the federal government is electrifying the federal fleet,” she said.
The U.S. Postal Service, which has another 220,000 vehicles, has also committed to working toward all new vehicle purchases being electric by 2026.
Building out a charging network for the fleet will also require ensuring the software systems involved have the appropriate security certifications, Philcox said.
Charging stations are networked through the cloud “and so we just want to make sure that the data that’s going through is secure, especially for our [Department of Defense] customers and our intelligence community customers,” she said.
Getting new chargers installed will also require “site surveys” — more than 200 planned for this year — “in different locations around the country to make sure that the electric grid is sufficient to support” the chargers, she said.
Developing the workforce to build EVs and install and maintain chargers is another challenge affecting federal, state and corporate stakeholders. But analyses of jobs lost, for example, when a fossil fuel plant closes, and jobs gained in clean tech are often “static” and miss the mark, said Betsey Stevenson, professor of public policy and economics at the University of Michigan.
“It’s like, ‘Oh, we’re not going to get this task and this task and this task anymore, so that job will be lost,’” Stevenson said. “But historically, jobs are rarely lost. What happens is tasks within a job evolve, and jobs evolve.”
At the same time, “a lot of the new jobs are going to be capital intensive and therefore involve more skills,” she said. Workers will need training, and a key challenge will be convincing workers that transitioning to new jobs is possible and positive, she said.
“How do we let people know that, when this is a transition to something they haven’t seen before,” Stevenson said. “We’re going to need some prodding. We’re going to need government, we’re going to need auto manufacturers to be pushing behind people and saying, ‘Trust us. Build the skills; the work will come.’”
Addressing a nationally recognized shortage of electricians, Stevenson called for a shift in the way training for these jobs is framed and designed. “Everyone wants their kid to go do a four-year degree,” she said. “But the truth is electricians today actually need a wider set of skills, and maybe we should think about four-year degrees that teach you how to run your own business, because these electricians … they’re running their own business, they need business skills, they need to learn economics. …
“Let’s stop thinking about this as something for only people who don’t want to go to college but thinking about this as a way to build a career,” she said.
A report issued Monday lays out a path for the U.S. to follow as it builds a network of offshore wind turbines and presents it as an opportunity to create an entirely new industry.
But there is some urgency to the effort, the report says, as there is limited infrastructure and manufacturing capacity now, and building it will take years. Given the extended lead time involved, most resources would have to be committed by the end of 2023 to create an operational supply chain by 2030.
The vessels and port infrastructure that exist now or are planned to be built would be enough to install only 14 GW by 2030, for example. And components for up to 83% of that first 30 GW of wind equipment would still need to be imported, while factories are being set up in the U.S. and American workers trained to run them, the report says.
“A manufacturing supply chain is already emerging in more than a dozen locations up and down the U.S. coast in support of the offshore wind industry, which will lead to thousands of well-paying jobs,” said Ross Gould of the Business Network for Offshore Wind, part of the partnership behind the report.
“To meet our ambitious clean energy national goals,” he said in a news release, “American manufacturers must play a larger role to accelerate our transition. This road map lays out the challenges and collaborative actions needed to bring more domestic companies into the supply chain and the opportunity those businesses bring to building out the U.S. offshore wind industry.”
Offshore wind has been gaining momentum for several years, with multiple states pressing development of multiple projects, particularly along the Northeast and Mid-Atlantic coasts.
The report’s authors say there is a widespread agreement that a domestic supply chain will be critical for sustainable growth in the new industry, but no clear understanding of what the supply chain should look like, how long it will take to create, what costs it will extract, what benefits it will yield and how much the existing infrastructure will accomplish.
“We demonstrate that if individual states leverage their existing manufacturing capabilities to contribute to the offshore wind energy sector, this conceptual supply chain would generate significant workforce and economic benefits throughout the United States, not just in coastal locations with active offshore wind energy programs,” the report states.
Multiple potential roadblocks were found on the road map, including communication gaps between stakeholder groups; scarcity of space and uncertainty of permitting for manufacturing facilities in ports; stress on supply networks for raw materials and subcomponents; and insufficient incentives for incorporating equity and sustainability into supply chain decision making.
But the most common concern that manufacturers shared with the report’s authors was the difficulty in securing financing to build the components of a supply chain because of perceived risk of cost or schedule overruns, legal challenges, and changes in government policy.
The report did not even look at the complexity of the transmission grid expansions that would be needed.
Details
The project is being overseen by the National Offshore Wind Research and Development Consortium and conducted by the National Renewable Energy Laboratory, the Business Network for Offshore Wind and DNV Energy USA.
A full project summary will be released by NOWRDC late this winter.
Monday’s report quantifies the resources needed to build a supply chain to reach the 30-GW goal by 2030 as follows:
$22.4 billion minimum initial investment
12,300 to 49,000 full-time equivalent workers
6,800 miles of cable
2,100 turbines
2,100 foundations
58 crew transfer vessels
34 new manufacturing facilities
11 service operation vessels
8 East Coast marshaling ports
4 to 8 transport vessels
4 to 6 heavy lift vessels
4 cable lay vessels
2 floating wind integration ports
2 scour protection installation vessels
Recommended near-term actions (2023-2024) to build a foundation are:
Convene working groups focused on local and holistic aspects of the supply chain.
Identify efficient and equitable locations for infrastructure.
Assess the need for additional incentive mechanisms.
Establish mechanisms targeted at floating wind infrastructure.
Establish curriculum and funding streams for workforce training centers.
Increase supplier awareness of offshore wind energy opportunities.
Recommended middle-term actions (2025-2030) to gain momentum are:
Construct the major supply chain facilities to meet demand.
Develop and share supply chain best practices.
Incorporate lessons from early OSW projects into operations and decision-making.
Train a manufacturing workforce.
Evaluate procedural and impact equity metrics for early OSW projects and incorporate best-practices into ongoing supply chain development activities.
Recommended longer-term actions (beyond 2030) to maintain a stable industry are:
Update key supply chain infrastructure to adapt to evolving technologies.
Expand supply chain infrastructure to new regions using lessons learned in early projects.
Add domestic production to fill manufacturing gaps in supply chains.
Continue to expand the offshore wind energy pipeline toward a potential 2050 goal of 110 GW installed capacity.
SPP, MISO Applying for DOE Funds to Help with JTIQ Portfolio
OKLAHOMA CITY — SPP told its members last week that it will apply for grants from the U.S. Department of Energy to help fund transmission projects recently identified with MISO along their seam that could unclog their generation interconnection queues.
David Kelley, the RTO’s newly minted vice president of engineering, said DOE’s $10.5 billion Grid Resilience and Innovation Partnerships (GRIP) program aligns neatly with SPP’s Joint Targeted Interconnection Queue (JTIQ) study with MISO.
GRIP, authorized under the Infrastructure Investment and Jobs Act, is designed to accelerate the deployment of “transformative” projects that improve the grid’s flexibility and resilience against the growing threats of extreme weather and climate change. It includes a focus on interregional projects, investments that accelerate the interconnection of clean energy generation, and using distribution assets to provide backup power and reduce transmission requirements. (See DOE Opens Applications for $6B in Grid Funding.)
The JTIQ study resulted in five projects on the MISO-SPP seam that should help reduce congestion and allow additional resources, primarily wind farms, to interconnect with the RTOs’ systems. Their staffs have proposed a cost allocation that assigns most of the portfolio’s $1.06 billion in costs to generation. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.)
“We have still yet to find the magic unicorn of developing transmission along the seams,” Kelley said. “When we looked at [the GRIP] program and what it was intended to do, it almost reads as if it was written for something like what JTIQ was trying to do. It was kind of a no-brainer for us to seek to receive some of this money on behalf of our members.”
Kelley said an initial concept paper has already been filed with the program’s administrators, meeting a Jan. 13 deadline. DOE will review the applications to determine whether they are worthy of full applications, providing that feedback to applicants. Final applications will be due May 19.
Under DOE’s Grid Innovation Program, applications must come from a state or a group of states, regulatory commissions or tribal or local governments. That has led SPP and MISO to collaborate with the Minnesota Department of Commerce and the Great Plains Institute (GPI) on the effort. The state of Minnesota, as a potential eligible recipient of the funds, made the filing. The institute is coordinating the effort by holding discussions with utilities that will build the projects and those utilities and states that will be affected.
“Our job has been to facilitate all potentially affected folks to kind of vet the DOE requirements,” Matt Prorok, GPI’s senior policy manager, told RTO Insider. “How might those be fulfilled? Are [the JTIQ] projects a good fit for this funding bucket?”
The proposed cost allocation for JTIQ projects. | SPP
Kelley pointed out that the GRIP program is a partnership involving federal and private dollars.
“We feel pretty good about it. We’ve talked to DOE a number of times, and they were very interested in what we’re doing here,” Kelley said. “We are being encouraged by what we’re hearing. But again, because this is a partnership, we do think it’s important that we lay the groundwork that not only are we pursuing DOE funds, but that we also have a commitment from SPP, MISO and our customers in our membership that we have the other half of this bill covered.”
Under the staffs’ proposed JTIQ cost-sharing methodology, generators will pay 90% of the portfolio’s cost and load will pay 10%. SPP load will pay about $71 million and MISO load about $29 million, without the DOE funding.
As with any discussion about allocating costs, several stakeholders raised concerns.
“I think all of us are seeing this DOE funding opportunity as a way to facilitate mitigating some of the concerns the stakeholders are expressing and the opportunity for that mitigation to really help make this a success,” the Advanced Power Alliance’s Steve Gaw said. “The second round of that application process, if the application makes it there, will be a very opportune time for additional comments of endorsement.”
The Cost Allocation Working Group (CAWG) on Friday unanimously endorsed and recommended that the Regional State Committee approve the 90-10 allocation. It also recommended that:
the 10% load portion of the JTIQ’s annual transmission revenue requirement (ATRR) be based upon adjusted production costs, as outlined by the RTOs’ joint operating agreement;
the load portion of the portfolio’s ATRR be regionally allocated on a load-ratio share basis consistent with previous RSC policies;
each building transmission owner recover the non-capital cost component allocable to generation interconnection customers through a formula rate template in the building TO’s region; and
SPP’s load share in the current portfolio and for the next study of the southern party of the MISO-SPP seam be regionally allocated on a load-ratio share basis consistent with previous RSC policies.
The motions all passed unanimously except for the last one, which Louisiana, North Dakota and Oklahoma opposed.
The RSC meets Jan. 30. Kelley said SPP plans to make the appropriate filings after the April round of governance meetings.
“We have to ensure we’re in lock-step with MISO and its processes,” he said.
GI Queue Continues to Expand
The JTIQ work will only result in more generation interconnection requests as SPP staff continue to work on reducing the backlog of requests in its queue.
Kelley said the SPP and MISO queues have grown since the JTIQ work began, with no end in sight.
“While we’ve made significant progress in clearing our existing backlog, there continues to be significant interest in developing new generation, both within the SPP footprint as well as MISO’s,” he said.
The backlog, which once stood at 651 requests and nearly 120 GW, had been reduced to 370 and 68.2 GW, respectively, in mid-December. However, the 2022 study cluster that closed in early January added 53.8 GW of requests, pushing the backlog to about 122 GW.
Many of those requests have yet to be validated by staff, leaving the active queue at 463 requests and just over 88 GW.
“It’ll take a couple of months to evaluate the impact of this cluster. It’s really, really big,” SPP’s Juliano Freitas told members, noting that the 2022 cluster exceeded forecasts by about 10 GW.
He said the new cluster is about 50% solar and 25% wind, in line with the active queue. Solar requests (39.2 GW) account for almost half the queue, with wind requests at 23.1 GW and storage at 12.9 GW.
SPP currently only has about 250 MW of installed solar capacity, said Casey Cathey, director of system planning. “That is kind of our next frontier.”
Freitas said that considering only about 40% of GI requests result in signed interconnection agreements, SPP could add more than 45 GW of capacity by 2028. The grid operator has added 27.7 GW of capacity since January 2017, executing 143 GI agreements.
Members Defer on PRM Deficiency RRs
The committee deferred action on a pair of revision requests related to deficiency penalties by load-responsible entities unable to meet the grid operator’s new 15% planning reserve margin (PRM).
Following late changes to the two requests by stakeholder groups the night before the MOPC meeting began, committee members agreed to wait until a special conference call Friday to consider the change requests. That will give additional time to several stakeholder groups who have yet to approve the proposed revisions; the committee will then be able to endorse a recommendation for the RSC and the Board of Directors when they meet next week.
SPP is hopeful FERC will approve the revision requests in time to accredit resources for the summer.
Staff have been working on the mitigation strategy at the board’s direction since July. It became necessary when the board increased the PRM from 12% to 15%, effective next year, which left some members complaining they would not have enough time to meet the requirements. (See SPP Board of Directors Briefs: Dec. 6, 2022.)
COO Lanny Nickell has said the mitigation concepts include reducing the deficiency payment charge, extending the timeline to cure deficiencies and adding mechanisms to assure capacity.
RR536, proposed by SPP’s Market Monitoring Unit, would replace the sufficiency valuation methodology’s current penalty framework with a sufficiency valuation curve similar to the curve that NYISO uses to value capacity in its market. The curve starts at twice the cost of new entry (CONE) until regional accreditation reaches the sum of total noncoincident peak loads, then slopes downward to a net CONE value when regional accreditation reaches the PRM.
When accreditation exceeds the PRM, the curve continues its downward slope until it reaches $0 when regional accreditation reaches 1.15 times the PRM. By focusing on how valuable excess accredited capacity is to the market given the regional level of accredited capacity, this methodology shifts from a punitive approach to a tool that manages the current deficiency and properly rewards LREs with excess accredited capacity.
Staff worked with the MMU on RR536 and also drafted RR537, which clarifies that an LRE making the deficiency payment will be sufficient for this year’s resource adequacy requirement. It also says that any entity receiving a deficiency payment cannot subsequently sell any of the excess capacity during the applicable calendar year.
“I think we’re getting closer. Today is too soon, given the language was only provided last night,” Evergy’s Mo Awad said. “I would like to take some time and review the language.”
Staff drew up a number of issues for stakeholder consideration, including clarifying that the waiver process is only in effect when the PRM increases; the timing of when generation must be committed to SPP, based on a deficiency megawatt amount; how the cost of new entry is broken into seasonal components; and simplifying megawatt allocation for the MMU’s CONE process.
The Supply Adequacy and Regional Tariff working groups will take up the revision requests on Tuesday and Thursday, respectively. The CAWG met Friday but did not vote on them; it has scheduled a special meeting for Wednesday.
December Storm Raises Same Issues
Staff told the committee that the December winter storm, while less severe than the February 2021 storm that forced the grid operator to shed load for the first time, still highlighted some of the same issues from two years ago.
C.J. Brown, director of system operations, said constricted fuel supplies and extreme cold weather-related outages led to some generation unavailability as surface temperatures in the SPP footprint were up to 25 degrees Celsius below historical averages.
Staff began receiving notifications on Dec. 20 from natural gas suppliers that non-firm usage of pipelines would be limited through Dec. 28. Ice floes on the Missouri River threatened several gigawatts of hydro generation, and the RTO’s main control room operated on backup power during the event after the facility’s transformer malfunctioned.
Empire Electric District and City Utilities of Springfield, Mo., near the Missouri-Arkansas border, experienced extremely low voltages on Dec. 23 caused by resource trips, lack of deliverability and parallel system flows. Empire had to shed about 25 MW of load for 15 minutes on Dec. 22.
Still, SPP was able to meet a peak demand of 47.2 GW on Dec. 22, a winter record.
Brown said that if the worst weather conditions had shifted to Dec. 23 or Dec. 24, SPP would have had 2 to 5 GW of capacity at risk.
“It doesn’t mean we would have had load shed,” he said, noting that the RTO could have reached energy emergency alert levels. “None of us want to be in a headline that says we shed load over Christmas. We need to get better information” from gas suppliers.
Midwest Energy’s Bill Dowling cautioned SPP about taking comfort in the amount of gas generation it committed before the cold front blew in.
“It’s one thing to know that [a gas unit] is committed a couple or three days in advance; … it’s something else to get the gas,” he said. “If the gas producers aren’t producing and it doesn’t show up in interstate pipeline, you’re not going to get it, I don’t care how much you paid for it.”
Josh Phillips, who represents SPP at the North American Energy Standards Board, said the board’s Gas-Electric Harmonization Forum is preparing a report on three main areas of concern during extreme weather events: fuel delivery assurance, communication practices and gas reliability.
Power generators and load-serving entities are underrepresented on the forum, Phillips said. He urged more industry participation as the final report delves into whether there’s a need to require every gas generator to have firm gas supply and transportation contracts.
Dowling said that whenever he listens to discussions between the electric and gas sectors, “it ends up, ‘This is your problem, electricity, so you have to change to meet our requirements.’”
“If [gas suppliers] declare force majeure, you just don’t get your gas,” said long-time MOPC member Bill Grant, now consulting for XO Energy. “The NAESB agreement needs teeth if they don’t perform, that’s the answer.”
Brown said staff will complete its post-event review and gather lessons learned, while also participating in the FERC-NERC joint inquiry on the storm. They will continue to support resource adequacy efforts through the RSC and other stakeholder groups.
Members Endorse ITP Scope, STEP
The committee endorsed two stakeholder groups’ recommendation to approve the 2024 Integrated Transmission Plan’s scope, which includes assumptions not standardized by the ITP manual.
The assessment will study two futures — a reference case and an emerging technologies case — that assume between 49.9 and 54.9 GW of wind resources and between 14 and 22 GW of solar resources by Year 10. SPP currently has 32.5 GW of installed wind capacity and 14,000 turbines on its system, but only about 250 MW of solar, Cathey said.
The scope also includes peak and energy increases in both futures to account for electric vehicle growth and an approved methodology for retirements based on participants’ resource plans. Staff used those plans to also determine wind, solar and storage capacity amounts. The study scenarios will assume all companies meet the PRM.
“We believe the two futures capture the necessary scenarios for building out the transmission system,” Cathey said.
The committee also endorsed the SPP Transmission Expansion Plan (STEP), a comprehensive list of all transmission projects over a 20-year planning horizon. The report indicates that SPP members completed eight upgrade projects costing more than $40 million from last April to year-end. SPP issued 76 notifications to construct (NTCs) for $822 million during the same period; 12 NTCs were withdrawn.
Cathey reminded the committee that the 2022 ITP assessment was a reliability-only study, thus resulting in a smaller portfolio.
RAS Scheme Passes
The committee unanimously approved a consent agenda that included eight revision requests; an extension of the Transmission Owner Selection Process Task Force’s sunset to Jan. 31, 2024; a waiver request to include the 2023 ITP needs assessment’s market powerflow models (MPMs) and consider the 2023 ITP MPM violations in the 2024 ITP; and a sponsored upgrade study of NextEra Energy’s proposal to add a 345/138-kV transformer at Oklahoma Gas & Electric’s Cimarron substation.
Nebraska Public Power District had RR505 pulled off the agenda for a separate vote, over concerns that the remedial action scheme (RAS) criteria would lead to unintended consequences. The change would supplant the need for approval conditions and clarifies RASes’ appropriate uses. Members approved the revision request with a 95% vote.
Five other RRs, if approved by the Board of Directors next week, would:
RR519: formalize the SPP operating criteria’s requirement to perform an annual resource real-time availability evaluation and report findings and recommendations to appropriate stakeholder groups.
RR522: clarify the use of the word “separately” (“Each facility must be registered separately with SPP…”) to direct parties in the agreement to register each facility separately when they have multiple resources involved with the pseudo-tie agreement.
RR523: modify existing pro forma generator interconnection agreements and language to provide a clearer indemnification standard with clearer language. The changes are modeled on PJM’s interconnection service agreement.
RR526: specify that a resource or an aggregation must be able to maintain a response of at least 0.1 MW for at least an hour to participate in the Integrated Marketplace; if the anticipated response drops below 0.1 MW, the resource must set its commitment status to “outage,” consistent with recent FERC orders and SPP’s current process.
RR528: clean up Business Practice 7060 by using “evaluation” rather than “study” for projects that have been issued an NTC, aligning the term with how it is used when an NTC is re-evaluated through the ITP.
The consent agenda also included two other RRs that don’t require board approval and go into effect immediately:
RR525: deletes Business Practices 7100 (Designated Transmission Owner Qualification Process) and 7150 (Transmission Owner Selection when a Designated Transmission Owner Rejects a Notification to Construct), which became obsolete with the implementation of SPP’s competitive transmission selection process.
RR529: the annual cleanup to correct grammar, punctuation and acronyms in the production and/or forward looking protocols.
