New Jersey is stepping up its electric vehicle promotional efforts, adding a fourth year to its main purchase incentive program and $13 million to a separate fund to encourage municipalities to buy electric trucks.
The fourth year of the Board of Public Utilities (BPU) program known as Charge Up New Jersey opened for applicants on July 12 with the same maximum available incentive as in the last round: $4,000 for the purchase of a vehicle priced below $45,000. However, the agency has cut the incentive for a vehicle priced between $45,000 and $55,000 to $1,500, from $2,000 in the third year.
The program, which awards incentives totaling at least $30 million a year, so far has paid out $73.5 million in incentives, providing subsidies for more than 16,000 vehicles, according to the BPU. That is equal to about 17.5% of the 91,560 EVs the New Jersey Department of Environmental Protection (DEP) reported in the state at the end of 2022. Yet EVs still account for less than 4% of the 2.53 million vehicles of all types research firm Statista said were on New Jersey roads in 2021.
The new phase of the Charge Up program is part of a multipronged state effort to promote EV purchasing and stimulate the development and installation of EV chargers to remove potential buyers’ range anxiety.
The push coincides with the release of New Jersey’s second Strategic Funding Plan for the state Regional Greenhouse Gas Initiative (RGGI) for 2023-2025. Transportation is the state’s largest source of greenhouse gas emissions, at just over 40%. It’s one of four spheres of focus in the RGGI plan, which says the goal is to “continue to drive the transition to electric transportation throughout the state, with a focus on electrifying light-, medium- and heavy-duty vehicles benefiting environmental justice communities.”
Expanding Charger Access
As part of the push, the BPU began soliciting new applications on July 12 for three programs designed to incentivize the development and installation of electric chargers. They include the EV Tourism Charger Program, which provides incentives of up to $5,000 for a Level 2 charger and up to $50,000 for a fast charger installed at a tourism destination, such as a hotel, boardwalk or historic site.
Also seeking applications is the Multi Unit Dwelling (MUD) Charger Incentive Program, which encourages owners and operators of MUDs to provide EV chargers for residents and guests by offering up to $4,000 for a Level 2 charger and up to $6,000 for a Level 2 charging station in an overburdened community. The third program opened for new applicants, the Clean Fleet program, provides grants to local governments and nonprofit organizations. The program offers up to $4,000 for the purchase of a light-duty EV, up to $10,000 for trucks up to Class 6 and up to $5,000 for the installation of Level 2 chargers.
The BPU has budgeted $8 million for the tourism program, $15 million for the MUD program and $12 million for the Clean Fleet program in this fiscal year.
Gov. Phil Murphy (D) said the four programs together would help “establish EVs as an affordable and accessible option for all residents, regardless of their income or zip code.”
“In order to remain on track to meet our bold emissions-reduction goals, we must ensure that cost constraints and range anxiety no longer pose formidable obstacles for our hard-working families,” he said.
Stimulating ‘Incentive-essential’ Buys
The Charge Up program has awarded 6,933 subsidies totaling $19.6 million since July 1, 2022, with an average subsidy of $2,775, according to figures on the program website.
Tesla vehicles accounted for 4,600 of the subsidies, or about 62% of the funds awarded, the figures show. In 2020, the first year of the program, Teslas accounted for 83% of the incentives. In response, the BPU changed the rules so the largest subsidy would go to vehicles costing less than $45,000 in an effort to help “incentive-essential” buyers, those with lesser economic means who opt for a cheaper vehicle and might not buy an EV without the subsidy.
Purchases of Chevrolet Bolts accounted for 936 incentives, or about 19% of the subsidy funds awarded in the year from July 1, 2022, and Volkswagen buyers received 627 subsidies, or about 8.5%, the figures show.
Hyundai buyers received 332 subsidies (4.6%), and buyers of Nissans received 136 subsidies (2.4%), with most of funds going to purchase Leafs.
Helping Small Population Communities
The $13 million made available for local governments to buy EV trucks will be awarded in a competitive solicitation for projects that closes Sept. 4. The subsidy amounts are designed to offset the extra cost of buying an EV compared to a diesel vehicle, and to be eligible for an incentive, applicants must be replacing and decommissioning a fossil-fuel vehicle.
This year, the program for the first time will offer an incentive for Class 2 to 6 vehicles, such as garbage trucks, school buses and shuttle buses. The maximum incentive in that category is $10,000.
The program is part of the sixth round of awards of RGGI funds, and it prioritizes subsidizing local government vehicle purchases in overburdened communities, with additional incentives allocated to communities with a population of less than 20,000.
For example, the program would award a subsidy of $15,000 to a community that purchased a Class 2 non-passenger vehicle, the smallest size funded in the program. But the subsidy could be increased to $56,000 if the municipality is an overburdened community with a population of less than 20,000. At the top end, a Class 8 non-passenger vehicle could receive a basic subsidy of $305,000, with an additional $30,000 if it is an overburdened community and another $76,000 if the purchaser is a municipality with a sub-20,000 population.
To receive the funds, the new vehicle must be fitted for three years with a telematic device, which allows the collection of data on the use of the vehicle.
New York has pushed back the contract award date in its latest offshore wind solicitation, and invited developers who submitted proposals to rebid at lower prices.
The New York State Energy Research and Development Authority (NYSERDA) said the addendum is intended “to ensure the most cost-effective outcome of the solicitation for ratepayers.”
NYSERDA, which is leading the state’s offshore wind development efforts, said on its website the move was in response to guidance issued in April and May by the Internal Revenue Service regarding tax credit eligibility through the Inflation Reduction Act.
The deadline for bids in New York’s 2022 solicitation was Jan. 26, 2023. NYSERDA at the time called it a robust and record-setting response — 100 proposals for eight projects from six developers. The details not only would help the state make huge strides in its energy transition but help create the local offshore wind industry envisioned by the state.
It said Jan. 27 that it expected to announce awards in the spring of this year.
In the July 27 memo to bidders, NYSERDA said it now expects to announce awards in the fourth quarter of 2023.
NYSERDA said the addendum is “another opportunity for updated pricing to ensure the most competitive award group.”
It said bidders could submit prices identical to or lower than their original bids but could make no other changes or propose higher prices.
Headwinds
Offshore wind construction has become much more expensive in the past two years — so much so that many developers are seeking to renegotiate or even cancel their financial agreements.
Commonwealth Wind in Massachusetts has reached a deal to pay nearly $50 million to cancel its power purchase agreements with three utilities, and SouthCoast Wind is seeking a similar exit. Both have said they hope to rebid in the next solicitation, at a higher cost.
The developers of the Beacon, Empire and Sunrise projects — every contracted wind project off the New York coast not already under construction — told the state Public Service Commission in June they may not be able to proceed without more money.
They want the type of inflation adjustment mechanism that was offered in New York’s 2022 solicitation, but not in the two previous solicitations.
The situation is similar in other states: Most developers who locked in their revenue but not their costs before surges in inflation and interest rates now say their projects cannot be financed as negotiated.
Much of the overrun likely will trickle down to the general population through some combination of higher utility rates, taxes and consumer prices.
That does not sit well with some stakeholders, especially given the secretive nature of offshore wind development. Most substantive details and dollar figures are redacted from public versions of developers’ supporting documentation.
The City of New York and a group of 55 large commercial/industrial/institutional energy users filed a motion (PSC Case 15-E-0302) on Thursday to force Beacon, Empire and Sunrise to disclose more information on their request for more money.
“Petitioners’ excessive redactions of critical information means that customers do not know the total amount of additional compensation that these developers are asking them to pay, nor can they evaluate the claimed need for such relief, and they are being deprived of the opportunity to develop fully-informed comments responsive to the Petitions,” they wrote.
“Petitioners’ overbroad use of redactions reveals a lack of regard for the right of utility customers to be adequately informed as to the costs they are being asked to bear.”
Inflation has eased in 2023 but interest rates have not.
Rhode Island Energy in July rejected the lone proposal submitted in Rhode Island’s latest offshore wind solicitation as too expensive for that state’s ratepayers.
WASHINGTON — FERC on Thursday unanimously issued Order 2023 revising its pro forma generator interconnection queue rules to speed up the backlogged process (RM22-14).
The rule will ensure that generation resources are able to connect to the grid in a reliable, efficient, timely and transparent manner, acting Chair Willie Phillips said at a press conference after the commission’s monthly open meeting.
“The final rule is one of the largest in FERC’s history. It represents the largest and most significant set of interconnection reforms since the pro forma interconnection procedures were created two decades ago,” Phillips said. “Our country has a severe interconnection backlog. Currently there are 2,000 GW of resources in interconnection queues, the largest backlog in history.” (See LBNL: Interconnection Queues Grew 40% in 2022.)
The rule would shift the pro forma interconnection rules from a first-come, first-served serial process to a first-ready, first-served cluster study process. It ramps up financial requirements for developers and sets penalties for transmission providers that fail to meet deadlines for completing interconnection studies. (See FERC Proposes Interconnection Process Overhaul.)
The rule also requires interconnection studies to consider grid-enhancing technologies (GETs) and sets new reliability standards for inverter-based resources.
Order 2023 comes out of the Advanced Notice of Proposed Rulemaking issued in 2021 under Chair Richard Glick, which has also produced a still-pending NOPR on transmission planning and cost allocation. (See FERC Issues 1st Proposal out of Transmission Proceeding.)
“We will not stop work on the long-term and regional planning transmission NOPR,” Phillips said. “We look forward to, in the months ahead, finalizing that proposal as well. And together … we will have the greatest transmission reforms in a generation to come out of FERC.”
All of the other commissioners praised the process around developing the final rule, with Commissioner James Danly saying that while he would have preferred looking into the six ISO/RTO interconnection queues individually, the final rule was a successful collaboration among the four sitting commissioners.
“Take me at my word when I say it because I don’t give compliments,” Danly told Phillips. “I pay you one here: You set up a set of circumstances where there was genuine collegiality amongst the offices in shaping the rule.”
Reforming the queues is important, Commissioner Allison Clements said, as many grid operators have signaled they will need additional resources soon to help keep the lights on.
“While we’re not looking to replace retiring thermal units on a one-to-one basis with solar and wind, getting these resources online, as the grid operators have told us, is critical to help alleviating their own concerns,” she added.
Clements also lauded Order 2023’s embrace of GETs, many of which are mature technologies that have been around longer than some consumer items that have long since gone out of fashion, such as floppy disks and the Sony Walkman.
Commissioner Mark Christie said the rule was a step toward unclogging the queues around the country. Ideally it will not conflict with any revisions that grid operators have made on their own, such as PJM’s, he added. (See FERC Approves PJM Plan to Speed Interconnection Queue.)
“That’s one of the issues that I address in my concurrence … the question of whether we have appropriate hold-harmless language with regard to existing reform efforts,” Christie said.
As with the old pro forma rules, ISO/RTOs will be able to seek an “independent entity” variation from FERC, and even vertically integrated utilities can get an exemption if they prove their rules are consistent with, or superior to, the new minimum standards. Some grid operators are engaged in changes that go well beyond what FERC has required with Order 2023. (See CAISO Tries to Shake up Its Interconnection Process.)
Given that the country has 2,000 GW of projects in the queue, which is double the amount of generation actually operating today, it is clear that the backlog needs to be worked through, Phillips said.
“Our government rules and regulations need to keep pace with the needs of our energy grid,” he added. “And so, while I applaud the RTOs that have moved forward with reforms, I think they’ve done it because, quite frankly, they know that FERC was moving aggressively to finalize this rule. And that’s a good thing. We want to make sure we recognize regional flexibility. What works in Alabama may not work in the Northwest, or what works in New York may not work in Arizona; we recognize that. But let me say this: No one region does every single thing that we put forward in this rule.”
Stakeholders Applaud Rule, but Await Changes on Transmission
Most initial reactions to Order 2023 were in praise of FERC for addressing the issue of clogged queues, but they also called on it to continue with its work on transmission reforms.
“Advanced Energy United and our members applaud the commission for identifying the urgent need for interconnection reform and for working diligently to put forward a final order that will start to improve the broken interconnection process,” said Managing Director Caitlin Marquis. “In light of the scope of the interconnection challenge, we also appreciate acting Chair Phillips’ recognition that there is ‘so much more to do’ and hope to see this momentum maintained with follow-up efforts by the commission to address additional interconnection reform needs.”
All were commenting based on what information FERC released at its meeting, with the order not being released as of press time Thursday evening. But AEU welcomed the commission’s decision to move away from non-financial “readiness” requirements that were unworkable while keeping provisions to hold transmission providers accountable to deadlines, with penalties growing every day they are late.
“While ACEG welcomes approval of these reforms, the best way to address interconnection delays is still to improve the planning and development of new transmission lines,” said ACEG Executive Director Christina Hayes. “As the commission begins its August recess, it is critically important that it continue to make progress on several outstanding items, including the planning and cost allocation rule. FERC has a crucial role to play in protecting the long-term reliability of our energy system, which is why it needs a full complement of members. We hope the president will expeditiously fill any vacancies so FERC can continue its important work.”
The Sierra Club also welcomed the rule, saying it was hopeful it would help grid operators clear out the 2,000-GW backlog.
“Moving these renewable generation and storage facilities from the queue to the real world is a critical step toward creating a clean, reliable and efficient energy grid, and we look forward to ensuring any process improvements here are implemented swiftly and fairly by grid operators across the country,” Sierra Club Senior Attorney Greg Wannier said.
The rule’s requirements for transmission providers to meet deadlines or face fines are a welcome new development because previously the onus was put on the developers of wind, solar and storage who were creating the demand for interconnection, Jason Burwen, a vice president at the storage firm GridStor, said in an interview.
The final rule changes how storage’s impact on the grid is studied in the interconnection process. Current interconnection planning processes often assume the worst-case scenario with storage charging at the peak demand hours, but the NOPR proposed shifting that to a more real-world use of the technology, Burwen said.
The new rules will allow storage developers to submit a business case to grid operators that lays out how the facility will actually be used, thus avoiding overestimates of their grid impacts, according to the order. Standalone storage, hybrid facilities and co-located storage can all submit such business cases, which transmission operators can disagree with if they are not consistent with “good utility practice.”
The order sets up a process in which the transmission owner explains its disagreement in writing and the storage project seeking interconnection can come back with a second attempt that address those concerns.
While storage is not as dependent on transmission expansion as wind and solar, it does need to see the grid expand to reach its maximum potential, Burwen said.
“Even these interconnection reforms … are probably a few years out from really kicking in and changing the way in which business is done,” Burwen said. “But it’s much more matching the timescale of the pain that wind, solar and storage project developers are facing as they try to build stuff and do so on the timelines that any rational investor is going to expect of them.”
RTOs React
RTOs had limited response to the order, as the text of the 1,481-page final rule wasn’t posted until Friday evening.
MISO said it is assessing how the new rules will interact with its proposal to limit queue submissions to about 73 GW annually, triple its entry fees and establish more rigorous land obligations and escalating penalty charges. (See MISO Aims for Manageable Interconnection Queue.)
“The commission has acknowledged MISO’s leadership in developing innovative solutions to the interconnection challenges. MISO appreciates the commission has codified many of them in Order 2023, and MISO is already assessing additional reforms to improve the quality and viability of future submissions,” RTO spokesperson Brandon Morris said in a statement to RTO Insider. “MISO is reviewing how the current rule can support these efforts and not slow these future reforms to help address the interconnection challenges in the MISO region.”
“The NYISO began efforts to improve the interconnection process in 2022, recognizing the need and urgency for reform. Efforts to accommodate new technology proposing to interconnect to the grid and developing efficiencies in the process are well underway,” said Kevin Lanahan, the ISO’s vice president of external affairs and corporate communications. “As part of these efforts, the NYISO has held numerous open forums where stakeholders have provided valuable feedback and proposals.”
“PJM expects to study the interconnection of more than 260,000 MW of mostly renewable resources. The process will speed up and streamline generation interconnection requests, improve project cost certainty, and significantly improve the process by which new and upgraded generation resources are introduced onto the electrical grid,” Shields said.
CAISO referred to its NOPR comments, which supported eliminating the “reasonable efforts” standard and imposing penalties for missed deadlines. It also noted it was the only ISO/RTO that did not report missing any study deadlines in 2022.
ISO-NE and SPP declined to comment.
Amanda Durish-Cook, Tom Kleckner, Devin Leith-Yessian, Hudson Sangree, Jon Lamson and John Norris contributed to this story.
ST. PAUL, Minn. — SPP’s Board of Directors and its state regulators last week endorsed congestion-hedging improvements that have been years in the making, accepting staff’s recommendation to approve a package of eight proposals designed to increase equity, fairness and financial transmission rights awards among market participants.
Three of the proposals are meant to improve equity by modifying: the long-term congestion rights (LTCRs) second round’s nomination capacity from 100% to an incremental percentage up to 100%; the nomination capacity calculation for the first round of the annual auction revenue rights (ARRs) to better allocation ARRs; and the ARR’s first round nomination capacity from 50% to an incremental percentage up to 50%.
Three other proposals will update load modeling and generator modeling to better align with transmission service studied and coordinate with transmission planning to review firm transmission assumptions used in the planning process. A seventh sets up stakeholder education to explain how existing tools can increase awards.
The distribution of excess auction revenue proved to be the sticking point before staff and the Regional State Commission’s Cost Allocation Working Group (CAWG), comprised of regulatory staff, agreed on a phased-in approach that provides equity in congestion rent for firm rights to transmission paths.
Recommendation No. 5, owing to its place on the list, will distribute excess ARR awards using a nomination cap-minus award method that considers only LTCRs and annual ARRs from the first two auction rounds and monthly ARRs from the first iteration. The first year will use 50% of the current distribution method and 50% of the new method, with the latter accounting for all distributions going forward.
The methodology, proposed by Evergy, does not consider congestion’s value on non-hedged firm transmission rights and benefits participants with non-congested and counter-flow firm rights.
SPP’s Market Monitoring Unit (MMU) weighed in on the debate, supporting staff’s recommendation for No. 5 that considers congestion’s value on firm transmission rights not hedged through the allocation process and calls for a third round of ARR nominations. It said the Evergy proposal was an incremental improvement to the current process, while staff’s proposal creates three times more equity over the current process.
Congestion-hedging improvements were one of 21 proposals brought forth by the Holistic Integrated Tariff Team and approved by the board in 2019. Staff first pushed for optimizing the flow of energy in a direction that results in a charge to the transmission congestion rights (TCRs) holder, or counter flow optimization, to address concerns about how TCRs are awarded and the efficiency of the current process. However, it never gained traction in the stakeholder process and eventually was replaced last year by a hybrid approach that focuses first on equitably allocating the congestion rights instruments and then increases the pool of awards available. (See SPP Congestion-hedging Recommendations Gain Traction.)
The package did not include a recommendation to give more opportunities for all market participants to receive long-term congestion rights. CAWG and staff are working together in considering load-serving entities’ ability to request and obtain LTCRs, making the awards finite and adding capacity factors and/or accredited capacity requirements to candidate LTCRs.
The topic was the primary reason the package drew opposition from renewable energy interests during the Members Committee’s advisory vote for the board, which passed 16-6 with one abstention. EDP Renewables’ David Mindham said transmission customers still are faced with a “major” equity issue when trying to deliver power through their transmission service.
“We enter those agreements willingly and most of my colleagues are looking to shed those agreements as quickly as possible,” he said, “as SPP has a strategic priority to optimize seams. Without issue No. 1 being part of the discussion, there is a major incentive for us to not wheel power associated with a major carrier that doesn’t align with the strategic priorities of SPP.”
Arguing that “perfection should not be the enemy of the good,” SPP’s Antoine Lucas, vice president of markets, said the nine recommendations will make “notable progress” with financial transmission rights.
“I still believe that recommendation one will have the most significant incremental impact,” he said. “If we’re able to make the progress that I believe that we can make on recommendation one, I believe that the impact or the difference between the two approaches or recommendation five really starts to level out to some degree. I really think it has the ability to bridge that divide.”
The RSC unanimously endorsed the package’s recommendations July 24 after it cleared the CAWG on an 8-4 vote.
General counsel Paul Suskie said staff now can begin turning the package’s eight approved items into revision requests.
Board, RSC Endorse Winter Obligation
The board and RSC also both endorsed a revision request that adds to the tariff a winter resource adequacy requirement for load-responsible entities (LREs) bound by the grid operator’s recent planning reserve margin (PRM) increase.
The measure (RR549) applies the same level of validation, study and assessment requirements to the winter season (December through March) that currently applies to the summer season, including a deficiency payment for capacity shortfalls. It also assigns an annual deficiency payment to prevent duplicate payments for the same capacity within an annual timeframe.
The board approved RR549 although the 23-person Members Committee only gave it 10 concurring votes against nine in dissent and four in abstention. SPP staff normally does not report the results of the directors’ ballots.
David Kelley, SPP’s vice president of engineering, said a winter season obligation is the culmination of a large amount of work by several stakeholder groups. That work now is focused within SPP’s Resource and Energy Adequacy Leadership Team. (See SPP REAL Team Endorses Winter Resource Requirement.)
“This is kind of the first major policy decision that sets the cornerstone for the rest of these policies to be effective,” he said.
“From my perspective, there’s a desire to get going with making the current resource adequacy an actual requirement … that we can hold people accountable to it while we continue to work on other aspects of the policy,” SPP CEO Barbara Sugg said.
Western Area Power Administration’s Lloyd Linke, holding a proxy for NorthWestern Energy’s Bleau LaFave, urged delay to give winter-peaking utilities greater clarity in how winter outages will be treated.
“The treatment of outages being the same or similar in the summer season as opposed to the winter season … is such a critical aspect of the whole program for us,” he said. “There is just a strong concern by the winter-peaking utilities that, ‘Yeah, it sounds good. It sounds like everything’s gonna be hunky dory. And we’re going to have the same sort of requirements, summer and winter.’ We just like to see that particularly baked into it initially so that we have some certainty.”
Keith Collins, the MMU’s vice president, repeated the same concerns with RR549 that he expressed during earlier MOPC and RSC meetings. While he supports a winter resource adequacy requirement (RAR), he said that, as written, the tariff revision doesn’t include language requiring a reasonable expectation of availability for resources used toward RAR; it doesn’t achieve the policy’s goal for the deficiency payment; and the deficiency calculation does not send the appropriate signal to improve available accredited capacity.
$50M Budget for Western Services
Members and directors approved nearly $50 million in budgets endorsed by the Finance Committee for two prongs of SPP’s expansion into the Western Interconnection, Markets+ and RTO West.
The approval sets the Markets+ budget at $9.7 million to fund its development of a tariff and associated protocols for a day-ahead market, designed for those not yet willing to join an RTO. The funds were collected upfront from potential market participants; work began earlier this year and is targeted to conclude with a FERC filing by 2025.
Almost all the costs are for labor. After the tariff is filed, SPP also has contractual agreements in place to bill the parties $500,000/month to attain FERC’s approval and to develop the market’s second phase funding agreement.
The RTO West’s $39.9 million budget sets aside $20.3 million for labor and $8.7 million for software, including maintenance. SPP has begun the same new member stakeholder process used in previous expansions to support the interested parties’ evaluation of RTO membership.
Five parties already have signed commitment agreements that obligate them to reimburse SPP for costs incurred should membership not be consummated. Deadlines have been established for the remaining parties to sign agreements.
RTO West will add 6 GW of capacity to SPP’s current market, creating a contiguous RTO market footprint with 59 GW of capacity that “optimizes trade by leveraging resource mix, geographic, and time zone diversity.”
SPP says RTO West will save members about $194 million annually in market savings, although some stakeholders expressed a wait-and-see attitude. Evergy and American Electric Power cast opposing votes when the Members Committee endorsed the RTO West budget 19-2, with two abstentions. AEP abstained from the Markets+ budget vote, which the committee unanimously endorsed.
Staff, led by Lucas and Bruce Rew, senior vice president of operations, made their cases before the Finance Committee in March.
“I’m grateful that Antoine and Bruce are in the room. They survived the Inquisition that the Finance Committee performed, and you’ll be happy to know they’re no longer limping, so they should be able to quickly get to a mic in case they need to answer a question I can’t,” SPP’s Lanny Nickell said, injecting some droll wit into his presentation.
Order 881 Compliance Change Passes
The board signed off on RR565 that staff and stakeholders say will bring SPP into compliance with FERC Order 881. On Friday, staff filed the tariff change with the commission and asked for an effective date of July 12, 2025 (ER22-2339).
The commission earlier had granted the grid operator’s extension request of Aug. 1.
Order 881 directs transmission providers to use ambient-adjusted ratings (AARs) for short-term transmission requests — 10 days or less — for all lines that are affected by air temperature. Seasonal ratings will be required for long-term service. (See FERC Orders End to Static Tx Line Ratings.)
SPP said in its response to a May deficiency letter that it will use updated AARs as the relevant transmission line ratings for reliability unit commitments and any other market process associated with the day-ahead and real-time markets. It also explained its timelines for calculating or submitting AARs and addressed systems and procedures so transmission owners can update their line ratings at least hourly.
The Monitor said the revision does not clearly delineate the expected roles between TOs and transmission provider and the use of AARs in market processes. It recommended edits that obligate TOs to provide factual line ratings and methodologies and that add transparency into the market processes’ line ratings.
“The tariff does not have the same responsibility requirements on transmission owners to provide information for transmission line ratings that are in fact accurate and factual,” Keith Collins, the MMU’s vice president, said. “That’s the type of language we see as being incredibly important to be included as the responsibilities that exist for the transmission owner.”
“Keith makes a good point,” the Advanced Power Alliance’s Steve Gaw said before the RR565 votes. “I think FERC might see this as an issue, but I also think that it’s been to the stakeholder process and for the sake of efficiency, we should probably move forward and let FERC wrestle with this issue.”
SPP Prepping EPA GHG Comments
Oklahoma Gas & Electric’s Emily Shuart suggested during the Strategic Planning Committee’s (SPC) discussion of the Environmental Protection Agency’s greenhouse gas rule that SPP use its comments to stress the importance of resource adequacy and retention.
EPA in May proposed to reduce carbon dioxide emissions from coal- and gas-fired power plants by requiring them to use carbon capture and sequestration and co-firing hydrogen. Comments on the rule are due Aug. 8. (See EPA Proposes New Emissions Standards for Power Plants.)
Shuart proposed that SPP use the comments, being developed by staff and an advisory stakeholder committee, to further engage with EPA “to secure our efforts in resource retention and making sure that there’s education on the resource adequacy and reliability issues that are coming into question right now, not just with the greenhouse gas proposals but with a number of their pending regulations and proposals.”
“I think there’s a role for us as the RTO, particularly one that is structured where we are geographically with resources, that we have to get in front of the EPA and let them know the challenges that we’re facing and how those are exacerbated by premature retirements,” she said.
Sugg agreed, saying the grid operator is in an “independent spot.” She said that, recognizing that members “are on both sides of the equation and concern areas,” the dialogue will continue between staff and the SPC.
Board Search Underway
Sugg, who also chairs the Corporate Governance Committee, said the group will conduct interviews in August for the board vacancies soon to be created by the retiring Larry Altenbaumer and Josh Martin.
“Despite our best efforts, [Altenbaumer and Martin] are riding off into the sunset at the end of this year,” she said.
The two will take nearly 38 years of board experience with them into retirement. A director since 2005, Altenbaumer replaced long-time board chair Jim Eckelberger in 2018 before handing the role to Susan Certoma earlier this year. Martin has chaired the Oversight Committee for more than a decade.
Director Liz Moore has accepted a nomination for a second three-year term. The Members Committee will vote on nominations to the board in October.
Sugg also said the CGC has nominated ITC Great Plains’ Patrick Woods and Basin Electric Power Cooperative’s Jeremy Severson to serve terms on the Members Committee ending in 2025. They currently are filling the vacancies left by Brett Leopold, who left ITC earlier this year, and Tom Christensen, who has retired from Basin Electric.
Woods and Severson will be up for election during the October board meeting.
Directors OK 20-year Assessment Report
The board approved a slim consent agenda, but not until the 20-year transmission assessment’s report was pulled off and endorsed separately. Omaha Public Power District’s Joe Lang asked that the assessment be considered separately after SPP distributed an addendum to the report the day before.
Lang said he didn’t have any issues with the addendum, saying it explained that a simulation issue prevented a flowgate from being analyzed. Staff’s further review identified a 345-kV line as providing the most future benefits, he said.
The Markets and Operations Policy Committee unanimously approved the report three weeks ago. ITC Holdings’ Alan Myers, the committee’s chair, told the board the addendum wouldn’t have “materially changed anybody at MOPC.” (See “20-year Tx Assessment Endorsed,” SPP Markets and Operations Policy Committee Briefs: July 10-11, 2023.)
According to the report, SPP will need between 900 and 1,200 miles of new EHV lines that could enable carbon dioxide reductions of up to 93%. The study team evaluated 463 solutions during its 35-month analysis; It found the solutions could cost as much as $1.55 billion in engineering and construction costs across its reference case and emerging technologies cases, with a benefit-to-cost ratio of $1.57 billion to $4.35 billion.
The assessment does not request notifications to construct, but it did recommend 13 new transmission projects to resolve congestion and other constraints. The board’s consent agenda also resulted in approvals of:
Sunflower Electric Power’s Ray Bergmeier and City Utilities Springfield (Mo.) to fill vacant seats on the Strategic Planning Committee as transmission-owning and transmission-using members, respectively;
A sponsored upgrade study for Omaha Public Power District for 161-kV work in Omaha, Neb.; and
Withdrawing Lea County (N.M.) Electric Cooperative’s notification to construct for a 115-kV network upgrade following another project’s cancellation.
PJMpresented several changes to its Critical Issue Fast Path (CIFP) proposal during the process’ meeting Thursday, reworking portions related to the seasonal market, weatherization, site visits, performance assessments and market power mitigation.
Getting through a portion of PJM’s 79-slide presentation spanned the entirety of the meeting, postponing presentations from Constellation Energy and the Independent Market Monitor to the next CIFP meeting Tuesday. Additional sections of PJM’s presentation pertaining to reliability risk modeling and accreditation were moved to Tuesday’s meeting, which is set to include presentations from Vistra, Buckeye Power and Leeward Renewable Energy. (See PJM Updates Risk Analysis; Stakeholders Present Revised CIFP Proposals.)
Following Tuesday’s meeting, only one Stage 3 meeting remains on the calendar, set for Aug. 7. The following week will be saturated with standing committee meetings, with Aug. 13 being the final day for agenda items and documents to be added to the materials for the Stage 4 meeting on Aug. 23. In that meeting, stakeholders will present to the PJM Board of Managers and subsequent Members Committee meeting, which will include the vote to recommend a package to the board.
The Stage 4 meeting will begin with a detailed presentation of PJM’s proposal, after which only members and invited non-member stakeholders will be allowed to continue participating. A sign-up form will be emailed to stakeholders subscribed to the CIFP and MC mailing lists.
Seasonal Auction Design Shifts to MRI Curves over VRR
PJM Vice President of Market Design Adam Keech said the new seasonal design stemmed from stakeholder concerns that PJM’s proposal was overly complex and not transparent. The previous iteration would have created variable resource requirement (VRR) curves for each season and aligned the price with the point on the annual VRR curve corresponding to the amount of cleared capacity. (See PJM Adds Seasonal Capacity to Stage 3 of CIFP Proposal.)
Thursday’s proposal instead would use marginal reliability impact (MRI) curves for the seasonal auctions, which would be set in advance and with no adjustments made during the auction clearing. The shape of the MRI curves generally would align with the status quo VRR slope, but the “amplitude” of the curve would be increased to ensure resources could retain the annual costs of taking on a capacity commitment in a single season in the event the other season cleared at zero.
The MRI curve for each season would be calibrated so that if the amount of capacity procured was at or lower than the reliability requirement, the corresponding price would be at least the annual net cost of new entry (CONE) for the reference resource.
PJM Director of Economics Walter Graf compared the current approach to how locational deliverability areas (LDAs) have their own VRR curves designed to ensure that the reference resource can meet its reliability requirement assuming the rest of the RTO cleared at $0 and no outside revenues would be available for resources within the LDA.
Several stakeholders expressed concern that increasing the amplitude of the curve would amount to doubling the cost consumers pay for capacity and requested PJM present more analysis on the expected reliability and cost impacts of the proposed approach.
Economist James Wilson, a consultant for state consumer advocates, gave the example of grafting PJM’s proposal onto a monthly capacity market and questioned if that would result in the possibility of a month with capacity prices increased by a factor of 12.
Graf said he believes it makes sense that the reference resource would be able to meet its annual costs in one month, under Wilson’s example, if that period is determined to hold the entirety of the grid’s reliability risk. He added that PJM’s model wouldn’t increase both the price and the quantity.
“The price in a given season is higher only if the reliability risk is higher and the quantity procured is lower,” he said.
Market Power Mitigation Changes to Must-offer for Intermittents, CPQR
The changes to PJM’s proposal also include removing the must-offer requirement for intermittent resources. Several resource types, including solar, wind and storage, are not subject to the requirement that generators must offer into the capacity market, an exception that PJM had proposed removing in earlier versions of its package. (See PJM Completes CIFP Presentation; Stakeholders Present Alternatives.)
PJM’s Skyler Marzewski said retaining the exception stems from intermittents not possessing a way of physically hedging against the risk that an emergency may occur at a time when they are not able to be online, subjecting them to capacity performance (CP) penalties. He said PJM has not determined if it intends for demand response to be subject to the requirement.
Graf said any resource that would not be required to submit an offer but intends to do so would need to notify PJM sufficiently in advance of the reliability analysis being conducted for that auction.
Emma Nix of Leeward said retaining the must-offer exception likely would lead to Leeward and a coalition of renewable developers dropping plans to offer an alternative to PJM’s proposal. “This is a giant step forward for getting renewable support for PJM’s proposal,” she said.
While the must-offer exceptions were one of the major concerns renewable developers had with the PJM package, Nix said they support requiring intermittents to participate in the capacity market in the long term, so long as the requirement is accompanied by a way of mitigating risk of performance penalties during times those resources can’t be expected to operate.
PJM added detail to its default capacity performance quantified risk (CPQR) calculation, in which it would create a default risk value for each resource class with an option for generation owners to continue to submit unit-specific values instead.
Graf said PJM would look at the 95th percentile of events to estimate a unit-specific analysis of how resources may over- or underperform during modeled performance assessment intervals (PAIs).
The amount of risk determined to be present at the 95th percentile would be multiplied by a cost-of-risk parameter, which in his demonstration Thursday was set at 10%. The cost-of-risk and other parameters in the calculation would be reviewed periodically.
Calpine’s David “Scarp” Scarpignato questioned why the result shouldn’t be the risk at the 95th percentile. Graf said competitive market sellers would be willing to have a small downside as a potential outcome at less than the full amount they stand to gain.
PJM detailed its proposed default Capacity Performance quantified risk calculation during the July 27 CIFP meeting. | PJM
Rework to Performance Assessment Testing
PJM’s proposal to require a physical demonstration that resources can meet their capacity commitments, with penalties for any shortfalls during testing, was revised to measure generators against their daily committed ICAP, rather than against their average seasonal committed ICAP. PJM’s Pat Bruno said the change was made with the understanding that a resource’s capability can change throughout a season.
The test would be based on either operational data for the relevant season provided by the generator or a demonstration that the resource schedules with PJM.
PJM also would be able to initiate two operational tests by scheduling a unit, following its parameter limits and considering the test a success if it is able to come online within a certain amount of its expected time and operates for its minimum run time. Generators would be made whole for costs incurred during testing.
Bruno said tests would be conducted at times that mirror reliability risk, such as cold weather during the winter.
A failed test would result in a forced outage ticket and the unit would be marked unavailable until it indicates to PJM that the issue behind the failure is resolved, or it successfully starts back up. PJM would be able to schedule re-tests, which would result in a capacity deficiency penalty if failed. Re-tests following a failure also would not be eligible for make-whole payments.
Bruno said the deficiency penalties are designed to be imposed following a failed re-test out of a desire to not assess large penalties against a generator for a random mechanical failure and to focus instead on repeated inability to come online.
Vistra’s Erik Heinle asked if resources would have enough time to nominate for fuel prior to a test. Bruno responded they would respect the notification times in a generator’s parameters.
Site Visitation Details
PJM gave more detail on plans to include site visits in its CIFP proposal with the goal of ensuring preparations for extreme conditions are being undertaken and to gather information on any challenges. The current thinking is to have every capacity resource visited around every five years, with a focus on newer generators.
The visits would look to ensure compliance with weatherization requirements and to evaluate if fuel arrangements are being made.
Owners would be given advance notice of any visits and any issues identified would have a “cure period” established with generator input in which no penalties would be imposed. Failure to address issues long-term could result in penalties.
Stakeholders Endorse Manual Revisions Conforming to New FERC Requirements
VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee endorsed revisions of Manual 14B to align with new language in NERC’s TPL-001-5.1 standard during its July 26 meeting. The changes aim to establish new transmission system performance requirements. (See “Stakeholders Endorse Quick Fix Manual Revisions to Conform to NERC Standards,” PJM PC/TEAC Briefs: July 11, 2023.)
The new language increases the requirements for PJM’s spare equipment standards, creates a new threshold for new outages to be included in the planning horizon and expands the technologies considered part of a component protection system.
The previous NERC standard required that RTOs include outages longer than six months in their planning horizon, which was changed to leave the rationale up to the organizations. PJM proposed looking at upgrades to 230-kV or higher rated equipment or outages that would last longer than five days.
The proposed spare equipment standard would involve PJM reaching out to asset owners to inquire about their policies for maintaining spare equipment to replace any failures that could take a year or two to replace. If those owners don’t maintain an inventory, PJM would conduct a study to evaluate the impact of that equipment failing.
The changes were brought before the July Planning Committee meeting as a quick fix proposal, which allows for a problem statement, issue charge and solution to be brought concurrently and voted on in the same meeting. The manual changes were effective immediately following MRC endorsement.
PJM and Monitor Present Generation Deactivation Issue Charge
PJM’s Paul McGlynn gave a first read of a problem statement and issue charge being drafted in collaboration with the Independent Market Monitor that would investigate increasing the deadline for generators to notify PJM of plans to deactivate, the compensation for generation owners that agree to continue operating facilities beyond the desired deactivation and the triggers offering a generator a reliability-must-run (RMR) contract.
Possible changes to capacity market rules and cost allocation for RMR contracts are out-of-scope in the issue charge. McGlynn said a new senior task force reporting to the MRC is the envisioned route for engaging in the discussion given the number of areas that deactivations impact, including planning, markets and operations.
The only reason PJM currently can provide for seeking an RMR is transmission reliability criteria, but McGlynn said there may be other reasons it wishes to keep a generator operating. The primary rationale the RTO envisions is losing reliability parameters such as black start when a generator goes offline.
Monitor Joe Bowring said the current rules create a lot of confusion and uncertainty, which results in resources being wasted on proceedings. “The rules need to be clarified,” he said.
Vistra’s Erik Heinle questioned if there would be a limiting principal in how long an RMR contract could run for, adding that it could take a long time to replace the black start service provided by a given generator while also discouraging other resources interested in investing to provide that service.
“Before we go down this route, we need to be careful to think of where we may end up,” he said. “We need to be careful of what signals we’re sending to the market.”
McGlynn said PJM’s goal is to keep RMR contracts as limited in use and duration as possible.
“Nobody wins when there’s an RMR. In general, the generators — they’ve already made the decision to deactivate, they want to deactivate it,” he said.
Bowring said he’s concerned about broadening the scope of RMR and believes it should be as narrow as possible but is willing to discuss options.
Dominion’s Jim Davis questioned if part of the rationale for re-evaluating how RMR contracts function is to slow the pace of retirements or make it take longer for them to exit the market. He said the company would not support any changes that could hinder generators’ ability to retire and that one of the purposes of a functional capacity market is to send price signals, including for retirement.
“Ultimately, the decision to retire a resource belongs to the resource owner and that decision is partially made to redirect capital,” he said.
McGlynn said the intent is to look at the process after the decision to retire has been made and support that determination. Senior Vice President of Market Services Stu Bresler added that the longer notice period for deactivation requests is meant to ensure the grid is prepared for resources to go offline.
Susan Bruce, of the PJM Industrial Customers Coalition, said it’s important RMR doesn’t become more attractive than market participation for some resources. She supported discussion of additional triggers for opening an RMR contract and said it also may be prudent to make capacity market changes in scope, given the large changes being considered in the Critical Issue Fast Path (CIFP) process and elsewhere.
Stakeholders also questioned if the voluntary nature of RMR contracts would be in scope, to which McGlynn said his understanding is that PJM can’t force generators to continue operating. Bresler said the issue charge doesn’t explicitly preclude having that discussion but that it may be a question for FERC to decide if PJM has the authority.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said he believes not explicitly ruling out discussion of permitting RMR contracts to maintain resource adequacy is “extremely dangerous” and should be out of scope. The capacity market has its own backstop and RMR should be focused on transmission needs, he said.
Several stakeholders also questioned if the complexity of the topic may not lend itself to the “CBIR Lite” (Consensus Based Issue Resolution) process.
PJM Seeks Stakeholder Process on Reserve Certainty
PJM’s Donnie Bielak presented a wide-spanning issue charge and problem statement on reserve certainty, with several immediate, medium-term and long-term goals for stakeholders to consider in a proposed new senior task force. PJM has seen a decline in the response rate for reserve deployments since the two tiers of reserves were consolidated in a reserve market overhaul implemented Oct. 1. That resulted in PJM increasing the synchronized reserve requirement by 30% this year, overriding stakeholder objections. Bielak said it’s likely nobody was happy with that outcome, and the goal of the new issue charge is to find better permanent solutions. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.)
The seven key work activities include reserve performance and penalties, aligning the offer structure with fuel procurement, how resources are deployed and PJM’s target reserve procurement. The proposed timeline for immediate need topics, such as performance and penalties, is to have a solution within a year, while the long-term need to incentivize resource flexibility to match grid needs is set for three to five years.
Heinle said he’s concerned such a wide range of topics could lead to the task force becoming directionless, a fate he said befell the resource adequacy senior task force before it was converted to the CIFP process with a tight turnaround mandated by the Board of Managers. He suggested that finding ways of keeping the work focused on specific areas would help prevent the process from outrunning stakeholders’ best intentions.
Sotkiewicz said he believes more education on the impact of the reserve market changes implemented in October is needed and that the lower response rate could stem from a software or design issue in the new system. He said prices are decreasing leading up to a spin event, which is the opposite of what should be happening. He said PJM rhetoric about generators underperforming and the possibility of enforcement actions has been unhelpful.
“I think there’s something actually much more systemic here that requires more investigation and education … for members to understand that,” he said.
Bruce said more analysis is needed to understand the dynamics of how the increasing number of inverter-based resources on the grid impacts reserves and what their contribution looks like. More education also is necessary to understand what is driving the lower performance. She said she worries if that is not established, it could lead to consumers spending more money on reserves to shore up the issue.
“The solution cannot be let’s just have customers pay more for reserves. Because if we don’t understand what the problem is … that’s just throwing money at the problem,” she said.
Bowring said the issue charge is too broad and should be broken into smaller stakeholder processes. He said he believes synchronized reserves’ failure to respond in recent months has to do with communications and training.
First Read on Peak Market Activity Credit Activity Proposal Expected in August
The Risk Management Committee (RMC) has finalized a slate of packages it plans to vote on during its August meeting, which will be followed by a first read at the MRC during its Aug. 24 meeting. Thomas Zadlo, RMC chair, said PJM is exploring ways of expediting a vote at the RMC to either hold a same-day vote in August following the first read or use other accelerated stakeholder actions to allow the proposal to be implemented in time for winter.
Constellation’s Adrien Ford said the company supports any acceleration that can be found while still respecting the need for appropriate document review.
Proposed changes include introducing minimum exposure and minimum transfer amounts, setting maximum amounts that can be invoiced over given timeframes and changing how collateral shortfalls and surpluses are calculated.
Other MRC Discussions:
Several state consumer advocates objected to or abstained from endorsing revisions to Manual 13 stemming from its periodic review, which Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said was due to dissatisfaction that the review of the manual did not take into account how emergency notifications and public messaging performed during the December 2022 winter storm. The changes were approved by acclamation as part of the consent agenda.
PJM presented a first read of proposed revisions to Manual 13 to include essential actions in NERC’s cold weather preparations for extreme events. Changes focus on the amount of detail needed in member load-shed plans.
Members Committee Endorses IROL-CIP Cost Recovery
The Members Committee voted to endorse a PJM-sponsored proposal to create a cost-recovery mechanism to allow generators to recoup expenses incurred by making upgrades after being designated critical to the derivation of an interconnected reliability operating limit (IROL) under NERC’s critical infrastructure protection (CIP) standards. The acclamation vote had six objections and 11 abstentions. (See “MRC Endorses IROL-CIP Cost Recovery,” PJM MRC/MC Briefs: June 22, 2023.)
PJM’s Darrell Frogg, who presented to the MC Wednesday, has compared the cost-of-service payment structure in the proposal to the cost-recovery structure for black start service, with generators submitting their costs to the RTO and Monitor to review and costs allocated to market participants.
The proposal was opposed by the Monitor, who presented a competing proposal in the Operating Committee, on the grounds the costs should be included in generators’ market offers and it could become a slippery slope to new non-market cost-of-service structures for other services, a concern he returned to Wednesday. He argued there is no explanation for what differentiates IROL-CIP-related costs from other services generators include in their offers.
Bruce said some industrial customers abstained from the vote over concerns the process PJM uses to select IROL-CIP facilities may lead to increased costs if PJM designates one generator, it makes the requisite upgrades and then PJM shifts the designation to a different resource. She said the “heartache” isn’t with having to pay for reliability upgrades, but rather with cost minimization.
Poulos said some advocates who abstained from the MRC vote switched to being in opposition because of a concern the proposal turns away from using markets and toward a less transparent cost-of-service approach.
PJM Assistant General Counsel Thomas DeVita said he believes the proposal included a healthy balance between allowing generators to recover costs while protecting consumers. He said costs incurred before the critical designation or those that would have been made regardless can’t be included and the proposal also includes provisions to avoid double counting.
“We have some very significant and serious protections built in for customers,” he said.
The National Highway Traffic Safety Administration (NHTSA) on Friday issued a proposal for a major increase in national fuel efficiency standards for cars, light-duty trucks and some heavy-duty vehicles, aimed at saving drivers money on gasoline while cutting both U.S. greenhouse gas emissions and dependence on foreign oil.
The 696-page Notice of Proposed Rulemaking would require automakers to hit a fleetwide fuel Corporate Average Fuel Efficiency (CAFE) of 66.4 mpg for passenger cars and 54.4 mpg for light-duty trucks for their 2032 models.
The standard for heavy-duty pickups and vans (HDPUVs) — defined as between 8,501 and 14,000 pounds — would taper off from 4.4 gallons needed to drive 100 miles in the 2030 model year to 2.6 gallons in 2035.
However, the NHTSA qualified those numbers by noting “that real-world fuel economy is generally 20 to 30% lower than the estimated required CAFE level.”
The NHTSA requirements for fuel efficiency for 2023 models are 50.5 mpg for passenger cars and 35.8 mpg for light-duty trucks, according to figures from the Department of Energy. According to the NHTSA, passenger cars include sedans, station wagons and two-wheel drive crossovers and SUVs, while the light-duty truck category covers four-wheel-drive SUVs, small pickup trucks, minivans, and passenger and cargo vans.
The proposed standards, covering model years 2027-2032, would push automakers to improve fuel efficiency 2% per year for passenger cars and 4% per year for light-duty pickups. The standards for HDPUVs would tighten 10% per year from 2030 to 2035.
The current standards for passenger cars and light trucks end in 2026. The NHTSA said the 2030 starting date for the HDPUV standard is because of “statutory lead time constraints” but did not provide further details.
Previous CAFE standards have set combined fuel efficiency targets for passenger cars and light trucks. However, the NHTSA said, it was setting different standards for the two categories because “manufacturers have already made substantial progress in technology application to passenger cars, such that the possibility for further fuel economy improvements … is relatively limited.
“The agency believes that there is more room to improve the fuel economy of light trucks, in a cost-effective way, and that the benefits of requiring more improvement from light trucks will be significant given their high usage and the fact that they make up an ever-larger percentage of the overall fleet.”
The combined standard for passenger cars and light trucks would be 57.8 mpg in 2032, the agency said.
The NHTSA estimates that the proposed standards would slash fuel consumption by 88 billion gallons for passenger cars and light-duty trucks and 2.6 billion gallons for HDPUVs through 2050. The resulting reductions in carbon dioxide emissions would be 885 MMT for passenger cars and light-duty trucks and 22 MMT for HDPUVs.
The agency estimates that savings from the proposal would exceed costs by $18 billion but that the savings consumers see at the pump would be more modest. For example, lifetime fuel savings of $1,043 for more efficient passenger cars would be offset by an increased cost of $932, delivering net savings of $111 in the 2032 model year. Lifetime net fuel savings for HDPUVs would be about $300 in the 2038 model year.
The release of the NOPR starts a 60-day comment period, and the NHTSA will hold at least one virtual public hearing during that time.
EPA estimates those standards would cut emissions from light- and medium-duty vehicles by 7.3 billion MT of CO2 between 2027 and 2055 and projects net benefits of $1.6 trillion. Proposed standards for heavy-duty vehicle rules would save 1.8 billion MT of CO2 and yield $320 billion in benefits.
“I want to make clear that EPA and NHTSA will coordinate to optimize the effectiveness of both agency standards while minimizing compliance costs,” acting NHTSA Administrator Ann Carlson told The Associated Press.
The proposed levels were chosen as both technologically and economically feasible, the agency said, noting that by statute, it is not allowed to factor electric vehicles into its efficiency standards, a major difference with the EPA standards, which are aimed at boosting vehicle electrification.
At the same time, automakers can use electric vehicles to meet the standards, the NHTSA said.
Reactions
Sen. Ted Cruz (R-Texas) slammed the proposal as an attack “on affordable gas-powered cars and trucks” and a “de facto EV mandate” that would raise prices and hurt national security.
John Bozzella, CEO of the Alliance for Automotive Innovation, said efforts to align the two standards are “encouraging” but they could still cause problems and extra costs for automakers and consumers.
“Conflicting and overlapping rules are complex and expensive,” Bozzella said in a statement released Friday. “If an automaker complies with EPA’s yet-to-be-finalized greenhouse gas emissions rules, they shouldn’t be at risk of violating CAFE rules and subject to civil penalties that levy costs on consumers and manufacturers — but deliver no corresponding environmental benefits.”
He called for “a single national standard to reduce carbon in transportation — one vehicle fleet and one national standard.”
While earlier raising concerns about penalties for automakers not meeting the NHTSA standards, General Motors released a statement Friday welcoming “the intent to align NHTSA and EPA standards and providing flexibility to industry to achieve these targets.”
The company has committed to selling only all-electric new vehicles by 2035.
The D.C. Circuit Court of Appeals on Friday denied a pair of petitions by the Rhode Island-based company Green Development over FERC’s approval of transmission charges connected to a proposed solar project. The court determined that Green Development’s four main issues with FERC’s approval lacked merit.
Green Development is the developer of four solar projects totaling about 40 MW in Rhode Island. The company requested to connect the projects to the local distribution system, owned and operated by Narragansett Electric Co., a former subsidiary of National Grid now owned by PPL Electric Utilities under the name Rhode Island Energy.
Narragansett and New England Power, also a subsidiary of National Grid, determined the solar project would require significant upgrades to the distribution and transmission systems, including a new substation, costing about $18 million, with the costs ultimately passed down to Green Development.
FERC denied the bulk of Green Development’s arguments opposed to this cost allocation in orders issued in September 2021 and February 2022. The commission upheld its findings of both orders upon rehearing (EL21-47 and ER22-707).
Green Development’s petition to the D.C. Circuit, argued in March of this year, alleged FERC mischaracterized some of the company’s arguments, failed to justify its jurisdiction over the upgrades, misinterpreted the definition of “direct assignment facilities” in the ISO-NE tariff and that the RTO and New England Power failed to file a new application for transmission service in accordance with the tariff.
In its ruling on Friday, the D.C. Circuit sided with FERC, rejecting all four of these clams.
“Each of Green Development’s four grounds for vacatur lacks merit. Accordingly, we deny the petitions for review,” wrote Circuit Judge Karen L. Henderson.
Green Development declined to comment on the ruling.
ST. PAUL, Minn. — SPP legal staff said last week it is evaluating whether to modify and refile a tariff revision to allocate “byway” transmission projects on a case-by-case basis or to seek a rehearing of the order.
General Counsel Paul Suskie told the grid operator’s Regional State Committee July 24 that staff is reviewing its options following FERC’s rejection of its proposed methodology. (See FERC Reverses Course on SPP Byway Cost Plan.)
“We will do that in our ordinary course,” Suskie told the committee, composed of SPP’s state regulators. “From a timing perspective, we could probably get a result back from FERC and an approval rather than going through the appeal process.”
Asked whether SPP could work the two paths in parallel, Suskie warned the RSC that doing both at the same time would create ex parte limits when communicating with FERC.
In a July 13 order, FERC unanimously reversed a 2022 decision approving the RTO’s process to allocate byway transmission projects — facilities rated at 100 to 300 kV — after rehearing arguments raised by several SPP members. The commission rejected SPP’s proposed methodology without prejudice and dismissed a November compliance filing as moot (ER22-1846).
FERC said SPP failed to prove its proposal to regionally allocate 100% of a byway facility’s costs on a postage-stamp basis would result in outcomes that are just and reasonable and not unduly discriminatory or preferential.
The grid operator currently allocates one-third of byway projects’ cost to the RTO footprint, with customers in the transmission pricing zone where the project is built being allocated the rest. “Highway” projects — those larger than 300 kV — are allocated RTO-wide.
RSC and its Cost Allocation Working Group have been working on the issue since 2017. It was one of 21 initiatives developed by the Holistic Integrated Tariff Team before the COVID-19 pandemic. Stakeholders and staff have produced reports and white papers that led to an earlier tariff revision being rejected by FERC in 2021.
“It’s probably an understatement to say I’m disappointed to see the FERC action,” said RSC President Andrew French, with the Kansas Corporation Commission. “I do think we have an opportunity here to see if maybe there’s a better approach, maybe even an approach that could address some of the concerns in our stakeholder process and hopefully we come up with something better. This is something that we have developed an extensive record on.”
Dana Shelton, legal counsel to the Louisiana Public Service Commission, pointed out that the agency, along with those of New Mexico, Oklahoma and Texas, opposed the revision request when it came before the CAWG in December 2021. FERC Commissioner Mark Christie noted the lack of “uniform” state support for the proposal in a concurrence to the order.
“It was on what we view as illegitimate cost-allocation principle … and an unjust and unreasonable rate allocation,” Shelton said. “We do continue to have concerns along those lines. I would ask that SPP and all concerned keep that in mind.”
“It was an issue of cost allocation and equitable treatment for utilities,” Texas Commissioner Will McAdams said. “Texas shared those concerns and would stand on that position.”
McAdams Elected RSC’s Vice President
RSC members elected McAdams as their vice president. He replaces Geri Huser, who stepped down from the Iowa Utilities Board in May, four years short of her term’s expiration.
Minnesota’s John Tuma was elected to replace McAdams as the committee’s secretary and treasurer.
SPP CEO Barbara Sugg recognized McAdams during her president’s report to the board for his “exceptional leadership” of the stakeholder group addressing the RTO’s resource adequacy issues. (See SPP REAL Team Endorses Winter Resource Requirement.)
“I have heard nothing but accolades for your leadership,” she said. “I’m just so impressed with the joint nature of that group and the value that they are going to bring to the RSC, to the board, to the Members Committee, really to all SPP stakeholders.”
The RSC also approved South Dakota’s Kristie Fiegen to chair the nomination committee that will select officers for 2024. Arkansas’ Justin Tate and Oklahoma’s Todd Hiett will serve with Fiegen.
Xcel Energy highlighted a busy day for utility earnings calls Thursday with weaker results the company blamed on inflationary pressures and a lower-than-expected return on equity from a rate case in its home state of Minnesota.
The Minnesota Public Utility Commission in June approved a $306 million, or 9%, rate increase over three years for Xcel, below recommendations from the state’s Department of Commerce and an administrative law judge. Xcel initially requested a $677 million, or 21%, increase before dropping its ask to $498 million and then $400 million.
The Minneapolis-based company reported earnings of $288 million ($0.52/share) for the quarter, down from $328 million ($0.60/share) from a year earlier.
CEO Bob Frenzel said the company is working to offset the effects of the headwinds and is continuing to “lead the nation’s clean energy transition.”
In June, the PUC also approved Xcel’s plan to construct a multi-day energy storage system that will test Form Energy’s 10-MW/1,000-MWh iron-air battery system at the utility’s 710-MW Sherco solar site. The battery is expected to come online in 2025. (See “Long-duration Storage is Key,” Overheard at EEI 2023.)
“We’ve always been focused on new technology, new research, development and deployment of new technologies to achieve our 100% goal,” Frenzel said, referring to the company’s first-in-the-nation commitment to 100% carbon-free electricity. “Long duration energy storage is a critical part of the energy future. A 100-megawatt-hour battery … [is] a nice asset class as we think about periods when the wind doesn’t blow and the sun doesn’t shine.”
Frenzel also addressed a recent report following an investigation by the Boulder County (Colo.) Sheriff’s Office into a 2021 wildfire that caused about $2 billion in property losses. The report found Xcel subsidiary Public Service Company of Colorado (PSCo) responsible for one of two ignitions. Xcel disclosed the report in its earnings release and said that if PSCo is found liable and is required to pay damages, the amounts could exceed insurance coverage of approximately $500 million.
“Because of the pending litigation that has been filed, we’re not in a position to discuss the fire in more detail at this time,” Frenzel said. “We will vigorously defend ourselves and move forward to presenting our position in court.”
Xcel’s share price dropped $2.18 (3.35%) during a down day on Wall Street, closing at $62.87. The Dow Jones Industrial Average lost 237 points, ending a historic streak of 13 straight gains.
AEP Continues with Asset Sales
American Electric Power said Thursday that the “de-risking” and “simplification” of its business continues to pick up speed with two non-core transmission ventures being put up for sale.
CEO Julie Sloat told financial analysts during the company’s quarterly earnings call that AEP will soon launch the sale of its interests in the Prairie Wind and Pioneer transmission projects. The former are 345-kV facilities in Oklahoma and the latter 765-kV facilities in Indiana.
AEP could also soon put its share of Transource Energy, a competitive transmission developer, on the block once it completes a strategic review.
AEP also plans to close the sale of its 1.37-GW unregulated renewables portfolio to IRG Acquisition Holdings in August and is on track with other transactions involving its AEP Energy retail and AEP OnSite Partners distributed resources businesses and its 50% share in the New Mexico Renewable Development joint venture.
“Our ongoing active management of the company strengthens our ability to prioritize investments in our regulated businesses,” Sloat said.
The Columbus, Ohio-based company delivered second-quarter earnings of $521 million ($1.01/share), compared with earnings of $525 million ($1.02/share) for the same period a year ago.
During the quarter, AEP received regulatory approval to add nearly 2 GW of new wind and solar generation in Oklahoma, Arkansas and Louisiana. It also has approvals in place for $5.2 billion of its five-year, $8.6 billion regulated renewables capital plan and has filed for approval of $1.7 billion in additional renewable projects.
AEP’s share price closed Thursday at $85.26, a drop of $2.35 (2.6%) on the day.
CenterPoint Energy Takes $74M Hit
CenterPoint Energy (NYSE: CNP) also reported quarterly financial results on Thursday, delivering earnings of $106 million ($0.17/diluted share) that included a loss and expense of $74 million ($0.12/share) related to the divestiture of Energy Systems Group (ESG).
The Houston utility earned $179 million ($0.28/diluted share) during the second quarter a year ago.
CenterPoint sold its interest in ESG for about $157 million to EEG Holdings in May. ESG offers energy efficiency and sustainable energy solutions.
The utility’s share price closed at $30.36 Thursday, an 85-cent loss.
