The Public Utility Commission of Texas last week approved an unopposed agreement over Southwestern Electric Power Co.’s (SWEPCO) request to reconcile its 2020-21 fuel costs related to the retired Pirkey coal plant, but rejected an administrative law judge’s proposed order that found the plant’s retirement prudent (53931).
Opponents of SWEPCO’s 2020 decision to retire the plant in East Texas contended the plant still had years of useful life.
Among the opponents was Commissioner Will McAdams, who said in a memo last week that because the utility’s action was not prudent, it should not be allowed to recover carrying costs from the mine that provided its fuel.
“I understand that the prudent standard is not a high bar, but the lack of depth in the 2020 analysis, especially when you’re retiring a plant 12 years early, it simply did not sit well with me,” he told his fellow commissioners Thursday.
McAdams said SWEPCO could have re-examined its analysis after the February 2021 winter storm “exposed reliability and resiliency issues of a kind never seen before and reinforced the need for existing dispatchable generation.” He said the utility’s decision to continue with its application as if the storm had not occurred “lacks fundamental credibility and common sense.”
“Had SWEPCO acted prudently, it would have updated the analysis based on the new reliability needs of grids, the volatility of the 2021 natural gas market, increased construction costs, supply chain issues and inflation,” he said. “It tells me that SWEPCO knew what outcome they wanted to achieve and may have nudged the analysis parameters to match that.”
The plant retired last spring after 38 years of operation.
It signed off on unopposed agreements filed by South Texas Electric Cooperative (54936) and AEP Texas and Electric Transmission Texas (55001) for their proposed routes. The utilities are building new double-circuit 345-kV transmission lines and related facilities in South Texas.
New Jersey has awarded $12.7 million in grants to install electric vehicle chargers at 405 new locations, including multiunit dwellings and tourism hot spots, as the state seeks to dramatically increase EV use in the face of some opposition to the move.
The New Jersey Board of Public Utilities (BPU) made the awards in three programs designed to provide incentives for specific market sectors believed to be key to creating a critical mass of EV chargers. The awards were made in the program’s third round, from the 2023 budget, and the agency is accepting applications for the 2024 funding round, which closes Nov. 30.
The targeted sectors include: multiunit dwellings, because they are tough for EV-owning occupants to install their own chargers in; tourism sites, to encourage EV drivers who might balk at coming to New Jersey visitor attractions for fear they won’t be able to recharge; and publicly owned fleets supporting local governments, which can lead by example, showing residents the benefits of EVs.
BPU President Christine Guhl-Sadovy announced the awards Monday, saying they are part of the agency’s effort to ensure drivers in all corners of the state have a place to plug in. The state had 2,047 Level 2 chargers and 972 Direct Current Fast Chargers in June, or about one charger per 3,050 residents, according to EvaluateNJ, an EV information website run by Atlas Public Policy.
“As we strive to combat the increasingly devastating impacts of climate change, reducing barriers to using an EV by building a robust network of public charging stations and supporting municipalities in electrifying their fleets remains a key focus of our clean energy agenda,” Guhl-Sadovy said.
The funding outlined Monday would increase the state’s charger total by about 13.5%.
Convenient, Affordable Charging
Last week, Gov. Phil Murphy (D) outlined a $10 million funding allocation to the state Department of Environmental Protection, about 80% of which went to “workplace and multi-dwelling charging station projects across the state.” He said the state is trying to make “the transition to electric vehicles more accessible and affordable than ever.” A BPU spokesperson said the two programs are unrelated.
The DEP’s EV charging funds go through the agency’s “It Pay$ to Plug in” program, which offers up to $4,000 for the installation of a single-port charger. The program has awarded about $14 million, funding the installation of 1,261 charging stations with 1,891 ports at 389 locations, according to the DEP.
“Convenient and affordable charging at home and at the workplace is core to our overall charging ecosystem, since that’s where the majority of charging will occur,” DEP Commissioner Shawn M. LaTourette said in a release at the time. “We must continue to act with the sense of urgency the climate crisis demands.”
About 37% of New Jersey’s carbon emissions are generated by transportation. The BPU’s EV charger announcement comes as the DEP moves to enact California’s Advanced Clean Cars II (ACC II), which requires that EVs account for a steadily rising share of new car sales until 2035, when all new vehicles bought in New Jersey must be EVs.
The rules, which eight states have adopted, is opposed by businesses, car dealers and fossil fuel interests, who say consumers aren’t ready for the move and the state doesn’t have the grid or charging infrastructure to cope with such a dramatic increase in EVs. (See NJ’s Push Toward Clean Cars Rule Sparks Vigorous Debate.)
Wine, Farming And A 280-year-old Restaurant
The round of BPU funding detailed Monday was about the same as in the previous round, which awarded $12.65 million through the three programs for the collective installation of 1,150 Level 2 and DCFC chargers and 106 public vehicles.
About half of the money outlined Monday — about $6.1 million — will pay for the installation of more than 1,300 chargers in multiunit dwelling residences. The agency’s MUD EV Charger Incentive Program awards up to $4,000 for a dual-port, Level 2 charging station in a multiunit development and up to $6,000 if it is in an overburdened community.
The Electric Vehicle Tourism Program, which provides up to $5,000 for a Level 2 charger and up to $50,000 for a Direct Current Fast Charger, awarded nearly $800,000 in two phases of the announced funding. The money will trigger the installation of 37 chargers, including: four Level 2 chargers at Phillips Farms, a 300-acre Central Jersey family farm that allows you to pick your own fruit and vegetables; two Level 2 chargers and two DCFC’s at Beneduce Vineyards, a fourth-generation winery in South Jersey; and two DCFCs at The Clinton House, a historic restaurant first opened in 1743. (See NJ Seeks to Lure Tourists with EV Chargers.)
The $5.75 million awarded in the Clean Fleet EV Incentive Program will fund local schools, municipal commissions, state agencies or boards, and other local government bodies to help transition their fleets to EVs. The program awards up to $4,000 for the purchase of a light-duty EV, up to $10,000 for a Class 6 electric truck, up to $5,000 for a Level 2 charger and up to $50,000 for a DCFC.
The 36 grants will pay for 140 EVs, 25 DCFCs and 124 Level 2 chargers. The recipients include the Passaic Valley Sewerage Commission, which received $1.4 million for five EVs, eight DCFCs and 15 Level 2 chargers. New Jersey Transit, the state’s mass transit agency, received about the same for 20 EVs, six DCFCs and 15 Level 2 chargers.
New York state has issued the roadmap for its first-in-the-nation school bus electrification program and is preparing to draw the first tranche from a $500 million pot of money to start carrying it out.
The $100 million announced Thursday will be enough to replace only several hundred of the 45,000 fossil-powered school buses in the state. Electric buses are quite expensive, so the state is providing substantial vouchers to help fleet operators buy them.
These early efforts are not intended to fully electrify the nation’s largest school bus fleet. Rather, the goal is for every fleet operator to gain experience with a handful of electric buses before 2027, when the sale of internal-combustion school buses will be banned in New York.
The hope also is that electric vehicle technology and grid infrastructure will evolve over the next four years to the point the lifetime cost of owning and operating electric school buses (ESBs) decreases to parity with internal combustion engine (ICE) school buses.
Then the special incentives for conversion can be reduced.
New York state in 2022 mandated the gradual conversion of the school bus fleets operated by hundreds of school districts and private contractors. It’s a step toward meeting the goals of the state’s 2019 climate protection law, protecting the health of children who ride buses and improving the air quality in neighborhoods near bus depots.
Later in 2022, state voters approved a $4.2 billion bond act for environmental projects, $500 million of which was designated for ESBs.
Other states since have enacted phase-outs of their own, but New York was first. ICE school buses will be banned from roads in the Empire State in 2035.
Program Details
ESB adoption is in its early stages.
The World Resources Institute estimates only 69,000 of the 20 million-plus U.S. children who ride buses to school each day are riding emissions-free.
New York had just 310 ESBs by the most recent count, according to the New York State Energy Research and Development Authority, which issued the ESB Roadmap in mid-September.
The roadmap guides the ESB program through 2027. It focuses on helping fleet operators afford their first few ESBs so that they, utilities and the state itself can gain experience and plan the wider buildout.
The most popular category of bus — the full-length Type C — runs in the $140,000 range with a diesel, gasoline or propane engine when purchased through one of New York’s school bus dealers. The cost jumps into the high $300s or low $400s with a battery electric drivetrain, depending on options chosen.
The base-level voucher offered by NYSERDA for purchase of an electric Type C bus in this first round of funding is $156,000. Up to $125,000 can be added through four bonuses for being a high-needs priority district, scrapping an ICE bus, adding vehicle-to-grid capacity and installing wheelchair capacity.
With the vouchers, an ESB might cost a fleet operator no more than an ICE bus.
A chart shows the demand for various sizes of school buses and the cost of electric versions. | NYSERDA
Additional aid will be available for charging infrastructure, but that portion of the program still is being developed.
(Hydrogen fuel cell buses also will be eligible for vouchers if any come to market.)
The early stages of the program are intended to focus on easy-to-electrify routes — those that will not test the range of present-day bus battery systems.
NYSERDA hopes to have up to 3,000 ESBs on the road by 2027, which with charging equipment would represent a roughly $780 million incremental cost over 3,000 similarly sized ICE buses. State and federal funding streams are expected to cover most of the added cost.
Challenges And Opportunities
NYSERDA expects to update the ESB roadmap in 2026, by which time it hopes to better understand best practices and costs from the early adopters’ experiences.
The 2023 edition of the roadmap outlines some of the challenges facing the ambitious goals and some of the early opportunities to overcome those hurdles:
New York school buses travel an average of 80 miles a day, which is within the 100- to 200-mile range of current ESB models.
The cold winters and hilly roads in the northern part of the state could reduce range. But range is expected to improve steadily: Federal data show improvements almost every year. From 2011 to 2022, the median range of electric vehicles offered for sale in the U.S. rose from 68 to 257 miles and maximum range from 94 to 520 miles.
The cost of ownership is something of a three-dimensional chess game. Upfront costs for ESBs are higher but maintenance costs are lower. To recoup the upfront cost, the service life must be maximized. ICE school buses average only 8.9 years on the road in New York — many are retired in good working order because of rust. So, it is best to use an ESB on longer routes to maximize return on investment — but not so long as to risk a dead battery.
Outside New York City, 96% of school buses are parked an average of 12 hours overnight every night — a long, predictable period ideal for a slower Level 2 recharge, when time-of-use rates are lower. More than half of New York’s school buses also are parked for four or more midday hours, presenting a window for a partial Level 2 recharge or more-complete Level 3 recharge.
Charger costs can range from $5,000 for a Level 2 unit to $100,000 for a Level 3 unit. Ideally, there is one plug per bus, but some fleet operators have found success with a combination of Level 2 and Level 3 chargers that add up to less than one plug per bus.
Recent problems for early adopters center on limited selection and availability — ESB manufacturers need clearer signals on market demand.
Future constraints as the 2027 and 2035 deadlines approach may include domestic content requirements, shortages of skilled labor for installation, permitting delays and extended timelines for transmission infrastructure upgrades.
Most school bus depots across the state lack the electrical capacity to charge more than a few buses, and many are in areas with limited grid capacity. There is no comprehensive database showing where these depots are and how many buses typically are parked there.
But the state Public Service Commission in April 2023 launched a planning process to address the charging needs of the medium- and heavy-duty vehicle sector.
Beyond the initial stages, electric infrastructure may range from 15% to 30% of the total cost of fleet electrification. This will be closely monitored.
Only 11% of fleet operators surveyed have assessed the electrification needs of their depots and their bus fleet.
With current technology limitations, fossil-fired cabin heaters may be needed for winter operation in the first generation of ESBs — battery-powered heaters would further limit mileage range already diminished by cold weather. This is counter to the whole point of bus electrification, but heaters can be turned on or off as needed while the bus is rolling, unlike the engine in an ICE bus.
Finally, the state has potentially put itself in a bind when it comes to paying for all of this.
NYSERDA expects the incremental costs of the first wave of ESBs — the 3,000 it hopes to see on the road by 2027 — will be covered by federal funds, utility incentives and the $500 million from the bond act.
That leaves 40,000 more electric buses to be purchased over the following eight years, and an untold number of megawatts of charging infrastructure to be installed. Whatever the eventual savings turn out to be, the up-front cost will be greater — high enough in some cases to cause sticker shock.
Public school budgets are subject to voter approval in New York state, as are supplemental capital spending proposals such as for a new building, roof replacements, a dozen electric school buses or rewiring a bus depot.
NYSERDA will help educate school district administrators and the public about the cost-benefit relationship in this conversion, and suggests districts conduct voter outreach of their own.
The state will focus its support of electrification in historically environmentally or economically burdened areas and those that are most at risk from transportation emissions.
Texas regulators last week directed ERCOT to not include scenarios assuming the loss of more than 8 GW of fossil generation as the grid operator’s staff continues to develop a reliability standard.
ERCOT briefed the Public Utility Commission on its reliability standard study modeling results during Thursday’s open commission meeting. Staff shared the outcome of the 48 scenarios they developed for the analysis and recommended that an additional study iteration be performed (54584).
However, the commissioners balked at the inclusion of an aggressive 8.3-GW figure for assumed coal and gas units’ retirement. The figure is based on EPA’s proposed rules limiting greenhouse gas emissions and other regulations. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.)
Commissioner Will McAdams said, “There’s no way the Public Utility Commission of Texas is going to allow this to happen.”
Commissioner Lori Cobos agreed with McAdams, saying ERCOT’s current 3.3-GW assumption for retirements would be more “reasonable” to expect.
“I think that 8,300 is an extreme scenario, and I don’t think it does any good to be opining for an extreme scenario that doesn’t seem to be coming to fruition, given market dynamics but also ERCOT actions and legislative action,” she said.
“Even then, the state will take steps to ensure that this doesn’t happen,” McAdams added. “We are not powerless and there are legal remedies here. There are market-driven remedies to keep these in system. We argued about this in the market design debate, and I said, ‘This ain’t gonna happen.’
“I fear that if we start subtracting massive amounts of megawatts out of the models — due to hypothetical federal regulations which we are sure to litigate and go all the way to the U.S. Supreme Court, which will take some time — I believe it will blow out the top of our models, unduly alarm the public and create a narrative that certain alternatives are better,” he said. “I would advise simpler is better. Provide focus to ERCOT, clear the field of the massively hypothetical scenarios and then just look at what we have in the range.”
ERCOT’s Kristi Hobbs, vice president of system planning and weatherization, agreed to reduce the retirement assumption to 3.3 GW. She also said staff would continue to include a one-day-in-five-years loss-of-load expectation in its frequency scenario limitations, along with LOLE expectations of one day in 10, one day in 15 and one day in 20 years.
Frequency Target
The PUC agreed with ERCOT’s recommendation to include a reliability frequency target in future studies that uses a capacity mix with additional inverter-based resources.
ERCOT has proposed a three-part framework that considers the duration and magnitude of a loss-of-load event, along with the occurrence’s frequency. It says this will better quantify LOLE risks when intermittent resources are a large percentage of the generation fleet. (See “ISO Prioritizes Market Changes,” Texas Public Utility Commission Briefs: Aug. 24, 2023.)
$30 Million Procurement
ERCOT staff also shared with the commission results of the firm fuel supply service’s (FFSS) second procurement, revealing the ISO acquired 3,319.9 MW of the reliability product for $29.9 million for the Nov. 15-March 15, 2024, obligation period (53298).
That was 13% more capacity and an estimated 43% cost reduction from the grid operator’s first procurement of FFSS capacity. That resulted in 2,940.5 MW of capacity for $52.9 million during the Nov. 15, 2022-March 15, 2023, obligation period.
Five qualified scheduling entities responded to ERCOT’s second procurement by offering 32 generation resources to act as FFSSRs during the obligation period. The grid operator awarded each resource the commission’s clearing price cap of $9,000/MW; 31 of the 32 generators offered fuel oil as the reserve fuel and one offered natural gas storage.
The first procurement saw 19 resources awarded at $6.19/MWh ($18,000/MW). Eighteen of the 19 generators offered fuel oil as the reserve fuel and one offered natural gas storage.
ERCOT added FFSS at the PUC’s direction after the disastrous 2021 winter storm, when curtailed gas supplies knocked numerous units offline and nearly collapsed the grid. The service is designed to provide additional reliability and resiliency during extreme cold weather by maintaining resource availability during gas curtailments or other fuel-supply disruptions.
The commission expanded eligibility to a broader range of resources for the service after its first phase.
Nuclear Working Group Meets
Following the open meeting, Commissioner Jimmy Glotfelty held an informational briefing for stakeholders interested in joining a PUC working group that will spend the next 14 months looking for ways to position Texas as a national leader in small modular reactors (SMRs) (55421).
In August, Gov. Greg Abbott (R) directed the PUC to create a working group to study and provide recommendations on SMRs. He also asked Glotfelty to chair the team, which the commission has labeled the Texas Advanced Nuclear Reactor Working Group. (See Texas Seeking Lead Role in Nuclear SMRs.)
“When the governor asks you to do it, you have to do it,” Glotfelty said.
PUC’s Jimmy Glotfelty briefs stakeholders on a working group that will address small modular reactors. | Admin Monitor
Nearly 20 market participants, companies and individuals already have filled out applications to join the working group. The first meetings will be held in October after the team members have been selected. Public meetings will continue into April before the team begins drafting a report with recommendations that is due to Abbott by December 2024.
“It’s exciting to see so much interest in this even when every day there’s another headline about something in this space. The challenge with those headlines is very few of them say Texas,” Glotfelty told stakeholders. “Our goal in this process is to figure out how we get more of them going.”
The commission says the group will evaluate how advanced reactors can provide safe, reliable and affordable power for Texas. It will study financial incentives, state and federal regulatory impediments to growth, the electric market’s effects, technical challenges and additional factors necessary to grow nuclear energy in the state.
“This is not going to be a government report that sits on a shelf. I’ve written plenty of those,” said Glotfelty, who brings years of experience at the U.S. Department of Energy to the position. “This is not to understand a good place to deploy these reactors. It’s to set the playing field so we can deploy these reactors.”
PJM has agreed to reduce its nonperformance penalties 31.7% for generators that could not meet their capacity obligations during the December 2022 winter storm.
A proposed settlement filed Sept. 29 by PJM and 81 other parties would resolve the bulk of 15 complaints generators filed against the RTO arguing that it had either improperly declared performance assessment intervals (PAIs) in regions where emergency conditions were not present or unjustifiably applied nonperformance penalties (EL23-53, et al.).
PJM did not admit to any wrongdoing or violation of its tariff in the settlement, and the agreement does not include any changes to the governing documents. The filing states that the settlement was either supported or not opposed by the “overwhelming number of active parties in the case.” (See Settlement Possible Between PJM And Several Generation Owners over Winter Storm Complaints.)
“These Winter Storm Elliott complaints had the potential to become the next ‘mega-litigation’ along the lines of the California Energy Crisis litigation or the Seams Elimination Cost/Charge Adjustment/Assignment litigation; instead, the settling parties have achieved a negotiated resolution that avoids years (or, in the case of the California Energy Crisis, decades) of litigation and now present that resolution to the commission for approval,” the filing said.
All 15 complaints would be resolved by the settlement except for portions of complaints by East Kentucky Power Cooperative (EKPC) (EL23-74) and Energy Harbor (EL23-63) to be decided by FERC. The settlement allows EKPC to pursue its request to modify its penalty charge rate and stop-loss rate.
EKPC argued that the Capacity Performance (CP) penalty rate and stop-loss limit are unjust and unreasonable by not being tied to the revenues market sellers receive through the capacity market — potentially resulting in resources being levied penalties larger than their capacity revenues. The complaint called for the commission to modify the penalty calculation to instead use the Base Residual Auction (BRA) clearing price, rather than the net cost of new entry (CONE) for both the charge rate and stop-loss. EKPC requested that the change be effective for the 2023/24 delivery year.
The PJM Board of Managers directed staff to revise the stop-loss to be based on the BRA clearing price as part of a larger reworking of the capacity market expected to be filed this month. The penalty charge rate would remain based on net CONE. (See PJM Board Releases Outline of CIFP Filing.)
The EKPC complaint also argued that PJM violated its tariff by not curtailing nonfirm exports during emergency conditions and that the company’s Bluegrass generator should be excused from penalties. EKPC agreed to drop both issues as part of the settlement.
The settlement asks the commission to “decide the merits” of Energy Harbor’s argument that PJM violated its tariff by assessing nonperformance charges against 300 MW of capacity that was unavailable due to maintenance outages. The company contended the capacity should be excused from penalties.
The settlement also includes an agreement that PJM will credit $4.4 million to Lee County Generating Station to resolve its complaint. The RTO will also extend collection of the company’s remaining penalty balance, and corresponding interest, to avoid depleting the collateral PJM holds to support Lee County’s exports to MISO.
Lee County’s complaint argued that it should not be subject to penalties, as it was on a forced outage at PJM’s request and would have been available during the PAIs if dispatchers had not requested that it go offline. In July, the commission approved a request from PJM and Lee County to defer the final six months of the company’s penalty billing schedule through June 2024 to avoid the company defaulting on its obligations in PJM and MISO (EL23-57).
The reduction applies to all market sellers assigned a share of the $1.8 billion in penalties associated with Winter Storm Elliott, including those that have already paid their penalties in full. Recipients of bonus payments — which are distributed to generators that overperformed during PAIs out of the pool of penalties collected — will be required to refund a portion of their allocation.
The penalty reduction is predicated on market sellers continuing to meet their payment obligations or already having paid off their penalties. If a party defaults or does not make a payment, the original full penalty will be reinstated with interest. Market sellers who opted for a longer nine-month repayment timeline, which comes with the tradeoff of being subject to interest, will have the interest due on their penalties recalculated to use the lower settled figure. Interest will not be due on the bonus payment refunds. (See “FERC Approves Alternative Billing Schedule,” PJM: Elliott Nonperformance Penalties Total More Than $1.8B.)
PJM will also re-evaluate the collateral each market participant must provide PJM to take into account the reduced penalties. Parties that have paid off their charges in full will have their collateral released under the settlement.
The settlement is contingent on FERC approval “without material modification or condition,” and it states that the filing will be withdrawn unless the settling parties agree to any modifications the commission may condition its approval on. The filing requests commission approval no later than Dec. 29 and use of the default comment period, which would make responses due Oct. 19.
“Timely commercial certainty is a core objective of the settlement, and that objective would be significantly undermined if the commission does not approve the settlement by the end of this calendar year,” the filing said.
On Oct. 25, the commission granted a tariff waiver PJM and several complainants requested to allow the RTO to delay collection of unbilled penalties and distribution of bonuses until the settlement is acted upon by the commission and can be implemented by PJM. The order stated that delaying billing would be “administratively efficient” by reducing the potential for rebilling and resettlement should the settlement be accepted and result in a change in the penalties due.
As CAISO grapples with an “unprecedented” surge in interconnection requests, the system operator has proposed prioritizing requests in zones where transmission capacity now exists or is under development.
The “zonal approach” is outlined in a straw proposal CAISO released Sept. 21 as part of its 2023 Interconnection Process Enhancements (IPE) initiative.
CAISO has been overloaded with interconnection requests resulting from the rapid pace of clean energy development in California as the state works toward a goal of 100% clean energy by 2045.
The most recent group of interconnection requests, Cluster 15, included about 544 requests totaling around 354 GW. That compares to 150 requests in 2020 and 373 requests in 2021.
CAISO said the increased number of requests is “unsustainable” and has overwhelmed existing processes.
“The ISO needs a significantly reformed structure to advance viable projects and prevent stagnant projects from hindering the progress of viable projects in the queue,” CAISO said.
In response, the straw proposal lays out a “significantly reformed interconnection process” aimed at promoting “rapid deployment of new generation for reliability, affordability and decarbonization.”
Zones, Scoring and Auction
CAISO calls the zonal approach a “central tenet” of its straw proposal. The ISO said its 2022/23 transmission plan took a zonal approach to planning for the resources in the portfolio provided by the California Public Utilities Commission for that cycle, “setting the foundation for the alignment of procurement and interconnection process enhancements.”
Under the proposal, projects in zones with available transmission capacity would be prioritized to move into the study process.
CAISO noted the importance of publicly providing information on the priority zones before opening an interconnection request window, such as a heatmap showing available transmission capacity. A heatmap is one of the requirements of FERC Order 2023, issued in July, regarding interconnection reform. (See FERC Updates Interconnection Queue Process with Order 2023.)
In another proposal, CAISO would use a scoring system in situations where the capacity of interconnection requests exceeds the available transmission capacity within a zone by more than 150%. Scoring criteria might include interest from an offtaker, permitting status and commercial readiness.
In some cases, CAISO would also conduct an auction in which winners would be prioritized and studied in a certain zone. The auction would occur when proposed capacity exceeds the capacity limit for a zone, after viability criteria are applied.
CAISO said an auction process may be needed “to achieve manageable queue volumes and preserve the competition of viable projects in each zone.” The ISO acknowledged that the auction proposal raised a number of stakeholder questions, including how the auction proceeds would be spent.
Interconnection Option B
The proposal also includes a process, called Option B, for requests to interconnect outside of priority zones. Those projects would be required to pay for needed network upgrades.
Comments on the new straw proposal are due Oct. 12. After that, CAISO will release a second draft, followed by another round of comments. The proposal is expected to go to the CAISO Board of Governors for approval in February.
The straw proposal is part of Track 2 of the 2023 IPE initiative. Track 1 involved changes to the Cluster 15 study schedule that were approved by the Board of Governors in May.
MISO’s Planning Advisory Committee is deciding whether to approve the MISO 2023 Transmission Expansion Plan, which has dropped to just under $9 billion within a month.
Last month, MTEP 23 stood at 578 projects totaling $9.4 billion. Now the annual portfolio clocks in at $8.96 billion across 575 projects.
At a special Sept. 28 teleconference, the PAC opted for an email ballot through Oct. 5 on whether to recommend the portfolio to MISO board members. The PAC’s vote is advisory and can be bypassed.
MISO’s Jeremiah Doner said transmission owners have reviewed projects, made adjustments and refined cost estimates since the final round of subregional planning meetings on MTEP 23 in September.
Doner said some projects have been postponed to later MTEP cycles. Most notably, MISO has deferred the $260 million third phase of Entergy Louisiana’s Amite South reliability project into MTEP 24.
MISO is conducting additional analysis on possible alternatives to the project, which was among MTEP 23’s most expensive, Doner said.
Despite the deferral of the Entergy project, MISO South’s 77 projects still account for 46% of MTEP 23 spending. MISO remains committed to its recommended, $1.7 billion, 500-kV Commodore-Waterford-Churchill loop project, which will replace both the first phase of Entergy Louisiana’s Amite South project and the Downstream of Gypsy reliability project, another Entergy Louisiana proposal. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.)
MTEP 23 contains $1.2 billion in generator interconnection upgrades, $1.7 billion in baseline reliability projects and nearly $6 billion in “other” projects, which includes reliability projects based on transmission owners’ self-imposed criteria separate from NERC standards, such as projects responding to load growth or addressing the age and condition of existing facilities.
Doner said MISO is confident it has assembled a package of “efficient, cost-effective solutions to identified system issues.”
Sector Critiques
MISO’s Competitive Transmission Developers Sector said the RTO should have reviewed more projects for “more efficient or cost-effective regional project alternatives.”
“Such a review is required by the MISO tariff and FERC Order No. 1000, and the failure to consider alternatives may lead to the approval of transmission projects that do not efficiently solve these and other system needs, which ultimately increases costs to customers,” the developers said.
Doner responded that MISO already prioritized alternative analyses for proposed new lines and larger, expensive projects that may affect the entire system.
“Roughly 75% of MTEP 23 projects didn’t meet criteria for alternative solution analysis, as they address needs with no cost-effective alternatives,” he said.
The RTO’s Environmental Sector said the MTEP 23 report should mention MISO’s “struggles to manage” its 242-GW generator interconnection queue and should describe what resources it needs to complete studies on time.
Doner said MISO continues to work on its queue processing time. He also pointed out that MISO is sitting on 49 GW worth of new generation that’s on hold despite MISO having already studied it and signed off on interconnection. He said “limitations on new interconnections are due to factors outside of MISO’s control, such as construction delays and supply chain issues.”
The Environmental Sector also asked MISO to pay more attention to HVDC lines in MTEP reports and do more to explore the potential for battery storage in MISO’s future.
Doner said MISO agrees that HVDC lines could be necessary. He said MISO and stakeholders will discuss HVDC needs as part of the second portfolio under MISO’s long-range transmission planning.
Doner also said, “MISO will monitor market performance and interconnection processes for potential improvements as more storage is constructed.”
Sustainable FERC Project’s Natalie McIntire said though the Environmental Sector often provides substantial comments, MISO “rarely” changes or adds detail to its MTEP reports based on the sector’s suggestions.
MISO said it will publish the comments it received as an appendix to the MTEP 23 report.
MTEP 23 will enter its next review at an Oct. 17 meeting of the System Planning Committee of the MISO Board of Directors.
MTEP 24
Meanwhile, MISO transmission owners have already submitted project proposals for MTEP 24, which will use the RTO’s new, one-stop model manager. The model manager project aims for one system of record for all planning and operations models to eliminate redundant data entry and review.
MISO and vendor Siemens are working to synchronize data collection fields between MISO’s different model structures. At the Sept. 27 Planning Subcommittee, MISO’s Scott Goodwin said he expects a few hiccups as MISO transitions to the new model system for MTEP 24.
MISO’s exploratory study on alleviating near-term transmission congestion has led the RTO to consider adding near-term economic benefits to its existing long-term economic planning.
Speaking at a Sept. 27 Planning Subcommittee, economic planning engineer Sean Rogers said that, as a result of this year’s inaugural near-term congestion study, MISO “will continue to explore how to adapt economic models and processes to identify near-term issues and solutions.”
MISO’s economic planning models are geared toward long-term horizons, not short-term congestion relief and economic benefits.
Rogers called the study a “starting point” for MISO to translate its long-term economic planning processes into a near-term model. He said over 2024, MISO will investigate how it can modify long-term planning models to “be more applicable for near-term use” and that the continuing evaluation will be part of the 2024 MISO Transmission Expansion Plan (MTEP 24).
Under this year’s purely informational study, MISO studied its top 10 most congested flowgates in its day-ahead market from 2021 to 2022. It assigned an unlimited kV rating on the flowgates in the study to pinpoint when hypothetical upgrades were beneficial over a five-year horizon based on adjusted production costs.
The study is for informational purposes only, so MISO isn’t recommending any transmission projects from its conclusions. However, planners said they may suggest projects after 2024’s study.
Stakeholders had requested that the grid operator come up with smaller, congestion-relieving projects like its interregional targeted market efficiency projects with PJM and SPP. (See MISO Adding Near-term Congestion Study to MTEP.)
MISO has said it first needs to better understand the nature of its near-term congestion before proposing a new project type and potential cost allocation. Some stakeholders have expressed disappointment that the study hasn’t resulted in a new class of projects.
Nevertheless, MISO found that if Duke Indiana’s Cayuga 345/230kV transformer were upgraded in west-central Indiana, it could save $2 million annually in adjusted production costs. The facility racked up about $30 million in day-ahead congestion in 2022.
Southern Minnesota Municipal Power Agency’s Murphy Creek – Hayward 161-kV line could save a little more than $1 million per year with an upgrade, cutting into the $28 million in day-ahead congestion it accumulated in 2022.
All other hypothetical upgrades on MISO’s top 10 most congested flowgates saved less than $500,000 annually. Two showed negative benefits because of impacts on nearby facilities.
MISO found a contradictory, $5 million in additional annual costs when it studied an upgrade to Ameren Illinois’ Marblehead North 161/138-kV transformer. MISO said it will continue to examine the reasons behind the economic harms. The Marblehead flowgate accumulated more than $102 million in day-ahead congestion costs over 2022.
Some flowgate congestion cases were found to be linked to temporary outages. Congestion on Great River Energy’s Johnson Junction – Graceville 115-kV line in Minnesota — which surpassed $71 million in congestion costs in 2022 — was “directly related to the planned construction outage on the Johnson Junction to Morris line” from Oct. 1, 2021, to Feb. 1, 2022. Two other congested flowgates were linked to Duke Energy Indiana’s Cayuga Unit 1 outage.
The building construction sector has the potential to move from being a massive emissions source to a carbon sink, a new report said.
Driving Action on Embodied Carbon in Buildings, jointly released by RMI and the U.S. Green Building Council (USGBC), looks at challenges in reducing embodied carbon emissions in the building construction sector and the potential for reducing and even negating those emissions.
“In our lifetimes, we could see buildings move from being leading drivers of climate change to safely and durably storing gigatons of atmospheric carbon,” the report said. “There is a long way to go to achieve such an ambitious goal, but it is not as far-fetched as it may seem. Buildings currently account for nearly 50% of global material flows. Only a small percentage of that material would need to store carbon to become a leading climate drawdown solution.”
When looking at greenhouse gas emissions reduction, the focus is often on energy consumed by buildings’ operations and how it can be cut through energy efficiency. The International Energy Agency says operating buildings and the appliances and equipment in them accounts for more than one-third of global energy use and emissions, but that figure doesn’t account for the buildings themselves.
The carbon embodied in the buildings includes the carbon emissions from the energy used in extracting, processing and transporting materials, equipment and fixtures, and constructing buildings, as well as managing the waste at the end of the building’s life. The World Green Building Council estimates buildings’ material and construction accounts for 11% of global energy-related carbon emissions. And it is why everyone in the green building industry winces when another video of imploding, never-occupied high rises in China makes the rounds on social media.
“Given the scale of the sector’s climate impact, it is imperative that owners, designers, builders, manufacturers and policymakers lead the market by prioritizing this issue,” the report said.
There are already cost-effective ways to reduce buildings’ embodied carbon. The report quoted an RMI study that showed it is possible to reduce the upfront carbon footprint of common building types between 19 and 46% with little to no added expense by making more informed materials choices.
Across all building materials, there are critical data gaps when it comes to measuring the lifecycle emissions of materials. “Currently, the most accurate data points exist for cradle-to-gate emissions in key building material categories including concrete, masonry, steel, aluminum, gypsum board, insulation, cladding, flooring, ceiling tiles and paint,” the report said. Emissions after “the gate” — transportation from the factory to the building site and construction itself — are less well understood.
Data gaps, however, are not a reason to delay action, the report said. “We know enough today to make meaningful decisions that reduce building embodied carbon emissions and should not let data gaps stop rapid uptake of low-embodied-carbon strategies in rating systems, policies and codes.”
Tackling The Big Three: Concrete, Steel And … Wood?
The potential to cut the embodied carbon of buildings in the future looks even better as innovations in the production of key building materials, especially energy-intensive concrete and steel, drive down their embodied energy. “Transition away from fossil fuel production of concrete and steel combined with the rapid decarbonization of the grid portends a future where the embodied carbon of these materials can approach zero emissions,” the report said.
Wood too has the potential to be improved, and it may not be as green as it may sound. “Wood used in building products has the potential to be a renewable and perhaps carbon-storing material that can help drive down embodied carbon emissions when efficiently substituted for high-impact materials. However, there are aspects of wood sourcing — such as forestry practices with poor climate outcomes, wider land-use impacts and energy-intensive product manufacturing — that can lead wood to have high emission and ecological impacts.”
Updates Can Double Embodied Energy
The embodied carbon from retrofits and renovations over the lifetime of a building may equal or exceed that of the initial construction, the report said, and is “poorly understood but could be a major driver of emissions if left unaddressed.” Avoiding, delaying or limiting the scope of updates, disassembling instead of demolishing and increasing materials recycling can all lower the impact of renovations.
Renovations, though, offer potential for carbon drawdown. “Interior finishes represent some of the best opportunities to incorporate carbon-storing, rapidly renewable, bio-based materials that are not subject to exterior weathering,” such as bamboo flooring and cellulose acoustic panels, the report said.
Despite a maximum generation emergency and hot weather challenges, MISO’s reliability, markets and operational functions performed as expected in August, RTO officials said last week.
MISO averaged an 87-GW peak load in August, higher than 2022’s 84 GW. Average daily generation outages hovered around 37 GW, also higher than August 2022’s average of 33 GW. MISO issued operating notices about system stressors on more than half the days in the month.
The average price of natural gas and coal fell to $2/MMBtu during the month from $8/MMBtu a year earlier, causing real-time LMPs to drop to $33/MWh from $87/MWh last year.
MISO also recorded a 3.3-GW all-time solar generation peak Aug. 31, when panels supplied about 4% of total load around midday.
MISO will review the late August maximum generation event and the reasons behind it with stakeholders at its Oct. 3 Reliability Subcommittee and again at its Oct. 5 Market Subcommittee.
