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July 30, 2024

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FERC Accepts Basin Tariff Revisions, Sets for Hearing

FERC last week accepted SPP’s proposed tariff revisions for Basin Electric Power Cooperative’s formulate rate template, suspending them for a nominal period, effective Nov. 14, subject to refund, and established hearing and settlement judge procedures. 

The commission said in its Nov. 13 order that its preliminary analysis indicated the proposed revisions have not been shown to be just and reasonable and that they raise issues of material fact more appropriately addressed in the hearing and settlement judge procedures (ER23-2836). 

FERC did find that a 50-basis point adder it previously granted Basin Electric for RTO participation still was appropriate, given Basin Electric’s continued membership in SPP. It said that the cooperative’s return on equity (ROE), inclusive of the adder, must remain within the zone of reasonableness during the hearing and settlement judge proceedings. 

SPP filed the tariff changes in September after FERC said Basin Electric became subject to its jurisdiction when it readmitted Tri-State Generation and Transmission Association as a non-exempt Class A member in November 2019. Basin Electric proposed to revise its template to reflect a base ROE of 9.69% and the 50-basis point adder for its SPP membership and calculated an 8.65%-11.12% composite zone of reasonableness. 

The cooperative also proposed to revise its template to reflect a capital structure of 48.22% equity and 51.78% long-term debt, based on the weighted average capital structure of transmission owners across the SPP region. Basin Electric claimed that because it is the largest non-governmental transmission owner by capitalization in SPP’s Upper Missouri pricing zone, it is appropriate to rely on the weighted average capital structure used in all SPP transmission owners’ formula rates. 

The proposed ROE and capital structure would result in an increase to the 2022 annual transmission revenue requirement of $4.68 million, Basin Electric said. That is about 4% under its 2022 ATRR under the existing template. 

Black Hills Settlement OK’d

FERC on Nov. 16 approved an uncontested settlement of Black Hills Colorado Electric’s proposed tariff revisions to transition from a stated transmission rate to a forward-looking formula rate for transmission service (ER22-2185). 

The commission last year accepted and suspended, subject to refund, the utility’s proposed revisions, setting the proceeding for hearing and settlement judge procedures. An administrative law judge approved the settlement with intervenors Tri-State and Arkansas River Power Authority in September and certified the agreement to FERC on Oct. 4. 

Commission trial staff supported the settlement, saying its approval “will resolve all issues set for hearing.” They said the agreement provides “significant benefits to ratepayers,” pointing to an ROE of 9.8% that was lower than the filed ROE of 10.44%. 

Staff also said a fixed capital structure of 47% equity and 53% debt is “both reasonable and preferrable” to the company’s as-filed proposal for variable capital structure. A three-year moratorium of “key components of the formula rate” avoids further litigation, they said. 

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MISO, SPP Ditch 90/10 JTIQ Allocation After $465M DOE Grant

CARMEL, Ind. — Weeks after the nearly $2 billion Joint Targeted Interconnection Queue (JTIQ) transmission portfolio was awarded a $465 million Department of Energy grant, MISO and SPP are switching their proposed cost allocation for the projects.

Now, all costs of the JTIQ portfolio should be assigned to interconnection customers, MISO and SPP have agreed. The new cost allocation will replace the RTOs’ previously proposed 90% assignment to interconnecting generators with the remaining 10% to load.

The RTOs have further said all operations and maintenance costs on the projects will be borne by the constructing RTO’s load.

Last month, DOE announced the JTIQ portfolio will receive $464.5 million from the department’s Grid Resilience and Innovation Partnership program. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)

MISO Director of Resource Utilization Andy Witmeier said MISO, SPP and states are in the middle of negotiations with DOE before they can receive the money.

Speaking at a Nov. 15 Planning Advisory Committee meeting, Witmeier said the grant will help get the JTIQ portfolio online “to the benefit of generators waiting to interconnect.” And he said a more simplified cost allocation likely will help move the projects across the finish line, even though MISO and SPP had settled on the 90/10 allocation almost a year ago.

“This is what MISO and SPP believe will have the most success in getting approved,” he said.

Witmeier characterized the change in direction on cost allocation as a “small pivot.” He said MISO always would have used the grant money to apply for the load’s share of project costs first, and the $464 million grant more than takes care of the tab load would have picked up under the original cost allocation proposal.

Witmeier said MISO and SPP concluded DOE’s funding can address rate complexities the 10% allocation to load will introduce in how costs will be spread across load and how operations and maintenance costs will be handled. He said using a 100% allocation ensures entitlements are assigned to the constructing region and reduces risk that load in one RTO is supplementing transmission in the other in the unlikely case not enough generation shows up to fund the lines.

Witmeier said the 100% method is a “much simpler rate design, if you don’t have load in that calculation.”

He also said the 100% allocation to generators matches SPP’s existing interconnection upgrades allocation and allows MISO and SPP to approach FERC with a “consistent approach.”

“The 100% is a small shift for MISO, but the 90/10 was a big shift for SPP,” he said.

In MISO’s individual queue process, interconnection customers bear 100% of interconnection costs except when network upgrades are 345 kV or higher, when the 90% to interconnection customers, 10% to load allocation kicks in.

In an email to RTO Insider, SPP confirmed the new rate design will be a better fit with its current cost allocation for generator interconnection projects.

Xcel Energy’s Carolyn Wetterlin said her utility agrees with the change. She said a 100% allocation will result in a “cleaner filing” to FERC and less costs borne by ratepayers in MISO and SPP.

However, the Coalition of Midwest Power Producers’ Travis Stewart said the change is significant and interconnection customers have concerns.

National Grid Renewables’ Maggie Kristian said some generation developers weren’t comfortable with load’s small share in the allocation to begin with. She said it’s disappointing to see even that small amount reduced to nothing.

Witmeier said the 100% cost allocation to projects will apply only to the first JTIQ portfolio. He said MISO and SPP will have to “go back to the drawing board” for future JTIQ portfolios and devise a new cost allocation. The RTOs hope FERC gives its blessing for JTIQ planning to become a cyclical process and replace their affected system study process.

Witmeier also said there are always lingering concerns about free riders in transmission cost allocation. He said while interconnection customers might be upset to completely cover the JTIQ bill, load is probably unhappy taking on 100% of MISO’s long-range transmission plan costs.

“We’ve been having this discussion in the MISO community for the past 15-20 years, what is the appropriate formula for generation and load,” Witmeier said.

He said while MISO will hear written concerns on the allocation change through Dec. 6, it’s unlikely to influence changes to MISO and SPP’s direction.

The RTOs also found a change in adjusted production cost benefits of the JTIQ portfolio between MISO and SPP since it first conducted a benefits analysis in 2021. Now MISO can expect to see a $76.5 million benefit, while SPP will experience $99.3 million in benefits over 20 years. The RTOs originally found a $55.7 benefit for MISO and a $132.9 benefit for SPP over the first 10 years the projects are in service.

As far as how the DOE grant will be split between MISO and SPP, that’s unknown, Witmeier said. He said that depends on how many projects apiece from the MISO or SPP clear their respective interconnection queues.

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ERCOT Cancels RFP for Additional Winter Capacity

ERCOT canceled its effort to procure additional generation capacity this winter Nov. 17, citing “limited response” from the market. 

The Texas grid operator was seeking 3,000 MW of capacity with its request for proposal. Participants responded with 11.1 MW of “potentially eligible” capacity. 

ERCOT CEO Pablo Vegas said Nov. 17 during an interview that it was “disappointing that there wasn’t more available.” 

“One of the important outcomes of this RFP process was learning what the market response would be to this type of capacity request,” he said in a statement. “We’ll take these lessons and continue to work with the [Public Utility Commission of Texas] and the market to evaluate other types of demand response products that could contribute meaningfully to electric reliability in the future.” 

The ISO announced its intention in October to increase operating reserves this winter. It listed 20 mothballed and seasonally mothballed dispatchable resources that were eligible to respond to the RFP. Austin Energy and CPS Energy, owners of three of the four largest plants on the list, have said they would not bring their decommissioned units back to life. (See ERCOT Searching for 3 GW of Winter Capacity.) 

Talen Energy notified ERCOT in August that it was planning to indefinitely suspend operations at the other large plant on the list, its 292-MW gas unit outside Corpus Christi. The grid operator evaluated offering a reliability-must-run contract for Barney Davis before Talen withdrew the suspension request on Oct. 27. (See “ERCOT Evaluating RMR Options,” Texas Public Utility Commission Briefs: Aug. 24, 2023.) 

Vegas said no generators offered their decommissioned units in response to the RFP, which presented three-month contracts that were to begin Dec. 1. The program’s 11.1 MW came from entities offering to shed load during emergency conditions. 

The awards would have been announced Thursday. 

The ISO said it weighed factors such as the program’s costs and the incremental additional complexity for its control room against the very small amount of capacity and the minimal reliability benefits in declining to proceed with the RFP. 

“It will come as a surprise to no one that knows anything about power markets that ERCOT’s Hail Mary attempt to procure zombie power plants failed,” Stoic Energy CEO Doug Lewin said on X, formerly known as Twitter, putting in a plug for energy efficiency’s benefits. 

The RFP also drew pushback from the PUC’s commissioners, who expressed concerns during an open meeting earlier this month over ERCOT’s refusal to place a firm cap on the program’s costs. Vegas told the commission staff had not yet set a budget for the RFP. 

Commissioner Will McAdams said the RFP should be considered an interim or bridge solution under state rules. That would mean it would compete with funds under the $1 billion cap designated for the performance credit mechanism. 

ERCOT said it “firmly believes” expanding demand response capabilities in the industrial, commercial and residential customer classes offers “tremendous potential.” It said it will work with the PUC and stakeholders to explore incentives and product designs that may work better in the future. 

The RFP was based on probabilistic analysis indicating ERCOT faced a 20% risk of entering energy emergency alert conditions this winter if the system was hit with another event similar to last December’s Winter Storm Elliott. It said the 3,000 MW of additional capacity that could be called upon if needed was an “added layer of protection” during peak demand. 

“The [RFP] was an extra layer of precaution to mitigate higher risk during extreme weather this winter,” Vegas said. “ERCOT is not projecting emergency conditions this winter and expects to have adequate resources to meet demand.” 

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MISO Decides Battery Storage Can Use As-available Tx Service

CARMEL, Ind. — Battery storage that charges from the grid should be able to use non-firm transmission service, MISO has decided.   

MISO is discarding its previous requirement that battery storage needs to secure yearly, firm point-to-point transmission service before it can charge from the grid.  (See MISO Agrees to Dial Back Tx Service Requirements for Energy Storage.)  

Manager of Resource Utilization Kyle Trotter debuted draft business practice manual language adopting the changes at a Nov. 15 Planning Advisory Committee meeting.  

Staff in October said battery storage should be treated like any other intermittent load in MISO and should be able to use as-available transmission service. That means storage owners will be free to use the less expensive non-firm, point-to-point transmission service or MISO’s Network Integrated Transmission Service for any length of time.   

Trotter said MISO hopefully will be able to incorporate the change formally by the first quarter of 2024. He said if the Planning Advisory Committee is receptive, MISO will test out the changes with the Market Subcommittee in January.  

Changes to MISO’s business practice manuals require only a review from MISO’s legal team to be implemented. They are not filed with FERC.  

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NERC ‘Very Happy’ With GridEx VII Participation

NERC’s GridEx security exercise may be in its seventh iteration, but it still packs a challenge for participants across the electric grid, stakeholders said in a Nov. 16 media call.

According to Manny Cancel, senior vice president at NERC and CEO of the Electricity Information Sharing and Analysis Center (E-ISAC), more than 250 organizations took part in the distributed play portion of GridEx VII, held Nov. 13-14. The distributed play was followed by an executive tabletop session Nov. 16, in which executives from the electricity, natural gas, telecommunications and finance sectors participated, as did representatives from the U.S. and Canadian governments and the Electricity Subsector Coordinating Council.

The participation rate was “pretty consistent with … prior GridExes,” Cancel said.

GridEx VI, held two years ago, saw participation from 293 organizations, the lowest number since the second exercise in 2013. (See NERC: GridEx Lessons Already In Use.) Nonetheless, Cancel said the E-ISAC, which developed the core exercise scenario for the distributed play as well as the virtual environment for the exercise, was “very happy with the level of participation,” particularly the involvement of other critical infrastructure sectors in the planning, distributed play and executive tabletop.

Electrical equipment vendors also played a part in this year’s exercise, as they have in previous years. Participants said the sector’s representation mostly came from original equipment manufacturers, who provided input into issues such as supply chain shortages that are causing growing concern.

“We do include vendors … not only in the actual drill, but even in the planning for the drill and coming up with scenarios, and that’s been valuable,” Cancel said. “They face the same threats that we face, they have insights, and they can provide value, so we’re looking forward to continuing to leverage that as we go forward.”

Cyber and Physical Attacks Simulated

Other real-world issues continued to influence this year’s distributed play and executive tabletop scenarios, stakeholders said. While details about the distributed play scenario — which participating organizations customized to fit their needs after the E-ISAC gave them the general themes — have not been released, participants in the call mentioned cyber intrusions by nation-state actors attacking the grid either directly or through supply chains, or spreading misinformation on social media.

Physical violence, another increasingly prominent focus of security specialists, also constituted “a substantial portion of the drill,” Cancel said. Puesh Kumar, director of the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response (CESER), said exercises like GridEx provide an opportunity for utilities and law enforcement to practice not only bringing those responsible to justice, but also preventing as much harm as possible.

“When people commit these types of crimes, it’s … a very unsafe environment. It’s not just unsafe for the general public, if the power goes out and critical resources aren’t available; it’s actually unsafe for the individuals committing these crimes as well,” Kumar said. “So getting that awareness of how unsafe trying to commit a crime like this actually is” remains a major focus for DOE and CESER.

Pandemic’s Lessons Resonate

Participants also noted the continuing legacy of the COVID-19 pandemic, despite the absence of travel restrictions that limited the GridEx VI executive tabletop to remote attendance only.

Duane Highley, CEO of Colorado-based Tri-State Generation and Transmission Association and co-chair of the ESCC, noted that his organization’s version of the distributed play included simulating the loss of its headquarters. Because “the ability to work remotely has really been enhanced” during the pandemic, Highley said reconnecting the company’s employees was much simpler than it would have been in previous years.

Kevin Wailes, CEO of Lincoln Electric System in Nebraska and ESCC co-chair, added that “the virtual environment provides the opportunity for a lot more participation [by small utilities and co-ops] than we’ve … had in the past.” Pedro Pizarro, another ESCC co-chair and CEO of Edison International, said he was glad the scenario included simulation of the loss of communications, because the experience of the pandemic made it “critical that we prepare for that kind of scenario.”

Cancel emphasized that the landscape of threats facing the energy sector is dynamic and evolving and that while events like GridEx can help entities practice their response to recently identified risks, there are always more dangers emerging. Kumar said one benefit of GridEx is its ability to bring together stakeholders both inside and outside the industry to practice their communication skills so they can engage quickly when malicious actors try to exploit new vulnerabilities.

“The reality is that there’s always going to be vulnerabilities; we just need to figure them out before someone else does and takes advantage of them,” Kumar said. “Exercises like this really bring the manufacturers closer together with the energy sector community, both in industry and government, to really start to mature what I like to think of as [operational technology] vulnerability disclosure. … I think that’s a very positive sign in terms of where we’re headed with vulnerabilities.”

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DOE Proposes Expanding NEPA Exclusions for Clean Energy, Transmission

The U.S. Department of Energy Thursday proposed revisions to its regulations under the National Environmental Policy Act that would expand the scope of “categorical exclusions” for transmission and clean energy. 

The exclusions would apply to projects that are shown to not have a significant environmental effect. It would create a new exclusion for energy storage projects within previously disturbed or developed areas, while changing exclusions for solar energy and transmission. 

DOE reasoned that upgrading lines can prevent the construction of new ones, with the Notice of Proposed Rulemaking (NOPR) highlighting reconductoring as a means of capacity expansion, which can increase the amount of renewable energy on the grid. 

“Improvements to capacity and efficiency can help to ensure reliability, reduce costs to consumers and reduce [greenhouse gas] emissions associated with electricity generation, transmission and distribution,” said the notice in the Federal Register. 

Rebuilding transmission lines is currently exempted, but only up to 20 miles. The proposal would remove that mile limit. The department reasoned that the environmental impact of a line is not related to its length. 

It also would expand the exclusion for relocating segments of a line to existing rights of way or previously disturbed or developed lands. Regulations currently include language limiting relocation exemptions to “minor” relocations of small segments; the proposal would remove the word “minor.” 

The storage exemption applies to electrochemical batteries and flywheels within previously disturbed or developed areas, or within small sites near such areas.  

The current categorical exclusion for solar is limited to projects of 10 acres or below, but DOE said acreage is not a reliable indicator of environmental impact and would remove that limit in the proposal. Projects larger than 1,000 acres on previously disturbed or developed land have not had significant environmental impacts, it said. 

DOE expects that the new exclusions will save it money and time, while improving the reliability and resilience of the electric grid. Expanded electricity generation that helps to reduce greenhouse gas emissions is another benefit. 

The department is taking comments on the proposal through Jan. 2. 

Speaking after FERC’s open meeting Thursday, Chair Willie Phillips said that the proposal would have more impact on DOE’s transmission siting authority. The commission has its own pending NOPR implementing its backstop siting authority granted by the Infrastructure Investment and Jobs Act. (See FERC Backstop Siting Authority Runs into Opposition from States.) 

DOE’s proposal was welcomed by American Council on Renewable Energy President Gregory Wetstone in a statement. 

“A dramatic increase in renewable energy and transmission infrastructure is needed to enhance reliability, lower energy costs and maximize the benefits of the Inflation Reduction Act,” Wetstone said. “A key barrier is the often lengthy siting and permitting process. ACORE supports the use of categorical exclusions for projects that will produce a cleaner grid and not adversely impact the environment. This mechanism improves siting and permitting while maintaining NEPA’s core environmental provisions.” 

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Popular Incentive Dropped from CARB’s $624M EV Funding Package

California regulators approved a $624 million clean transportation incentive funding package on Thursday but said goodbye to a flagship program that helped consumers in the state buy more than 500,000 zero-emission or hybrid light-duty vehicles. 

The California Air Resources Board (CARB) approved a funding plan for 2023/24 that includes $455 million in incentives for zero-emission drayage trucks and school buses.  

Another $28 million will go to the Clean Cars 4 All program, which pays lower-income consumers to scrap their old cars and buy a cleaner vehicle. An e-bike incentive program will receive $18 million, and $14 million will go to the Clean Off-Road Equipment incentive program. 

But the plan does not include money for the Clean Vehicle Rebate Project (CVRP), which has received $1.61 billion since its launch in 2010 and provided incentives for the purchase of about 533,000 vehicles. 

CVRP ran out of money and closed to new applications effective Nov. 8. The program offered incentives of up to $7,500 for the purchase of new battery-electric, plug-in hybrid and fuel cell vehicles. The program included income caps, but they were less restrictive than those of Clean Cars 4 All. 

Stephanie Parent with CARB’s Mobile Source Control Division said CVRP had been “a huge success story.” 

“CVRP achieved its goal of accelerating the deployment of ZEVs in California and provided highly useful ZEV market information to stakeholders in California and beyond,” Parent told the CARB board on Thursday. 

According to the California Energy Commission’s ZEV dashboard, 1.7 million light-duty ZEVs have been sold in California. So far this year, ZEVs accounted for 25% of new car sales. 

Rather than providing purchase incentives for the broader ZEV market, CARB will now shift its focus to lower-income consumers through its Clean Cars 4 All and finance assistance programs. 

Smaller Package

The $624 million incentive package that CARB approved on Thursday is substantially smaller than the $2.6 billion approved last year for 2022/23. That was the agency’s largest budget yet for the incentives. (See CARB Approves $2.6B in Clean Vehicle Incentives.) 

The current package includes $455 million in incentives for zero-emission heavy-duty vehicles: $80 million for drayage trucks and $375 million for public school buses. Those incentives will be available through the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP). 

The drayage truck incentives will help fleets meet the requirements of CARB’s Advanced Clean Fleets (ACF) regulation adopted in April. Under ACF, all new trucks added to drayage fleets must be zero-emission starting in 2024, and all drayage trucks must be ZEVs by 2035. (See CARB Adopts Clean Fleets Rule Despite Broad Skepticism.) 

The state budget didn’t give CARB funding for other types of heavy-duty vehicles that are eligible for HVIP incentives. But HVIP received $1.8 billion in the 2022/23 funding plan, and the program reports that incentives are still available. 

On the light-duty side, the $28 million going to Clean Cars 4 All will be split into two parts. Half will go to air districts that have been administering the program since its launch. The other half will go to a new statewide expansion of the program. 

CARB’s incentive funding plan also includes the addition of zero-emission motorcycles (ZEMs) as an eligible vehicle in Clean Cars 4 All. Incentives for ZEMs were previously only available through CVRP. 

The Tesla Effect

CVRP received a $515 million allocation for 2021/22 that was intended to fund the project through June 2024. But earlier this year, CARB estimated the project would run out of money as soon as October of this year. 

That’s because Tesla in February reduced the price of two of its models — Model 3 and Model Y — making them again eligible for the CVRP incentive after losing eligibility in 2022. Starting in March, CVRP applications surged to about 12,000 per month. (See California EV Rebate Program Expected to Run Empty Ahead of Plan.) 

Following the board’s approval of the incentive funding package on Thursday, CARB Executive Officer Steven Cliff read a resolution expressing appreciation to the Center for Sustainable Energy, which ran the CVRP program for nearly 14 years. 

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FERC Enforcement Report Details One Closed Probe into Winter Storm Uri

WASHINGTON — FERC on Thursday released its 17th Annual Report on Enforcement, which showed that it has closed down one market manipulation probe into the events around February 2021’s Winter Storm Uri.

The commission still has open, nonpublic investigations into the events around Uri, which led to massive blackouts in Texas where hundreds died and roiled natural gas markets around the country, leading to billions in extra costs for consumers.

“I cannot talk about them,” FERC Chair Willie Phillips said at his post-meeting press conference. “But hear me: For those people who had market manipulation, who committed market manipulation, or if there was any fraud that was imposed upon our consumers — the Federal Energy Regulatory Commission, the Office of Enforcement … will find you, we will punish you, and you will pay the price.”

The investigation FERC closed without action came from a referral of Enforcement’s own Division of Analytics and Surveillance about a gas marketing company that curtailed supply to customers to whom it had delivery obligations by citing force majeure and then sold gas to a different customer at a higher price, the report said.

Enforcement staff reviewed documents and took sworn testimony from employees and determined it lacked evidence to move forward. The firm’s decision to sell gas to a different customer appeared to have been made during a small window of time when the marketing company believed its curtailments would be less substantial.

“Enforcement staff also did not find evidence that the marketing company actively sought out buyers to sell gas to at an elevated price,” the report said. “To the contrary, the purchaser unilaterally reached out to the marketing company requesting gas.”

DAS is regularly watching the electric and natural gas markets that FERC polices, with the report saying in fiscal 2023, its surveillance led to 567,000 screen trips in the electric markets, leading to 43 surveillance inquiries and six referrals for investigation. On the gas side, it had 24,000 screen trips on the year, leading to 27 surveillance inquiries and three referrals for investigation.

The division engaged in enhanced surveillance during “disruptive market events” related to December 2022’s Winter Storm Elliott and a period of high energy prices in the West during the winter of 2022/23. It is continuing to analyze both market events and has already referred some matters related to last winter’s weather events to investigative staff.

Overall, Enforcement opened 19 new investigations and closed nine pending probes without further action. Staff also negotiated 12 settlements that were approved by FERC for a total of $33.4 million: $11.7 million in civil penalties and $21.7 million in disgorgement.

Three other settlements resolved litigation in federal District Court for $4 million in disgorgement, one order to show cause for $4.4 million in civil penalties, and one U.S. Court of Appeals matter for a $10.75 million civil penalty.

Enforcement staff also completed nine audits of public utility, natural gas and oil companies that resulted in 68 findings of noncompliance and 332 recommendations for corrective action. They directed $33 million in refunds and other recoveries.

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Washington’s 2nd Cap-and-trade Reserve Auction Raises $259.5M

The state of Washington’s second cap-and-trade Allowance Price Containment Reserve (APCR) auction raised almost $259.5 million, the state’s Ecology Department said Nov. 15. 

The auction held on Nov. 8 cleared all 5 million carbon emissions allowances put up for bid at a Tier 1 price of $51.90, which represents the soft cap price that triggers the need for the secondary APCR auction. August’s quarterly auction blew through the cap when it cleared at $63.03. (See Wash. Allowance Prices Surge Again in 3rd Cap-and-trade Auction.) 

The APCR auction is a mechanism intended to keep carbon prices in check by releasing a reserve of allowances only to “compliance” entities — those organizations that need to cover direct emissions. The APCR is not available to financial traders of allowances.  

Thirty entities participated in the second APCR auction, including oil refiners, natural gas companies, electric utilities and the state’s two largest public universities. 

The state’s first APCR auction took place in August, raising $62.5 million. (See Wash. Raises $62.5M from Cap-and-trade Reserve Auction.) 

That take from the latest auction translates into more than $1.72 billion collected so far in 2023, the first year of Washington’s cap-and-invest program. Most of the money will go to climate change-related projects. 

The state legislature last spring appropriated roughly $300 million from the state’s first auction in February. Gov. Jay Inslee (D) next month likely will unveil his proposals for the funds in preparation for the 2024 legislative session scheduled to begin in January.  

Washington has one auction left to conduct for 2023, which will occur in December.  

Conservative critics of Washington’s cap-and-trade program have blamed it for the state’s high gasoline prices. When the program was approved in 2021, Inslee’s administration contended it would add only a few pennies per gallon to prices at the pump. This has prompted intense criticism from Republicans. 

Washington this month said it tentatively will seek to link its cap-and-trade system with the California-Quebec market in an effort to reduce the impact on gas prices. (See Wash. Looks to Join California-Quebec Cap-and-Trade Market.) In its last auction, the California-Quebec program cleared allowances at roughly $36.  

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NYISO Braces for the Coming Winter

Winter Operating Study Report

NYISO’s Operating Committee on Nov. 16 approved the winter 2023/24 operating study report, which found New York’s bulk power system can operate reliably this winter based on calculated transfer capabilities.

The report by the ISO’s Operating Studies Task Force estimates internal and external thermal transfer capabilities for the upcoming winter season based on forecast load and dispatch assumptions, as well as any generation or transmission changes since last year. The external analysis covers NYISO’s adjacent balance areas of ISO-NE, PJM and Ontario’s IESO.

The task force reported an increase in internal thermal transfer limits for the Total East (1,525 MW) and Central East (1,825 MW) interfaces due to Segments A and B of the Alternating Current transmission project, which was designed  to increase the deliveries of renewable power to downstate New York.

Changes in cross-state and inter-state winter thermal transfer limits for 2022/23 | NYISO

Changes to external transfer limits also were seen. The ISO-NE-to-NYISO interface saw a decrease of 225 MW due to the reactivation of the Sprainbrook-East Garden City (Y49) 345-kV line. Meanwhile, the NYISO-to-PJM interface increased by 250 MW due to changes in PJM’s dispatch assumptions and the PJM-to-NYISO interface increased by 75 MW due to the redistribution of flows from the Segment A and B project.

NYISO reported that 639 MW of fossil-fuel based generating capacity was deactivated and that 336 MW of renewable generation was added since last year’s study. The appendices are posted online.

Winter Capacity Assessment

Aaron Markham, NYISO vice president of operations, informed the OC that while NYISO expects sufficient capacity for 50/50 peak forecast winter conditions, there is a risk of shortfalls during extreme weather events if non-firm fuel resources become unavailable.

The assessment projects winter generation capacity of 39,668 MW, approximately 750 MW lower than last year’s assessment, due primarily to the retirement of peaker units.

“Over the last approximately five years, we’ve seen about a 2,400-MW reduction in the margin as a result of retirements,” Markham said. “Continued reductions in winter capacity, disruptions in fuel supply or other concerns might result in operational challenges, especially during extreme cold weather events.”

2022 and 2023 winter capacity assessment and comparison | NYISO

Projected winter capacity margins for normal and extreme weather conditions with only firm fuel resources available:

    • 2,641-MW surplus capacity margin for 50-50 peak forecast conditions
    • -161-MW deficit capacity margin for 99-1 peak forecast conditions

Projected winter capacity margins for normal and extreme weather conditions with non-firm fuel available:

    • 9,135-MW capacity margin for 50-50 peak forecast conditions
    • 6,333-MW capacity margin for 99-1 peak forecast conditions

Projected firm fuel generation potentially unavailable at high load or temperature conditions (NYISO 2023 Gold Book, Table I-20):

    • 114 MW lost for 90-10 daily average temperature (5 F)
    • 707 MW lost for 99-1 daily average temperature (-2 F)
    • 707 MW lost for 90-10 daily minimum temperature (0 F)
    • 3,441 MW Lost for 99-1 daily minimum temperature (-8 F)

Markham said NYISO will continue monitoring winter conditions and communicate any emergencies to stakeholders. The ISO is continuing to review the 11 recommendations from the FERC and NERC joint inquiry into the electric outages caused by Winter Storm Elliott. (See Déjà Vu as FERC, NERC Issue Recommendations over Holiday Outages.)

Matt Cinadr, a power systems operations specialist with The E Cubed Co., revisited a stakeholder concern regarding the treatment of special case resources by NYISO, saying the assessment’s findings highlight that these resources should not be overlooked. (See Providers See ‘Mixed Signals’ on Demand Response in NYISO.) “I don’t think anything should be done to push SCRs further out of the market,” he said, “there is value in the [802 MW of SCRs] being shown in your assessment.”

OC Election

The OC elected James Kane, senior energy market adviser with the New York Power Authority, as the committee’s new vice chair. Kane co-chaired the Electric System Planning Working Group in 2021.

October Operations

Markham also told the OC that October’s load peaked at 21,735 MW on Oct. 4, recorded its minimum load of 11,890 MW on Oct. 8, and added 73 MW of behind-the-meter solar since the previous month.

He added that the Oct. 14 annual solar eclipse had a minor impact on BTM production, affecting only 100 MW, significantly less than the anticipated 700 MW. (See “Eclipse Preparation,” NYISO Business Issues Committee Briefs: Sept. 14, 2023.)