Washington carbon prices continued to rise last week after the state’s latest cap-and-trade auction cleared at $63.03, up 13% from the May auction.
The August auction represented the third quarterly sale of allowances by the state, raising roughly $542 million in revenue on 8.6 million allowances sold, according to the Washington Department of Ecology. That translates into about $1.462 billion raised so far this year, with one regular quarterly and one supplemental auction still to go.
Washington Carbon Allowance (WCA) prices have risen steadily with each auction, with the February sale clearing at $48.50 and May’s hitting $56.01. The cap-and-trade program went into effect on Jan. 1, 2023.
“Prices at quarterly auctions are determined by auction participant behavior, so we can’t really speculate as to why bidding has resulted in any increasing settlement prices,” Claire Boyte-White, Ecology’s policy relations manager on cap-and-invest issues, said in an email to NetZero Insider.
“Because our program is still new, one potential explanation is that market participants are still getting their feet under them as they develop their compliance and decarbonization strategies” Boyte-White wrote.
In a summary of the auction results, emissions markets analytics company cCarbon noted that both the California cap-and-trade and Regional Greenhouse Gas Initiative markets saw prices peak during their third auctions before pulling back from those highs.
“Only time will tell if Washington’s WCAs will follow a similar trend!” cCarbon said.
The company also pointed out that financial traders increased their takings in Washington’s most recent auction, winning 14.5% of allowances compared with 10% in the previous auction.
“This increase, coupled with a lower bid ratio of 1.79, strongly suggests that compliance entities are content with their current holding at these price levels,” cCarbon said.
High allowance prices have been blamed for Washington having the highest gasoline prices in the nation this summer, outpacing even California, the only other state with a cap-and-trade program. (See Cap-and-trade Driving up Washington Gasoline Prices, Critics Say.)
Washington officials have been exploring whether the state should link up with the California-Quebec cap-and-trade system as a way to reduce prices, and hope to make a decision this year. That combined market is roughly six times as liquid as Washington’s, with allowance prices hovering at about $35.
Last week’s WCA auction once again exceeded the soft cap of $51.90 that triggers a requirement to hold a supplemental Allowance Price Containment Reserve (APCR) auction, a mechanism intended to contain carbon costs for industry by releasing more allowances into the market. The first APCR auction held in early August raised about $62.5 million on 1,054,809 allowances sold. (See Wash. Raises $62.5M from Cap-and-trade Reserve Auction.)
The next APCR auction is scheduled for Nov. 8 and will offer 1.58 million allowances.
“We anticipate that these extra APCR allowances will moderate prices in the short term,” cCarbon said in its summary. “Indeed, we are already seeing signs of this impact on the prices and demand from compliance entities in this third WCA auction.”
Eversource and National Grid expect their annual peak electricity load in Massachusetts to more than double by 2050, the utilities told the state’s Department of Energy Resources (DOER) last week.
The projections are part of the draft electric sector modernization plans (ESMPs) submitted to DOER by Massachusetts’ investor-owned electric utilities, which detail the electric distribution companies’ plans to meet the massive increase in electricity demand associated with the electrification transportation and heating in the state.
The wide-ranging drafts also include near-term investment proposals, five- and 10-year demand forecasts and solutions planning, and they mark a major change in how the state conducts grid planning.
The Grid Modernization Advisory Council (GMAC), a stakeholder committee created by the state’s 2022 Act Driving Clean Energy and Offshore Wind and convened by DOER, will review the filings, solicit public feedback and provide comments on the utilities’ drafts.
“It’s really taking a forward-looking approach for the first time in Massachusetts’ history,” said Kyle Murray, Massachusetts program director for the Acadia Center and GMAC voting member. Murray said grid planning in the state historically has happened in an “ad hoc manner.”
Murray added that one of the council’s goals is to engage the public in the grid modernization process and include voices that historically have been absent from these proceedings.
The draft ESMPs outline the large infrastructure investments that will be needed to enable the clean energy transition, including huge increases in peak electrical loads. National Grid expects its annual peak to increase from about 4.6 GW to 10.7 GW.
National Grid 2025-2029 proposed ESMP investments | National Grid
“Annual peak load, which is the maximum demand on the system in a given year, is expected to grow across our network 7% by 2029 and 21% by 2034 relative to 2022 levels, and more than double by 2050,” National Grid wrote in its 726-page report.
Eversource expects an even larger increase for its system, anticipating its peak to rise from about 6.1 GW to 15.3 GW.
“The majority of this 150% increase in electric demand by 2050 is driven by electrification of heating needs (about 50%) with the remaining driven primarily by electrification of transportation needs (25%) and normal load (25%),” Eversource wrote.
The utilities also noted that the increasing reliance on distributed energy resources (DERs) will further strain the grid and necessitate additional upgrades.
To meet the expected demand increases, Eversource proposed building 12 new substations and upgrading 16 existing substations. The company also proposed three new substations and 14 upgrades to accommodate additional solar resources. National Grid proposed upgrading or expanding 18 existing substations and building 28 new substations by 2034.
“Absent making these system investments in advance of these new peak demand levels, the expected load growth will result in overloads of existing equipment, which would impact the safety and reliability of our network operation,” National Grid wrote.
National Grid peak load forecasts | National Grid
Murray said one of his main hopes for the process is to help clear out the interconnection backlog of renewable energy projects.
“We know we need as many renewables on the market as possible, and yet they’re coming on at a pace that’s kind of like a trickle,” Murray said.
“Building system capacity with substations and battery storage systems will provide a critical foundation for enabling electrification and reliable interconnection of DERs,” Eversource wrote.
The utilities emphasized the importance of early public engagement while making these investments, and jointly proposed the creation of a Community Engagement Stakeholder Advisory Group (CESAG) to help boost engagement with potentially impacted communities. Under the utilities’ proposal, the group would be led by the utilities, with members agreed upon by the GMAC.
Eversource 2025-2034 proposed capital investments | Eversource
In an August letter to the GMAC, María Belén Power, undersecretary of environmental justice and equity at the Office of Energy and Environmental Affairs, stressed the importance of including environmental justice communities in the infrastructure siting process.
“[Environmental justice] populations should be engaged in public processes from the very beginning, not as an after-thought, and the engagement must be coupled with meaningful outcomes and results,” Power wrote. “Adding equity or community outreach as a final step in the process does not allow for a meaningful process. Successful community outreach happens when the voices and perspective of those most vulnerable are reflected in the outcome.”
Power said all communities affected by new grid infrastructure should be given ample opportunity to participate in siting processes, with accommodation made for the different languages spoken by residents. The undersecretary also emphasized the importance of considering the cumulative effects of grid infrastructure.
“When planning for new energy infrastructure or enhancement of existing ones, we must ensure we are not causing additional harm to those who have historically been overburdened,” Power said. “When possible and if feasible, if a project may cause additional harm or burden on EJ populations, an alternative site should be identified.”
The utilities also outlined some mechanisms to reduce future demand, including energy efficiency, advanced metering infrastructure, managed charging and time varying rates.
“Regulatory and tariff changes that enable time-varying rates and recognize the shift toward greater electrification are required to support more impactful offerings to offset peak demand growth with increasingly flexible loads and expanded deployment of distributed resources,” National Grid wrote.
Larry Chretien, executive director of the Green Energy Consumers Alliance and a GMAC member, told RTO Insider he still is reviewing the drafts, but agreed on the need to develop programs like time-varying rates and managed charging focused on reducing peak demand. High demand peaks lead to both higher costs for consumers and increased fossil fuel combustion.
“We think it’s sacred that we’ve got to reach our climate goals, but we also want to make sure that it can be afforded by folks who are economically vulnerable,” Chretien said. “I want to push the utilities on trying to bend the demand.”
The GMAC will hold public listening sessions Oct. 30 and Nov. 1, with final feedback and recommendations from the GMAC due Nov. 20. The utilities then must file their final ESMPs with the Department of Public Utilities in January.
The nation has a looming problem. The infrastructure upon which millions of Americans rely on to power their daily lives is growing older while demand on regional power grids is breaking all-time records with increasing regularity. The country’s regional grid operators lack sufficient access to generation in neighboring regions, resulting in preventable power outages and soaring electricity prices during extreme weather events. Even under normal operating conditions, a lack of import and export capability between various parts of the country can result in higher power costs.
The construction of high-voltage transmission lines between regions has been stymied over the years for various reasons, but it is clear we increasingly need new interregional lines, both now and in the future. One relatively simple way to accomplish this would be for Congress to direct FERC to establish a minimum interregional transfer capacity requirement to ensure that grid operators have enough capacity to export or import a certain amount of power to neighboring regions at all times. Doing so will strengthen the nation’s resilience to extreme weather events, increase overall grid reliability and ultimately reduce the cost of delivered electricity to customers.
Fortunately, this policy option has recently been the focus of significant discussion by stakeholders. Late last year, FERC discussed such a minimum transfer standard. Notably, in its post-workshop comments, the U.S. Department of Energy emphasized that its draft National Transmission Needs Study finds a “pressing need for additional electric transmission infrastructure, including interregional transmission.” Additionally, this topic has merited review by the Joint Federal-State Task Force on Electric Transmission, a collaborative dialogue between FERC commissioners and state utility regulators.
So, what’s the “right” amount of transfer capacity? Some grid experts have called for a minimum interregional transfer capacity requirement ranging from 15 to 30% of peak load. While there are benefits and costs associated with a higher or lower percentage, there is wisdom in setting a uniform minimum requirement. As I recently testified before the Senate Energy and Natural Resources Committee, it would be more expeditious if Congress were to define and set a reasonable threshold rather than tasking FERC with a multiyear stakeholder process to determine the requirement, a process that would surely further delay critical projects’ buildout.
The need for new transmission lines also serves to mitigate the impact of extreme weather events, which are undeniably increasing in severity and frequency. In the first seven months of this year, 15 extreme weather events across the country — several of which caused power outages — each resulted in $1 billion or more in damages. These events accounted for the most disasters over the period since 1980. Extreme weather has also contributed significantly to congestion costs in recent years. While power outages during storms are never fully preventable, we can prepare our electric grid to better withstand them, as interregional transmission lines can transport available power from several states away to areas where local generators cannot meet demand.
Further, as I testified, long-distance wires connecting regions serve as an important insurance policy: While grid operators hope to avoid asking neighboring grids for electricity, it is important to have the ability to do so when a situation arises. For example, the addition of high-capacity interregional transmission lines from Texas to neighboring regions could have prevented the devastating storm-induced outages in February 2021, according to an analysis from power sector consulting firm Grid Strategies. Given the tremendous cost savings associated with additional interregional transmission capacity, a line could have paid for itself in four days during that cold snap.
More recently, some utilities could have saved upward of nearly $100 million per gigawatt of capacity in late 2022 if they were able to wheel more power in from the Midwest or New York. Instead, unplanned generation losses of all types exceeded 70 GW, and several balancing authorities ordered firm load shed of more than 5 GW over the Christmas holiday.
Moreover, increasing congestion on the regional power grids — when there is insufficient transmission capacity to deliver the most affordable power to customers, forcing more expensive generating units to run — cost the U.S. an estimated $20.8 billion in 2022, according to Grid Strategies. While this savings estimate can be debated, it is indisputable that customers pay more when they are unable to access cheaper supplies of electricity.
These facts are not lost on utility regulators. During the past year, members of the federal-state transmission task force reviewed the merits of a minimum transfer capacity standard and, more broadly, the need for more interregional transmission. In an op-ed published by RTO Insider in April, former Arkansas Public Service Commission Chair Ted Thomas touted the “significant reliability benefits” a standard would provide. (See Stakeholder Soapbox: Transmission Keeps the Lights On.)
At a task force meeting, former FERC Chair Richard Glick recognized that over the last decade, “there really hasn’t been any interregional transmission built … so we’re in a situation where I believe we need to consider, are there reforms that are necessary to move forward?”
Vermont Public Utility Commissioner Riley Allen found that there is a “growing body of evidence [that] interregional transmission can contribute to a significant degree on a triad of needs,” including affordability, reliability and clean energy. And Dan Scripps, chair of the Michigan Public Service Commission, similarly emphasized that “there’s no doubt that increased interregional transfers and interregional transmission can also offer additional benefits, particularly economic benefits, but ultimately the real value is ensuring that we have a grid that can support reliability and enhanced resilience, particularly in times when the grid operates in ways other than for which it is originally planned.”
I agree with my colleagues on these points, but I also know that the cost of developing new energy infrastructure projects must be weighed against a number of competing considerations. That said, I am confident that building more interregional transmission lines is a good, near-term investment that will deliver benefits now and for future generations. The facts are clear; it’s the political will that is needed.
Jason Stanek is the former Chairman of the Maryland Public Service Commission and previously served as a co-chair of the Joint Federal-State Task Force on Electric Transmission.
Several generation owners and PJM are progressing toward an agreement regarding the non-performance charges the RTO assessed in its allegation the generators failed to meet their capacity obligations during the December 2022 winter storm, according to the settlement judge mediating the deliberations (EL23-53, et al.).
Judge Matthew J. Vlissides Jr. wrote in a Sept. 1 status report that a “majority of the participants indicated that they reached a settlement in principle” as of the previous day’s conference and he recommended terminating the process without holding further meetings. (See FERC Sends Elliott Complaints Against PJM to Settlement Judge.)
“These participants represent that they are finalizing the settlement materials and anticipate filing the settlement package by late September 2023,” he said.
East Kentucky Power Cooperative spokesperson Nick Comer said EKPC is pleased the parties have reached a settlement in principle but wouldn’t comment further until the terms have been filed with the commission. PJM declined to comment.
The companies involved in the settlement procedures include Essential Power (EL23-53), Aurora Generation (EL23-54), the Coalition of PJM Capacity Resources (EL23-55), Talen Energy (EL23-56), Lee County Generating Station (EL23-57), SunEnergy1 (EL23-58), Lincoln Generating Facility (EL23-59), Parkway Generation Keys (EL23-60), Old Dominion Electric Cooperative (EL23-61), Energy Harbor (EL23-63), Calpine (EL23-66), Invenergy (EL23-67) and EKPC (EL23-74).
PJM stated the penalties from Winter Storm Elliott total about $1.8 billion, though during stakeholder meetings it has said it’s likely some percentage of generators will default on the penalties. To reduce the impact to those companies, PJM filed to extend the payment period for non-performance charges to nine months, which FERC approved in April. (See “FERC Approves Alternative Billing Schedule,” PJM: Elliott Nonperformance Penalties Total More Than $1.8B.)
The commission established the settlement judge procedure June 5 to see if the parties involved in a dozen complaints could reach an agreement within 60 days and extended the process an additional month on Aug. 14 after Vlissides wrote a progress report finding the parties were “significantly progressing” toward settlement.
PJM asked the commission to establish a settlement judge in April, arguing that while it maintains the penalties are valid, a faster resolution could support the long-term health of the capacity market and result in more consistent settlement outcomes.
“The capacity market also is designed in large measure to signal the need for new capacity resource investment, and the expectations of the financial and investment community accordingly are an important backdrop to the operation of this market,” PJM said in its earlier filings. “Timely, consensual resolution of these disputes thus could, potentially, help support the long-term health of the resource adequacy construct in the PJM region.”
The complaints argued PJM improperly declared emergencies in regions where it was not warranted and continued to export to other balancing authorities in contravention of its tariff and the RTO had not provided generators with the required notifications they were expected to be available to allow them to procure fuel.
AUSTIN, Texas — The Infocast Texas Clean Energy Summit attracted several hundred developers, asset owners, financiers, investors and ERCOT stakeholders to discuss the booming opportunities and looming challenges in today’s renewables environment.
Speakers and panels discussed large flexible loads, crypto mining, energy storage, Texas’ continued reliance on renewable energy and the challenges facing ERCOT from the state’s tremendous growth and insatiable demand for energy. Many of those solutions will be affected by the new laws and rules passed by the recent Texas Legislature.
Part of a panel addressing the new legislation, Mark Stover, director of state affairs for Apex Clean Energy, pointed to a projected slide that included images of a couple of news clippings.
“I think there were about 50 bills that impacted our industry, but there were 19 bills that did not get across the finish line. Some were killed on the floor, some never got on a hearing, others kind of just got lost in the shuffle. But there were 19 bills that would have directly harmed the clean energy industry. Fortunately, those went away.”
One of the bills that failed (Senate Bill 624) would have required wind and solar facilities to acquire special permits from the PUC, a requirement thermal generators wouldn’t face.
“That was an industry killer that would have been absolutely devastating for the clean energy industry,” Stover said. “Fortunately, we were able to get the recession and ensure that that bill did not pass, no trouble.”
Still up in the air is the shape of the future ERCOT market. The grid operator and the state’s regulators still are pushing forward with the performance credit mechanism (PCM), a market tool that would retroactively reward dispatchable generation that meets performance criteria during the tightest grid periods with incentive payments.
Staff plans to draft a strawman proposal incorporating the Public Utility Commission’s feedback and hold a series of workshops with stakeholders and PUC staff. ERCOT and the market monitor will perform a cost-benefit analysis before the legislature next meets in 2025. The ISO expects it will take another two years to implement the PCM.
“So where do we go from here? There’s a lot of details to be worked out,” said Nate Miller, a director with Energy and Environmental Economics (E3). (The firm studied several market designs for the PUC but did not recommend the PCM.)
He said a reliability standard first must be determined, as it will set the PCM’s performance credits awarded to generators. Then comes the question of dispatch requirements, hybrid resources only being part of the equation.
“There’s a lot of details in the PCM that could significantly weigh the impact of PCM on the market,” said Resmi Surendran, vice president of regulatory policy for Shell Energy North America. “The PCM, based on some studies, could have been a one-third reduction in the energy price, which is the revenue stream for renewables. Hopefully, it can be implemented as an additional revenue stream … without reducing the revenue stream for everyone else.”
While the renewable sector may have escaped more severe legislation this year, it may have been enough to scare off some potential investors.
“Investors saw what happened in that last Texas session and are sort of unsure about what’s going to happen in the next session for understandable reasons,” said Frank Swigonski, director of market design for Pine Gate Renewables. “I’ve heard people say that there’s always been anti-renewable sentiment in Texas and this was just another day at the office. The difference last session was it was a little bit more pronounced and it got a little bit more national attention. I think that’s something that we’re going to be dealing with as we’re trying to get investment projects long term.”
Swigonski said the PCM remains the biggest question mark with how costs will be allocated and its effect on the energy market.
“That uncertainty itself is a challenge because other developers can probably feel the same way and we can execute around new interconnections, cost allowances and new firming requirements, as long as we know what those requirements are,” he said. “But as long as there’s a big question mark in your financial spreadsheet, it’s really hard to close on them right.”
That said, Swigonski still says the Texas energy market is a great place to invest.
“The interconnection process in Texas is the fastest, the easiest and cheapest anywhere in the country. None of that changed,” he said.” Texas is a big state. It’s got a dynamic, dynamic economy, there’s load growth, low taxes, and there’s a lot of sunshine and wind.”
“We’re pretty invested in Texas, and we think that the policy risk is very manageable,” said Allan Schurr, chief commercial officer of storage developer Enchanted Rock. “I can tell you that having lived a former life in California that it is a wild card. Texas is a lot more predictable. It’s undergoing a lot of changes with the market redesign. I don’t know about the fundamentals but somehow, through the noise and the fog, there’s still opportunity for us.”
Living with Large Flexible Loads
When Bitcoin miners — having been shoved out of China because of their insatiable demand for power — began flocking to Texas in 2021, Gov. Greg Abbott (R) welcomed them in a tweet proclaiming the state “will be the crypto leader.”
Two years later, Bitcoin mining consumes about 2.2 GW of power. That consumption could triple should the additional 4 GW of mining operations approved by ERCOT’s interconnection process become energized. And while the mining loads gobble power, their ability to shut down quickly during tight operations is what makes them appealing to grid operators.
ERCOT has adapted quickly to Bitcoin, data centers and other large, flexible loads (LFLs). It has created a working group dedicated to the loads and hired an LFL interconnection manager, Agee Springer. It also has proposed new LFL classifications as either curtailable load resources or registered curtailable loads; the former would participate in economic dispatch; the latter would operate outside SCED.
“The optimal solution for reliability would be for as many of these loads as possible to participate in the economic dispatch,” Springer said. “What this really does is it allows their behavior to be factored into the economic dispatch and accounted for when generation is instructed on how much power to produce. We see this as kind of a benefit to both loads and to ERCOT. It takes the guesswork out of being price responsive. You feed your desired behavior and your strike prices into the economic dispatch and then your behavior is coordinated with the rest of the grid.”
He said the proposed concepts, which could be ready next year, would provide more data from load resources and improve the accuracy of ERCOT’s forecasts. That would create a bigger pool of ancillary services, Springer said, “so that’s a benefit for everyone.”
The Clean Energy Buyers Association’s Bryn Baker, senior director of market and policy Innovation, stressed the need to be able to run a 21st-century grid that keeps the lights on in 21st-century weather.
“That requires thinking more expansively about what is dispatchable versus non-dispatchable. Certainly, renewables are not always reliable and the dispatchable energy is not always reliable,” she said.
“A big success story, besides demand response, is wind, solar and storage holding up the grid when its groaning at the edges,” Baker added. “It is going to require thinking about things differently. We’re going to need new technologies and new approaches … but most important is that we’re building [an ERCOT] market where that innovation happened, where testing those new technologies and approaches is possible.”
IRA Could Be Boon to Texas
Several panelists marked the one-year anniversary of the Inflation Reduction Act, which provides billions of dollars in incentives, grants and loans to support new investments in clean energy and other areas.
“When you look at it at first blush, you see a lot of positive things that are more long term,” said Matt Pawlowski, vice president of development for NextEra Energy Transmission. “We’ve gone from the years of three to five years [of tax credit deadlines], etc., where you’re kind of rushing into everything because you think it’s going to expire. Now, we have a much longer runway … the IRA has been a longer-term view of things that we’ve wanted for years, instead of three-, four- and five-year chunks.”
George Hardie, vice president of business development for Pattern Energy Group, agreed the IRA will spur new development in Texas.
“It’s a mixed bag of theories and it’s certainly ample ammunition for issues in some of the congested areas in the Texas Panhandle, where there’s more power than can get to some of the load centers,” he said, noting the demand placed on the grid by oil and gas production in the Permian Basin. “We’re seeing astounding load growth … all that oil and gas is being electrified, so there’s going to be a significant amount of renewables and weather, as well solar, needed for that density.”
A federal appeals court on Tuesday rejected a challenge to FERC’s 2020 revisions to how it enforces the Public Utility Regulatory Policies Act, though it concluded the commission committed a “serious violation” by not conducting a formal environmental assessment (EA) before issuing the order (20-72788).
Multiple renewable energy industry and environmental advocacy groups petitioned for review of Order 872, which they argued made it more difficult for independent, non-utility-owned energy generators to be designated qualifying facilities under PURPA (RM19-15, AD16-16). (See FERC Rejects Challenges on PURPA Changes.)
The 9th U.S. Circuit Court of Appeals, however, found that FERC holds broad rulemaking discretion and its interpretations of the law were not unreasonable. The court also rejected the petitioners’ challenges to four specific provisions of the order.
The court did agree with the petitioners’ contention that FERC violated the National Environmental Policy Act by not preparing an EA before issuing the order. It remanded the order to FERC to conduct an EA, but it declined to vacate it.
“Although FERC’s failure to prepare an EA is a serious violation, Order 872 does not suffer from fundamental flaws, making it unlikely that FERC could adopt the same rule on remand, and the disruptive consequences of vacatur would be significant,” the court said.
PURPA directed FERC in 1978 to promulgate rules to encourage development of two types of QFs: alternative energy sources such as renewables owned by the same person within 1 mile of each other that totaled no more than 80 MW generation capacity, or fossil-fired cogeneration facilities.
The law mandated that electric utilities buy the power generated by QFs under rate guidelines established by FERC and set by states. In response, FERC issued Orders 69 and 70 in 1980.
Congress changed the statutory language via the Energy Policy Act of 2005, and FERC responded with Order 688, which among other things established a rebuttable assumption that facilities with not more than 20 MW capacity do not have adequate, nondiscriminatory access to markets.
With Order 872, issued under then-Chair Neil Chatterjee (R), the commission explained that extensive technology advances and dramatic energy industry changes in the preceding 40 years made significant revisions necessary.
Among other things, FERC:
expanded the 80-MW calculation radius to up to 10 miles and set a list of factors to establish whether facilities were “separate”;
allowed states to eliminate the fixed-rate option;
gave states additional flexibility to calculate utilities’ avoided costs; and
reduced the 20-MW nondiscriminatory threshold to 5 MW.
Ruling
The 9th Circuit rejected the petitioners’ contention that Order 872 discourages development of QFs, and therefore violates PURPA, which directed FERC to encourage such development.
The judges shot down various other arguments as well. They ruled that:
FERC did not overstep the authority granted to it by PURPA, and Order 872 meets the test of the Chevron
FERC was not arbitrary or capricious in making the rules; it was reasonable and used discretion delegated to it by Congress.
Order 872’s rate-related provisions do not violate PURPA’s nondiscrimination requirement.
The court did fault FERC for its reasoning for not preparing an environmental impact statement or an EA.
“FERC misunderstands NEPA’s requirements,” it wrote, adding that the commission’s own regulations for implementing NEPA support its conclusions.
“It was eminently foreseeable that a regulatory change of this magnitude could produce significant environmental effects,” it wrote. “It was a near certainty, for example, that at least some QFs could lose their status under the 2020 site rule, or that at least some states would eliminate the fixed-rate option for the calculation of avoided costs.”
But the court concluded that vacatur would cause severe trouble, as several states have already initiated proceedings in response to the order and some utilities already have received relief from mandatory purchase obligations with facilities rated at 5 to 20 MW.
“Victory. Again,” Chatterjee posted on X in response to the news. “The Chatterjee FERC record in the courts is quite strong.”
California will need to double its public EV charging infrastructure between 2030 and 2035 to serve the expected number of electric vehicles in the state, according to a new report by the California Energy Commission (CEC).
That draft Electric Vehicle Charging Infrastructure Assessment, which highlights the massive needs stemming from the state’s aggressive transportation decarbonization goals, coincided with the release of a CALSTART working paper on phasing the national EV charging infrastructure build-out.
The CEC assessment estimated that by 2035, more than 15 million light-duty electric vehicles in California would require more than two million chargers at public and “shared private” locations, more than doubling the seven million vehicles and one million chargers projected for 2030. This estimate did not include chargers installed in single-family homes but included shared private locations such as multifamily dwellings and workplaces.
The estimate of 15 million electric light-duty vehicles represents a tenfold increase from today. In the first quarter of 2023, California surpassed 1.5 million light duty electric vehicles, with nearly 85% full EVs, 15% plug-in hybrids (PHEVs) and less than 1% hydrogen fuel cell vehicles. In that quarter, full EVs and PHEVs accounted for more than 20% of new passenger vehicle sales. Light-duty vehicles were defined as vehicles with a gross vehicle weight rating below 10,000 pounds, primarily privately owned cars and trucks.
The assessment was the second biennial report required under Assembly Bill 2127. The draft report extended the 2021 analysis by five years to 2035, the target date for Gov. Gavin Newsom’s ambitious transportation electrification goals. His Executive Order N-79-20 set goals for 100% zero-emission new passenger car and truck sales and 100% zero-emission vehicle operations for drayage trucks by 2035.
For the grid, peak weekday charging for light-duty vehicles is likely to reach 4,000 MW in the middle of the day by 2030, with more than a third of that from DC fast chargers. Residential charging, in contrast, would peak overnight, with the estimated demand showing a significant rise at 9 p.m. when time of use rates drop.
The assessment’s estimates for the mix of Level 1, Level 2 and DC fast chargers for light-duty vehicles appeared to be conservative, with only 83,000 DC fast chargers in the 2.11 million total, or less than 4%. That is a much lower percentage than today when California has 9,808 DC fast chargers to its 82,000 public Level 2 chargers.
In addition to building out EV charging infrastructure for passenger vehicles, the assessment forecast demand for fast chargers for commercial vehicles. The 377,000 medium- and heavy-duty EVs in 2035 would need an additional 256,000 20 to 150-kW DC fast chargers in depots, as well as 8,500 higher powered 350 to 1,500-kW public DC fast chargers. For medium- and heavy-duty vehicles, the load on the grid is more spread, with a peak demand in 2030 of 800 MW overnight, largely from vehicles at depots.
CALSTART, a nonprofit consortium focused on clean transportation, released a working paper on charging infrastructure for zero-emission medium- and heavy-duty vehicles throughout the United States. In Phasing in U.S. Charging Infrastructure: An Assessment of Zero-Emission Commercial Vehicle Energy Needs and Deployment Scenarios, CALSTART recommended phasing the building-out of commercial vehicle charging infrastructure, starting with “favorable launch areas.” The phased approach could support commercial EV uptake at the rates specified in the Global Memorandum of Understanding on Zero-Emission Medium- and Heavy-Duty Vehicles (Global MOU), which the United States signed in 2022.
“This phased approach can manage distribution grid upgrade timelines and maximize utilization even with the Global MOU’s attainable market penetration rates, which exceed those proposed by U.S. regulators,” the report said. “Favorable regions include where 1) industry concentrates, 2) public and private funds have high leverage, 3) policy is supportive, 4) energy will cost less or 5) distributed grid modernization will occur.”
The Virginia State Corporation Commission last week ruled that Dominion Energy overstepped its authority in requiring distributed solar for large customers to go through new processes that led to spikes in the cost of installation.
The Virginia Distributed Solar Alliance filed a complaint against the new procedures in June, alleging they overstepped the regulated utility’s authority, as the SCC has been looking into the issues around interconnection of distributed sources in other cases. The SCC last approved interconnection rules back in 2020 and it is now looking at additional changes.
The commission on Aug. 30 agreed to suspend the parameters and interconnection agreements until it wraps up its open proceedings looking into the issues, but it declined to “address the myriad of additional relief” sought by the solar group.
The group’s other requests can be taken up in other proceedings, the SCC said. It also noted that it was not taking lightly Dominion’s claims about safety and reliability, but that it lacked authority to implement the new processes without a prior order.
“Dominion should continue to take the actions necessary to maintain the immediate safety and reliability of its system; this may include, but need not be limited to, seeking specific authority from this commission in one or more formal proceedings,” the commission said.
The utility adopted new parameters for projects between 250 kW and 1 MW and projects that range from 1 to 3 MW in December 2022, but the solar group’s complaint focused on their impact on projects below 1 MW, which are midsized, nonresidential projects. The complaint alleged that the new rules have led to costs, delays and barriers to adding such distributed generation around Virginia.
The rules that were suspended by the SCC led to “unprecedented” costs and delays by potentially requiring distributed solar to pay for substation upgrades and dark fiber cable and relay panel equipment. Dark fiber costs between $150,000 and $200,000/mile; relay panels can cost $250,000 for equipment and potentially more than double that for engineering, mobilization and construction management.
The complaint listed a number of anecdotes, including one at the James River Juvenile Detention Center for Henrico County, where Dominion estimated $2.25 million in preliminary costs for a 686-kW system. Prince William County Schools faced similar costs on a 987-kW array it was planning. Both projects, and others owned by private firms, proved too expensive with the extra costs that Dominion assessed under the now-suspended rules.
Dominion had argued in a filing last month that it needs to update the rules as distributed generation has grown rapidly in Virginia since a law passed expanding its net energy metering program.
“As a result of these changes, more net metering generation, with higher capacity ratings, are now rapidly developing and penetrating the company’s electric power system,” the firm said. “The company has been tasked with integrating more net metering distributed energy resources, with higher capacity ratings, that are now permitted to produce up to 150% of the customer’s expected annual energy consumption.”
The parameters suspended by the SCC were meant to ensure Dominion’s ability to specify the equipment and technical specifications needed to establish safe and reliable interconnection, the company said.
MISO’s Independent Market Monitor took his concerns to stakeholders last week over what he deems unrealistic fleet assumptions in MISO’s long-range transmission planning.
MISO Independent Market Monitor David Patton delivered a presentation at an Aug. 31 long-range transmission plan (LRTP) teleconference to let stakeholders know he’s concerned MISO’s long-range transmission planning could upend market functions. He said the issue is serious enough for him to delve into MISO’s transmission planning matters when usually he’s confined to market matters.
“The performance of the market is greatly impacted by out-of-market investments … coordinated by MISO,” Patton said. He said overblown transmission investments can “fundamentally” affect locational marginal prices and ancillary services.
Patton said the capacity expansion prediction MISO is using to develop its second LRTP portfolio contains an overestimated amount of intermittent, renewable generation and an exaggerated amount of dispatchable generation retirements.
“Planning to that future, I think is highly problematic,” Patton said.
MISO would come up with a “very different set of future transmission needs” if it includes a more realistic fleet projection that includes battery storage, hybrid storage, and renewable resources and new natural gas generation, he said.
Patton’s criticisms are contained in this year’s State of the Market report. He also appeared in front of MISO board members to critique MISO’s transmission planning future. Board members have questioned Patton’s departure from markets into transmission planning. (See “LRTP Doubts,” MISO IMM Zeroes in on Tx Congestion in State of the Market Report.)
Minnesota Public Utilities Commission staff member Hwikwon Ham said he had serious concerns with Patton’s critique of transmission planning. He asked what’s keeping the IMM from weighing in on states’ integrated resource planning, because that also affects MISO markets.
Ham said MISO’s second LTRP portfolio’s assumptions are based directly on states’ emissions reductions plans.
“You are directly defying that outcome,” he said.
American Transmission Co.’s Bob McKee agreed MISO’s futures use “actual” state plans and planned retirements.
Patton said he wasn’t trying to question state directives. But he said his analysis shows a 2040 fleet mix that contains 108 GW less solar and wind resources than MISO is planning for. He said MISO states still could achieve their official emissions reduction targets even with the absent, hypothetical intermittent resources. Patton said he didn’t account for “announcements made by governors that may or may not make their way into legislation.”
MISO expects it will add 369 GW of new, mostly renewable resources by 2042, bringing its total installed capacity to 466 GW. However, only 202 GW of that capacity is accredited; staff assumes a declining effective load-carrying capability for the renewable additions. (See MISO: Long-range Tx Needed for 369 GW in Interconnections.)
Patton also said he found MISO’s forecast that it will have 29 GW of flexible resources — including green hydrogen, long-duration battery storage, small modular nuclear reactors and reciprocating internal combustion engines — highly unrealistic. He questioned whether those technologies will be commercially available by the 2040s.
Patton also said half of MISO’s 13 states don’t have definitive decarbonization mandates. He said MISO shouldn’t assume members don’t build dispatchable gas resources between now and 2030.
But some stakeholders said they viewed Patton’s view as more environmentally harmful and more expensive to ratepayers, because of an expansion of gas infrastructure. Some also said it was disrespectful for Patton to show up to a planning meeting so late in the game to advocate for a rethink of MISO’s transmission planning future.
Patton said he will make a point to participate in MISO’s LRTP benefit analysis going forward.
Sustainable FERC Project attorney Lauren Azar said she worried Patton’s transmission analysis based on a concern for the market is shortsighted because the market only sends short-term signal and doesn’t indicate “the type of grid we’re going to need in 2042, or even 2035.”
“MISO is [a] leader in the nation in building 20 years out,” Azar said.
But Patton warned about the dangers of overbuilding transmission based on a flawed view of future capacity.
“If we adopt a future that’s not realistic, I don’t think we can be confident in that,” he responded.
Southern Renewable Energy Association’s Andy Kowalczyk asked Patton to consider MISO may be running the risk of underbuilding the transmission system, which also would raise costs for ratepayers. He said he didn’t think battery storage would “absorb” the need for new transmission because it still needs to charge from and dispatch to the system.
Sustainable FERC Project’s Natalie McIntire said she was skeptical of Patton’s analysis that MISO states could achieve a dramatic, more-than-90% carbon reduction by 2042 while removing 108 GW of renewable energy from the equation.
But North Dakota Public Service Commissioner Julie Fedorchak said she thought it was worthwhile for Patton to question MISO’s fleet assumptions when the second LRTP portfolio could cost as much as $30 billion.
“We absolutely need more analysis instead of less,” she said.
Mississippi Public Service Commission consultant Bill Booth called for MISO to take a fresh look at its battery storage addition assumptions.
“This is an expensive endeavor. We cannot afford to build wasteful transmission. …These are costs that are going to be borne by ratepayers, and we need to make sure they’re necessary and needed and the best thing for the footprint,” said Kavita Maini, an energy consultant representing MISO end-use customers.
MISO Responds
MISO Vice President of System Planning Aubrey Johnson said MISO in the past has been accused of not “being big or bold enough in transmission planning,” especially in its 2011 multivalue transmission portfolio. He said MISO is embarking on “least regrets” long-range transmission planning.
Johnson reminded stakeholders that the LRTP portfolios are being developed to resolve major regional system issues, not ensure the interconnection of an additional 369 GW, or ensure a certain generation mix. He said MISO’s planning future is meant to reflect members’ resource planning.
“It’s not the goal to maximize transmission building, but to maximize the value of the transmission we recommend,” Johnson said. He added he’s confident MISO will advance the most valuable second LRTP possible.
FERC has ruled it’s appropriate for MISO to continue to preclude renewable resources from providing ancillary services in its markets, countering a solar trade group’s complaint.
FERC said the Solar Energy Industries Association (SEIA) didn’t present evidence that MISO’s policy of barring renewable output from ancillary services was producing unfair rates (EL23-28).
In an Aug. 31 order, the commission said much like its recent order authorizing MISO’s ban on wind and solar generation from supplying ramping capability, it remains the case that renewables rarely are the most economic choice to supply operating reserves because their locations exacerbate already binding transmission constraints. (See related story, FERC: MISO Can Ban Intermittent Resources from Providing Ramp.)
SEIA lodged the complaint early this year in part because of MISO’s effort to bar renewables from furnishing ramping. (See Solar Trade Group Challenges MISO Ban on Renewable Ancillary Services.) The group argued that MISO’s dispatchable intermittent resources are operationally capable of providing regulation service, spinning reserves and supplemental reserves and that MISO’s market rules today discriminate against some resources because they’re tailored to the large, centralized power plants of the past. It also said instating renewables’ eligibility for such services would foster competition.
But FERC said SEIA didn’t demonstrate that renewables “can reliably deliver the ancillary services they are cleared to provide to the MISO market in a manner comparable” with other resources.
The commission acknowledged MISO’s current market clearing software isn’t sophisticated enough to consider locations of resources and nearby congestion rendering them non-deliverable. It said if MISO were to clear operating reserves from renewable sources, congestion would prevent them from making it to market in most cases. Thus, allowing procurement would create a reliability issue and payments to unhelpful resources, FERC decided.
The commission also agreed with MISO that it’s far more lucrative for renewable resources to provide energy over ancillary services.
Lastly, FERC said SEIA’s arguments differed from the commission’s previous regulations requiring open access transmission service and establishing separate performance and capacity payments for frequency regulation service, and its ruling against the undue discrimination of electric storage resources.
“Those orders did not require that every resource type must be allowed to provide such services,” FERC said.
FERC said though it’s “undisputed” MISO’s tariff treats renewable and nonrenewable resources differently with respect to ancillary services, SEIA didn’t prove that renewable and nonrenewable resources are “similarly situated” because when renewables are cleared to provide ancillary services, they’re trapped behind a transmission constraint.
As with their order blocking MISO renewables from providing ramp capability, Chairman Willie Phillips and Commissioner Allison Clements issued a joint statement to emphasize that the order was limited. The two said MISO’s market dynamics are set to change — and the snub likely will be temporary — as renewable energy becomes more prevalent.
“We strongly urge MISO to continue to improve and enhance the software on which its markets rely. Both MISO and the commission recognize the limitations of MISO’s current software, and the record suggests that these shortcomings are contributing to problems that go beyond [renewable] integration alone,” Phillips and Clements wrote. “We anticipate the continued development of these resources and encourage MISO to be ready for them as they come online.” They said MISO should devise ways to account for locational congestion in its software when selecting resources.
