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December 28, 2024

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NARUC Panel Calls for Clean Energy, GHG Emissions Tracking Standards

WASHINGTON ― President Biden wants all federal agencies to use 100% carbon-free electricity (CFE) ― 50% of which will be matched hour for hour 24/7 ― by 2030. Rhode Island’s Renewable Energy Standard will require the state’s retail electricity suppliers to ensure that 100% of the power they provide is from renewable sources by 2033. And Google (NASDAQ:GOOGL) is targeting 100% clean energy, matched hour for hour 24/7, by 2030.

Despite their very different goals, these clean energy buyers all face a common challenge: figuring out how to keep track of both the clean energy they use and the carbon emissions they cut, according to a Feb. 13 panel discussion at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit.

“The way we account [for] CFE — in fact, the way the industry generally counts CFE — is not actually aligned with the way greenhouse gas emissions are counted for Scope 2 emissions,” said Tanuj Deora, director of clean energy at the White House Council on Environmental Quality.

Scope 2 emissions are the greenhouse gas emissions generated by the electric power purchased by an organization. Scope 1 are the emissions an organization directly owns or controls, while Scope 3 are the emissions produced from sources an organization neither owns or controls, such as from companies in its supply chain.

“One could take actions that result in a 100% CFE score but [with] some emissions being … assigned to the user,” Deora said. “On the other hand, we could actually zero out our Scope 2 greenhouse gas emissions but not actually be consuming only carbon-free electricity.”

Moderating the session, Rhode Island Public Utilities Commissioner Abigail Anthony framed the panel as the beginning of a discussion on the need for “harmonized certificate tracking and emissions accounting systems” for clean energy and emissions reductions. States with and even without renewable or clean energy mandates are affected, Anthony said, as whether or not they have a legal obligation, businesses in a state may have their own clean energy targets.

“I want all my regulator colleagues to understand their role as a market regulator of … generation certificates,” she said. “This is not a conversation we sit on the sidelines of. … Some states are going to need to be able to defend their own claims of emission reductions, and then you need to have systems that allow us to defend those claims legally,” as will corporations doing business in those states.

While not calling on NARUC for an official working group on the issue, Anthony would like to see the organization provide “another space for us to work together to develop standards that would allow the determination of who has what and will allow new products to be developed more easily to enable more complex emission accounting.”

She pointed to PJM’s recent announcement of its new clean energy tracking service that will provide certificates broken down by the hour as an example of the level of detail and innovation that will be needed. (See related story, PJM EIS Announces New Hourly Clean Energy Certificates.)

“It’s really important for us to figure out how to reconcile” these issues, Deora agreed. With more than 300,000 federal buildings across the U.S., the federal government is the country’s largest energy consumer, with a load of about 54 TWh of electricity a year, he said. Producing that much clean energy, at least half of it 24/7, will require accounting standards that are “going to be inclusive of both the statutory requirements across all the states who have their own rules, as well as each individual buyer’s specific targets and goals,” he said.

Betsy Beck, who leads global energy markets and policy for Google, said the company has been procuring enough clean power and retiring the associated renewable energy credits to cover its global operations. But, Beck said, developing accounting standards for its 24/7 goals means “you need to think about the grid at a more granular level.”

“It’s not enough to just balance at a high level,” Beck said. “Now we really need to be thinking about what are the right sources we need to fully decarbonize the grid. It can’t just be building the cheapest renewable energy sources, which have been wind and solar, but what do we need for the carbon-free energy supply in all hours of all days so that we do not need other fossil resources kind of backing renewables up?”

Who Has the Carbon Emissions?

As a member of NEPOOL, Rhode Island uses a relatively straightforward method for emissions accounting based on energy certificates, and not only for renewables, said Todd Bianco, chief economic and policy analyst for the state’s PUC.

“Coal has certificates too, and we follow those certificates to sort of understand what our emissions are,” Bianco said in a Monday phone interview with RTO Insider. “And we use renewable ones to help us calculate how much we’ve reduced emissions from the baseline.”

But, echoing Deora, Bianco said the clean energy and emissions certificates are not aligned.

“Folks have … focused on … the renewable aspect, which is great, but when you try to do the actual carbon emissions, you also have to have the highest fidelity to be able to show, well, who does have those carbon emissions? You’re in a power pool; there’s gas and coal and oil, let’s say, so if you didn’t use them, who did?”

During the NARUC panel, Bianco ran through a few scenarios in which the allocation of certificates could get blurred or just confusing. For example, if two businesses are on the same power system, and one is procuring wind energy and one gets electricity from a fossil fuel plant, who gets the certificates for the clean energy?

If a state agency is just looking at compliance for a renewable portfolio standard, Bianco said, it might use the clean energy credits from the wind-powered business to zero out the greenhouse gas emissions from the firm getting its electricity from the fossil fuel plant.

The agency could make “a legally defensible claim that the state is not evading emissions consistent with our statutory mandate,” he said. “But what would those two businesses tell their investors?

“And that’s where the certificates could go to the next level. Everybody has to agree,” Bianco said. “It’s no longer that I can make my claim in a bubble. Everyone has to agree to how they’re going to measure.”

Common Tool Set Needed

The General Services Administration announced its first 24/7 CFE agreement in November, working with Entergy to provide clean power to federal buildings in Arkansas. Moving ahead, Deora said, the federal government could be modeling its clean energy procurements on corporate practices.

“We’re going to [be] technology neutral, so we’re inclusive of all carbon-free electricity technologies beyond what is traditionally considered renewable,” he said. Nuclear, hydropower and fossil generation with carbon capture will be included.

Federal guidelines released in August also stress “temporal matching” on an annual and hour-for-hour basis, and “locational matching,” so that CFE is generated in the same region or service territory in which it is consumed, Deora said.

Like the federal government, Google is looking beyond wind and solar, Beck said, and the diversity of energy resources is going to make data accessibility and transparency critical for clean energy and emissions accounting.

“Whether your state has an RPS or not, you’ve probably got the federal government in your state; you probably have Google and other large energy customers,” she said. “Sorting out these inconsistences [in emissions accounting] and having systems in place to enable this data and this transparency is going to be critically important.

“We cannot continue figuring out these systems in silos,” Beck said. “Our sustainability goal is not going to be same as the government’s; it’s not going to be the same as the next company’s. But if we have a common tool set, we can use that to achieve our goals, hopefully in a meaningful and transparent way.”

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Texas PUC Rejects CCN for Grid United’s Pecos West

Texas regulators last week denied Grid United’s request to build an intertie between ERCOT and the Western Interconnection, saying they did not have the authority to approve the application.

The Public Utility Commission cited state law Thursday in rejecting a partial certificate of convenience and necessity for Pecos West, a proposed 280-mile, 525-kV HVDC intertie connecting the Lower Colorado River Authority’s (LCRA) system with El Paso Electric (EPE), which sits in the Western Interconnection (53758).

Will McAdams Peter Lake (Admin Monitor) Alt FI.jpgCommissioners Will McAdams (left) and Peter Lake during PUC’s open meeting. | Admin Monitor

PUC staff argued in a preliminary order that state law prohibits the commission from granting Grid United’s request. They said only LCRA and EPE, as owners of the facilities that would be interconnected, can be granted the CCN.

“Grid United Texas does not qualify under [Texas’ Public Utility Regulatory Act] as an entity that could be designated by El Paso Electric or LCRA to exercise the CCN rights reserved to them,” staff said. “Thus, under no circumstance can the commission legally grant Grid United Texas a CCN or any rights emanating from a CCN for the proposed interconnection.”

Houston-based Grid United had sought “partial authorization” from the commission. It said its application was limited to the intertie and not the right to construct or operate the line. Intervening parties supporting the application said state law should not apply because the proposed line is not a transmission facility, but staff rejected that argument.

“Only the owners of the existing facilities to which the proposed interconnection will directly interconnect can be certificated for the proposed interconnection,” they said. Staff pointed out that, as Grid United is not a utility under Texas law, it can’t be designated by either LCRA or EPE to exercise their respective rights to “build, own or operate a new transmission facility.”

Initial ERCOT studies last year determined Pecos West would offer “significant” reliability benefits to the Texas grid, providing new markets for producers and reduced curtailment of renewable resources with “negligible” impact on prices.

At issue, however, is Texas’ right-of-first-refusal law, which was passed in 2019 and is now before the U.S. Supreme Court. Texas last year asked the high court to review an appeals court’s remand back to a district court over the latter’s claim that the ROFR law violates the U.S. Constitution’s dormant Commerce Clause. (See Texas Petitions SCOTUS to Review ROFR Ruling.)

Commissioner Jimmy Glotfelty said he would have preferred to set the docket aside and wait for the Supreme Court’s ruling or further ERCOT studies, but he indicated his hands were tied.

“I think the law, unfortunately, tells me that a right of first refusal is a right of first refusal. And according to this docket at this time, I would have to support the staff’s position,” he said.

Jimmy Glotfelty (Admin Monitor) FI.jpgJimmy Glotfelty reads his statement on Grid United’s CCN application. | Admin Monitor

Glotfelty, who has worked with Grid United founder Michael Skelly in the past, said he struggled with the decision. (See related story, Skelly’s Grid United Quickly Making Waves.) He noted the HVDC tie would provide the state with resilience, reliability and low prices, “three things that our citizens need and that our [legislative] leadership has directed us to improve.”

“There are numerous points in the filings that in my opinion are right on target, and we should be able to permit these types of lines,” he said. “The biggest barrier to HVDC in this case is the [ROFR] law that the legislature has passed. … I want to push this line and other lines, but this law was passed and it’s our job to implement the statute.”

“We’re always looking for ways to increase competition in the market. Competition delivers great results, and we’ve seen that historically,” Commissioner Lori Cobos said. “At this time, the law is just not written to allow this type of construct.”

Grid United withdrew the application on Friday, asking that it be dismissed without prejudice. Spokesperson Ally Copple said the company remains committed to developing Pecos West. It has identified preliminary corridors and hoped for regulatory approvals in 2024. Under that scenario, Pecos West could be operational as early as 2029, Copple said.

“We have reviewed the preliminary order and the relevant statute, and we are confident there are other paths to move the project forward,” she said.

PUC Joins Lawsuit vs. EPA

The PUC agreed to join Texas’ lawsuit before the 5th U.S. Circuit Court of Appeals over the EPA’s rejection of the state’s proposed plan to control emissions that drift into neighboring states. Texas Attorney General Ken Paxton says the agency had “no good reason” to reject the plan (23-60069).

The state is one of more than 20 that, under EPA’s Cross-State Air Pollution Rule (CSAPR) plan, must establish NOx emissions budgets beginning with the 2023 ozone season (May 1-Sept. 30). The agency says the reductions are necessary to address upwind states’ interstate transport obligations. (See “Staff Defer Comment on CSAPR,” ERCOT Technical Advisory Committee Briefs: July 27, 2022.)

The PUC also agreed to join with the Texas Commission on Environmental Quality in its comments to EPA over its process for developing state plans to reduce greenhouse gas emissions.

Cobos, McAdams Step up at RTOs

Cobos, the PUC’s liaison with MISO, will serve as president of the Entergy Regional State Committee. Comprising state regulatory commissioners from Arkansas, Louisiana, Mississippi and Texas, and members of the New Orleans City Council, the committee provides input on Entergy’s transmission system operations and upgrades in MISO South.

Cobos is also the secretary for the Organization of MISO States, the RTO’s state regulatory body, and sits on the grid operator’s Advisory Committee.

“I can’t say ‘no’ to really big challenges,” she said.

PUC Chair Peter Lake complimented Cobos and Commissioner Will McAdams, the commission’s representative on SPP’s Regional State Committee. McAdams was recently selected to lead the grid operator’s newly created Resource and Energy Adequacy Leadership team and appointed as the RSC’s treasurer.

“You’re both clearly gluttons for punishment,” Lake said.

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Bill Seeks to Promote Clean Aviation Fuel in Washington

A legislative effort to make Washington more attractive to the alternative jet fuel industry has reached the state Senate’s Ways and Means Committee.

The committee scheduled a Feb. 20 hearing on Senate Bill 5447 , which would set a business and occupation (B&O) tax rate of 0.275% for any plant that would produce at least 20 million gallons a year of low-carbon jet fuel. A B&O tax is a tax on a business’ gross receipts, and most B&O rates in Washington range from 0.47% to 0.9%.

Senate Majority Leader Andy Billig (D) and Rep. Vandana Slatter (D) each introduced versions of the bill in their respective chambers. It is a common behind-the-scenes legislative practice to pick one of two similar bills to send to both chambers, while letting the other stall in committee. Billig’s bill was selected to advance further in the legislature.

The Port of Seattle has expressed interest in using jet biofuels at SeaTac International Airport since 2017. Low-carbon biofuels would be mixed with existing petroleum-based jet fuels to reduce their carbon intensity.

The only existing alternative jet fuels plant on the West Coast is near Los Angeles, and the two proposed bills seek to develop a second plant in Washington. A few years ago, the predicted cost of building such a plant was at least $1 billion.

Support for SB 5447 was overwhelming at a Feb. 1 hearing before the Senate Environment, Energy and Technology Committee. Supporters included Alaska Air Group (NYSE:ALK), Delta Air Lines (NYSE:DAL), sustainable aviation fuel supplier SkyNRG, BP America (NYSE:BP), the Port of Seattle, Amazon (NASDAQ:AMZN), Washington State University and the Association of Washington Business.

Their representatives said the aviation fuels sector is difficult to decarbonize, but that the effort is needed to meet the state’s goal to eliminate most of its greenhouse gas emissions by 2050. The low tax rate will attract alternative fuel plants, they said.

At a Feb. 7 hearing before the House Environment and Energy Committee, Darrin Morgan, a representative of Netherlands-based SkyNRG, said: “We’d like a facility to be here in Washington state.”

“We have a chance to capture the market,” Slatter said. “With this bill, Washington would be a leader in this new industry.”

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California Energy Commission Grants $31M to Manufacture Futuristic ZEVs

The California Energy Commission on Wednesday continued its recent practice of making large grants to in-state manufacturers of zero-emission vehicles, including futuristic three-wheeled cars with built-in solar panels and hydrogen-powered big rigs.

The CEC awarded Aptera Motors Corp. $22 million to “produce an affordable solar ZEV that uses the sun to fuel up to a 40-mile daily commute without the need for grid-connected charging,” the agency said in a grant document.

The car’s range on a plug-in charge is up to 1,000 miles in a version with the most battery capacity, Aptera says on its website. Other versions can reach 250, 400 and 600 miles on a charge, the company says.

“That looks like a Jetsons kind of [vehicle]. Is that something that is capable of going freeway speeds?” CEC Chair David Hochschild asked Pablo Ucar, Aptera’s vice president of production and procurement.

The car’s top speed is 110 mph, “so it drives like a real vehicle,” Ucar said. “The reason it is a three-wheeler is because we want it to be the most efficient vehicle in the world. Three wheels are more efficient than four wheels. It is a two-passenger vehicle. It performs and behaves like a regular car on the highway.”

The CEC grant, matched by $26.4 million from Aptera, will pay for installing vehicle production equipment at two manufacturing facilities in Carlsbad and Vista, California, cities in San Diego County.

The vehicle is on preorder and expected to be available to buyers later this year. Aptera plans to produce 20,000 vehicles annually by 2025 and to create 444 manufacturing jobs, the CEC said.

Commissioner Patty Monahan, the lead commissioner for transportation programs, acknowledged Aptera’s car is unlike anything on the road in the U.S. and involves uncertainty. But one of the CEC’s goals is to encourage new concepts in zero-emission vehicles from companies such as Aptera, she said.

“We’re taking calculated risks in terms of really wanting to support innovation in the ZEV ecosystem and recognizing that electrification offers this opportunity to be really innovative,” Monahan said.

The CEC approved a $9 million grant to Symbio North America, with a company match of nearly $11 million, to expand its facility in Poway, also in San Diego County, and to establish a new facility in Temecula, in Riverside County, for hydrogen fuel cell vehicle power systems and vehicle assembly. The expansion will create 63 jobs and establish a hydrogen fuel cell workforce training program in partnership with nearby universities and colleges, the company said.

“These California facilities will assemble regional long-haul heavy-duty fuel cell class 8 trucks and have an annual combined maximum production capacity of 250 trucks and 250 to 300 fuel cell power systems to expedite fuel cell truck deployment in California,” the grant request said.

Hochschild asked Symbio North America General Manager Rob Del Core how the company’s big rigs would compare with battery-powered electric trucks being produced by Tesla and others.

“We’re looking at applications where a hydrogen fuel cell could really dominate in terms of the benefits for things like fast-fueling, long range and of course payload capacity,” Del Core said.

That will include trucks that can travel 400 miles from Southern to Northern California without refueling on a route with 70 mph highway speeds and a winding 4,000-foot mountain pass.

The CEC’s grants are part of a major push to encourage ZEV manufacturing and job creation in California using funds allocated by state budgets in 2021 and 2022.

As of January, CEC staff had recommended 13 projects for funding totaling $199.4 million.

Last month the CEC awarded more than $46 million in grants to four manufacturers of electric tractors, forklifts, car batteries, and charging stations with the intent to bolster in-state production of zero-emission vehicles and equipment.

Ranging from about $8 million to more than $14 million, the grants were among the largest manufacturing subsidies ever granted by the CEC. (See CEC Awards $46 Million for ZEV Manufacturing.)

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PJM MRC/MC Preview: Feb. 23, 2023

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

As part of its consent agenda, the MRC will be asked to endorse:

B. proposed revisions to Manual 27: Open Access Transmission Tariff Accounting to conform to the settlement agreement approved by FERC in PJM’s filing to change its administrative cost recovery charges (ER22-26).

C. proposed revisions to Manual 40: Training and Certification Requirements resulting from a periodic review.

Endorsements (9:10-9:20)

3. Manual 6 FTR Bid Limits (9:10-9:20)

PJM’s Emmy Messina will present a proposal to increase the number of bids a corporate entity may submit into FTR auctions, alongside corresponding revisions in Manual 6: Financial Transmission Rights. The committee will be asked  to endorse the proposed solution and associated manual revisions. (See “FTR Bid Limit Increase Endorsed Under Fast Track Pathway,” PJM MIC Briefs: Jan. 11, 2023.)

Issue Tracking: FTR Auction Bid Limits

Members Committee

Consent Agenda (12:35-12:40)

As part of its consent agenda, the MC will be asked to endorse:

B. a proposed solution to implement the second phase of PJM’s hybrid resource rules, along with corresponding tariff and Operating Agreement revisions. (See PJM Releases Phase 2 of Energy Transition Study.)

Issue Tracking: Solar-Battery Hybrid Resources

C. a proposal to revise PJM’s day-ahead zonal load bus distribution factors and corresponding revisions to tariff section 31.7. (See “MIC Endorses Proposal on Hybrid Resources,” PJM MIC Briefs: Nov. 2, 2022.)

Issue Tracking: Day-ahead Zonal Load Bus Distribution Factors

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Nuclear Bill Advances in Washington House

OLYMPIA, Wash. — The House Environment & Energy Committee unanimously recommended Thursday that the full House of Representatives pass a bill to add advanced nuclear reactor technology to the alternative power sources that the state uses to replace fossil fuels.

House Bill 1584, sponsored by Rep. Stephanie Barnard (R), would add advanced nuclear to solar, wind, hydroelectric dams, landfill methane and other sources of non-fossil fuel power sources. Washington is legally required to eliminate 95% of its greenhouse gas emissions by 2050. Barnard represents the Tri-Cities, home of the 1,200-MW Columbia Generating Station nuclear plant, which produces roughly 12% of the state’s electricity.

The owner of the plant, Energy Northwest, supports the bill, as does the Grant County Public Utility District, which is considering building a small modular reactor (SMR) complex within its territory.

Each modular unit would be a mini-reactor capable of generating 50 to 300 MW. SMRs are designed to allow additional modules as needed, with 12 modules being the theoretical maximum. Compared with conventional nuclear, the concept is supposed to result in lower costs, faster construction times and more flexibility in tailoring a reactor complex to its customers’ needs.

Grant County PUD is looking at a design by Maryland-based X-energy but has not decided whether to pursue an SMR.

“We’re looking at advanced nuclear technology because of growth in our county,” Bill Clarke, a lobbyist representing the PUD, told the committee.

NuScale Power of Portland, Ore., became the first SMR developer to receive approval for its 60-MW design by the Nuclear Regulatory Commission. The company plans to submit an improved follow-up version of that design to the commission that includes increasing output to 77 MW each. The company is pursuing building its first complexes in Idaho Falls, Idaho, and Romania by the end of this decade.

Leaders from both Energy Northwest and the Tri-Cities want to attract NuScale to build at the site of two never-completed reactors next to the Columbia plant. That site has infrastructure in place to build either reactors or reactor components.

At Thursday’s committee hearing, Roger Lippman of Nuclear Free Northwest opposed the bill, saying the term “advanced nuclear technology” is not defined in the bill. He added that no advanced nuclear technology plants have begun operating in the U.S., meaning the technology does not have a proven track record.

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FERC Affirms MISO’s Seasonal Auctions, Accreditation

FERC on Thursday rejected two rehearing requests over MISO’s seasonal capacity auction and availability-based resource accreditation, clearing the way for the RTO to conduct its first seasonal auctions in April.

The commission affirmed its previous decision that the seasonal, availability-based accreditation will incentivize availability and more accurately represent when generating units contribute to resource adequacy (ER22-495).

Commissioner Allison Clements, as she did in FERC’s original order last year, disagreed with MISO’s accreditation inputs, saying it “glosses over MISO’s failure to adequately justify key details in its proposal.”

Clements zeroed in on what she called “two of the most problematic design flaws”: MISO’s selection of resource adequacy hours that allow resources up to 12 hours to be counted in its operating reserve margin calculation, and the 24-hour lead time before resources are excluded from being assumed as available during those hours.

“In defense of its position, the only explanation MISO gave is that its choice of a 12-hour lead time was better than an alternative of 24 hours, which would have included even more resources incapable of delivering capacity when needed,” she wrote in a concurring opinion. “But the Federal Power Act is not a ‘Price is Right’ showcase showdown, and the fact that a proposed rate is closer than an unjust and unreasonable option does not demonstrate it to be just and reasonable. One hundred dollars for a gallon of milk is not a fair price, and the fact that $50 is a better alternative does not make it reasonable.”

Clements said MISO’s decision to credit resources that take up to a full day to start up will lead to extending credits for resources that are ineffectual during reliability issues.

“Incredibly, while MISO’s only defense of using 12 hours as the lead time threshold for including resources in its calculation of operating margin is that doing so is more accurate than using a 24-hour lead time, it proposes to use the even-less-accurate 24-hour lead time when determining which resources get credit for delivering capacity,” she said.

FERC last year approved the grid operator’s request to conduct four seasonal capacity auctions, with separate reserve margins, and apply a seasonal accreditation mostly based on a thermal generating unit’s past performance during tight system conditions. The expected and historical tight conditions are dubbed “resource adequacy hours,” covering 65 hours during the year when resource availability is less than 25% of operating margin.

Louisiana and Mississippi regulators, Consumers Energy, Entergy (NYSE:ETR), DTE Energy (NYSE:DTE) and Alliant Energy (NASDAQ:LNT) sought rehearing of the order’s accreditation portion. They said a harsher accreditation based on risky hours that can’t be predicted with certainty will result in fluctuating accreditation values, undue penalties to generation and won’t reflect MISO supply fundamentals. (See MISO’s Seasonal Capacity Proposal Opposed at FERC.)

DTE and Alliant accused the commission of “cursorily sweeping aside” concerns over accreditation instability. They said the accreditation framework could potentially cause about a “ten-fold increase in year-to-year accreditation volatility for some market participants” and could cause members to overbuild generation on the MISO system.

Entergy noted that according to the RTO’s own analysis, a quarter of all market participants’ total accredited capacity will experience a standard deviation between 7.7% and 15.5% from one planning year to the next in the spring season. Entergy said that translates into a 20% chance that a market participant’s total accredited capacity will “undergo a year-to-year change of 20%.”

The utility said a resource can experience “a significant reduction” in accredited capacity if it is unavailable during “even one or two days.” Mississippi and Louisiana agreed that the design will cause “large swings” in accreditation year over year.

Before last year, MISO accredited its thermal resources annually based on the asset’s historic three-year equivalent forced outage rates.

The commission was unpersuaded by the arguments and said the new accreditation’s benefits still stand to outweigh the small amount of aggregate volatility it introduces across planning resources’ capacity values.

FERC said the accreditation will lead to “increased accuracy, increased confidence in generator availability during high-risk hours, better coordination of resource outages and stronger incentives for resources to be available in times of need.”

The commission disagreed with a coalition of clean energy organizations that said thermal resources shouldn’t have a different accreditation framework from renewable resources. It said resource classes can be accredited using different methods.

The clean energy groups also took issue with MISO’s response should a season not have at least 65 resource adequacy hours. The grid operator will use resource performance data from other high-risk hours throughout the year as a “backfill” to ensure there are 65 resource adequacy hours.

They also said MISO’s proposal to top off the risky hours to make sure it meets a minimum 65 hours, or 3% of a season, “creates an artificial profile for these resources and assumes risk in a season during hours where there are none.” FERC responded that maintaining a minimum target of hours to base accreditation upon “mitigates the volatility concerns.”

The commission also supported MISO’s 120-day advance notice requirement for planned generator outages; a capacity replacement obligation for resources on planned outages lasting longer than 31 days; and the RTO’s plan to treat offline resources with lead times greater than 24 hours as unavailable during resource adequacy for accreditation purposes.

It resisted calls to delay the seasonal launch until the 2024-25 planning year to let market participants get their bearings in the new environment. FERC said market participants have attended stakeholder workshops that warned of the change as far back as 2019.

FERC’s decision arrives as MISO may revise the availability-based accreditation method. The grid operator wants to adjust unit-level accreditation by a capacity value determined by loss-of-load expectation rather than its existing unforced-capacity values that rely on forced outage rates.

The design would apply to all resources and require edits to the new availability-based design. MISO currently uses a unit-level effective load-carrying capability calculation based on a peak hour contribution for wind resources. (See Stakeholders Cry Foul on MISO’s Resource Accreditation Pivot.)

Clements contended that FERC violated the Administrative Procedure Act because it did not respond to arguments that many resources with nearly a full day’s startup time cannot maintain reliability when they’re offline during resource adequacy hours.

She found it “laudable” that MISO is seeking to improve “its outdated capacity accreditation framework. “

“It is clear that … today’s markets must be designed to address increasingly complex reliability challenges. Although MISO’s proposal fell short of the mark, this does not suggest that changes to MISO’s resources adequacy rules are not appropriate. To the contrary, further changes appear necessary,” she said.

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PJM EIS Announces New Hourly Clean Energy Certificates

The subsidiary of PJM that manages its registry of clean energy certificates will next month release a new product broken down by the hour in which the energy was created, the RTO announced last week.

Ken Schuyler, president of PJM EIS, said no other registry of renewable energy credits (RECs) in the U.S. has created an hourly product, but he believes it’s a road others are likely to follow to meet the needs of customers seeking increasingly granular data, particularly those striving to meet clean energy goals.

The certificates currently managed by the Generation Attribute Tracking System (GATS) that EIS operates include the generator location, emissions output, fuel source and date the generator went online. Each one represents 1 MWh and are produced based on the amount of power the facility produced in a given month.

The new credits will also include the output by date and hour.

“We recognize that customers are interested in more granular, real-time data that can be used to innovate new ways to incentivize clean energy,” Schuyler said in an announcement. “Using the unique data offered by GATS, customers can make more informed choices about their energy use.”

The more detailed certificates allow those with environmental targets to match their energy usage throughout the day to ensure the entirety of their power is provided by renewable or carbon-free generation, Schuyler said. Another application he identified is for buyers to target when they purchase credits to displace high-emitting generators during hours when marginal emissions are at their highest.

“The hourly data that we’re making available is being made available so that they can make informed choices and accomplish their strategies, whatever that might be,” he told RTO Insider.

Constellation Energy (NASDAQ:CEG) applauded the announcement, saying it enhances the ability for consumers to demonstrate that they are using carbon-free energy. 

“This advancement is enabling companies like Constellation to offer a more complete range of products that help customers meet their sustainability goals,” said Kathleen Barrón, Constellation’s chief strategy officer. “As we work toward our purpose of accelerating the transition to a carbon-free future, we can provide this critical service for customers who want more clear and accurate data on their emissions impact, including producers of clean hydrogen who must demonstrate that they are using zero-carbon energy to qualify for new federal tax credits.”

The company noted that it launched its own hourly carbon-free energy matching product last year, allowing customers to match their energy with regional carbon-free generation on an hourly basis. The new hourly certificates supplied by EIS will provide a “transparent and independent way to certify that they are meeting their clean energy goals.”

Speaking on a panel during PJM’s General Session in October, Brian George, lead of Google’s (NASDAQ:GOOGL) energy regulatory and policy engagement team, said the company was shifting to procuring clean energy when and where it’s needed, rather than focusing on the installation of additional renewable generation. In an email following PJM’s announcement, he said the hourly data is central to the company’s carbon-free energy goals. (See PJM General Session Focuses on Clean Energy Transition.)

“We welcome PJM’s announcement to implement an hourly tracking mechanism. As a buyer of electricity in PJM with a goal to power our data centers with 24/7 CFE by 2030, hourly tracking is essential. We hope other RTOs and ISOs across the country will follow PJM’s leadership,” George wrote.

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Exelon Earnings Highlight Investments to Comply with State Legislation

Exelon (NASDAQ:EXC) leadership last week charted out the company’s path to maintaining its growth targets while implementing its plans to comply with state environmental legislation.

“The Exelon team has proven it’s ready to meet the challenge of leading the nation in its energy transformation, powering a cleaner and brighter future for our customers and our communities while creating value for our shareholders,” CEO Calvin Butler said during the Feb. 14 earnings call.

Exelon reported a 27% increase in earnings for 2022, at $2.054 billion. Its fourth-quarter earnings of $432 million were nearly 40% higher than those in the fourth quarter of 2021.

The company saw 8.1% annual growth off its 2021 guidance midpoint and operating earnings of $2.27/share, exceeding guidance by 2 cents/share. The 2023 projection anticipates 5% earnings growth relative to the 2022 guidance and operating earnings guidance at $2.30 to $2.42/share.

Butler said the company completed its separation with Constellation Energy and has had a successful first year as a transmission-and-distribution-only utility.

“In 2022, Exelon showcased our ability as a pure transmission-and-distribution company to deliver on our financial and operational commitments,” Butler said. “Because of the partnership with our customers and communities, Exelon is ready to lead the energy transition to a cleaner and brighter future.”

CFO Jeanne Jones noted that the 5% growth expected this year is below Exelon’s 6 to 8% target range between 2022 and 2026. Exelon is projecting its operations and maintenance costs being $100 million higher this year, which Jones attributed to one-time costs associated with the Illinois Clean Energy Jobs Act (CEJA), as well as information technology investments, cybersecurity enhancements and taking advantage of favorable weather to engage in corrective maintenance.

Commonwealth Edison filed its first multiyear rate plan and its grid plans to the Illinois Commerce Commission under CEJA, which calls for carbon-free energy generation by 2045. The plan’s investments include bus reconfigurations, work overhead and underground infrastructure to support an anticipated 1 million electric vehicles by 2030, and converting 4-kV infrastructure to 12 kV. (See Illinois Senate Passes Landmark Energy Transition Act.)

“As Illinois progresses towards its decarbonization goals, ComEd is starting from an industry-leading position of strength,” Butler said.

ComEd has also filed with the ICC to defer collection of 35% of the 2024 rate increase until 2026 to smooth the impact for customers.

Jones said carbon mitigation contracts are projected to save ComEd customers over $3 billion in energy charges between 2022 and 2027.

The company is also preparing to submit its multiyear plan with the Maryland Public Service Commission later this month, with proposed investments in line with the state’s Climate Solutions Now Act. Jones pointed to the $50 million in school bus electrification incentives Baltimore Gas and Electric has offered Maryland school districts as the type of investments the utility is making. (See Md. Climate Bills Become Law Without Hogan’s Signature.)

“Like Illinois, Maryland’s Climate Solutions Now Act has set aggressive climate and decarbonization targets, creating an environment where utility action and investment is a key priority and for which multiyear planned frameworks are particularly well suited,” Butler said.

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CenterPoint to Invest $43B, Addressing Customer Growth

CenterPoint Energy (NYSE:CNP) said Friday it plans to increase its 10-year capital plan to $43 billion through 2030, with a focus on additional investments in grid reliability and modernization.

CEO David Lesar told analysts on an earnings call that the company has added $2.3 billion to the capex plan and identified an additional $3 billion of potential opportunities that will be folded in “when we believe we can operationally execute it, efficiently fund it, and minimize the regulatory lag associated in recovering it.”

The Houston-based utility reported fourth-quarter earnings of $122 million ($0.19/share) and year-end earnings of $1.01 billion ($1.59/share), compared to $641 million ($1.01/share) and $1.39 billion ($2.28/share) for the same periods in the previous year.

“We continue to execute well; 2022 was truly an exciting and productive year,” Lesar said during the call. “We are confident that this strong momentum will continue into the new year.”

He noted it was the 11th straight quarter CenterPoint has exceeded or met its own expectations for earnings guidance. Lesar has been CEO for the last 10 of those quarters.

The infrastructure investment will be needed. Texas has added nearly 1.1 million jobs since the COVID-19 recession, Lesar said. Houston, CenterPoint’s primary electric service region, has added 179,000 jobs and increased its population by almost 300,000 to nearly 7 million, he said.

“This is now like adding a city the size of Irvine, Calif., to our footprint in just one year,” Lesar said. “We see this trend continuing as the Texas miracle keeps humming along.

“This growth is just one of the reasons we believe we are uniquely positioned as a company.”

The company’s share price closed at $29.22 Friday, a gain of 16 cents on the day.

Entergy Takes Hit from Grand Gulf

Entergy (NYSE:ETR) on Thursday reported earnings of $106 million ($0.51/share) for the quarter and $1.1 billion ($5.37/share) for the year. That compared to $259 million ($1.28/share) for 2021’s fourth quarter and $1.12 billion ($5.54/share) for the year.

The results included a $551 million charge, $413 million after tax, for System Energy Resources Inc. (SERI), the Entergy subsidiary that owns the Grand Gulf Nuclear Station in Mississippi. FERC in December issued two orders involving the plant’s customer rate impacts. The orders addressed a series of uncertain tax positions that SERI took.

The New Orleans-based company has begun issuing refunds to ratepayers. It reached a $300 million settlement with the Mississippi Public Service Commission last June.

“We still believe that a global settlement with the remaining retail regulators on terms similar to the agreement with the MPSC would be in the best interest of all parties,” Entergy CEO Drew Marsh told financial analysts during the quarterly conference call. “It would resolve disruptive litigation uncertainty for SERI and our stakeholders, including our regulators, accelerate meaningful value to customers, avoid costly and unnecessary third-party litigation fees and allow all parties to move forward with fewer distractions.”

Entergy’s earnings exceeded Zacks Investment Research projections of $0.45/share. Entergy’s share price ended the week at $109.42, up $1.87 from Wednesday’s close.