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August 24, 2024

Judges Skeptical of Capacity Sellers in PJM Offer Cap Dispute

An attorney for Vistra (NYSE:VST) and other capacity sellers faced skeptical questioning from the D.C. Circuit Court of Appeals last week in a bid to overturn FERC’s September 2021 ruling changing PJM’s offer cap rules.

Vistra and attorneys for FERC, PJM and its Independent Market Monitor presented arguments to Judges Judith W. Rogers, Patricia Millett and J. Michelle Childs during a 70-minute hearing Nov. 8 (21-1214).  

In March 2021, the commission ordered PJM to revise its market seller offer cap (MSOC) in response to a complaint by the Monitor, which said the original cap was too high because it erroneously assumed the RTO would annually experience 30 performance assessment hours — emergency hours when capacity sellers face penalties for underperforming. (See FERC Backs PJM IMM on Market Power Claim.)

Six months later, the commission replaced PJM’s single default offer cap with several default caps applicable to different generation technologies (EL19-47). PJM and capacity sellers sought rehearing, with the RTO arguing that the commission’s decision could lead to over-mitigation of the market. (See PJM Requests Rehearing of MSOC Change.)

Vistra said the prior rules allowed sellers to include opportunity costs in their offers, even if the offer is above the seller’s avoidable costs.

In its brief to the D.C. Circuit, Vistra said that FERC could have corrected the MSOC by changing the assumed emergency hours to 20 hours or less.

“Instead of fixing the miscalibrated assumption … FERC abandoned an opportunity cost-based offer cap altogether, without explanation or even acknowledgment, in favor of an offer cap based solely on a flawed calculation of projected operating costs,” it said.

Under the new rules, Vistra said, the commission gave “precedence to the Market Monitor’s alternative version of the supplier’s offer and requires the supplier to make a filing with FERC to challenge the Market Monitor’s version of the supplier’s offer.” Vistra said that violates capacity sellers’ rights under Federal Power Act Section 205 to file rates and terms for services rendered.

Rogers challenged Vistra attorney Paul Hughes’ argument that the commission failed to adequately explain its ruling.

“I think some of the statements in your brief are a little misleading,” she said. “I mean, it’s fine if you don’t agree [with FERC’s conclusion] if you give us reasons. But that’s different from saying FERC never responded, or never addressed the alternatives, when clearly — when you read its order and order on rehearing — it did.”

PJM attorney Paul M. Flynn argued that FERC’s ruling upset the balance between consumers and market sellers.

“We want to make sure that there is no exercise of market power, but where there is a real legitimate cost a supplier has, we want to make sure they have reasonable opportunity to include that in their capacity price,” he said. “FERC overshot. It went dramatically away from the Capacity Performance construct.”

FERC attorney Matthew Estes said Vistra was erroneously contending “the commission has given the Market Monitor the ability to set the offer cap.”

“That’s not correct. The tariff gives the suppliers the ability in the first place to propose an offer cap based on the formula. The Market Monitor simply reviews that offer to see if it complies with the tariff. And ultimately, if the supplier disagrees with what the Market Monitor determines, it can go to the commission and ask the commission to decide what cap complies with the tariff.”

In such a dispute, said Jeffrey W. Mayes, general counsel for IMM Monitoring Analytics, “we would bear the burden of proof to show that the offer was unjust and unreasonable — that it was not competitive.”

California PUC Revisits Net Metering Plan

The California Public Utilities Commission released a new net metering plan Thursday after months of controversy over its prior efforts to cut payments to rooftop solar owners for exported electricity and to charge them grid-connection fees.

The latest proposal tries to strike a balance between the competing demands of the solar industry and an alliance of investor-owned utilities and ratepayer advocates. The solar industry argues that reducing the state’s generous incentives will undermine solar adoption, while the utilities and ratepayer advocates say the state’s current net-metering scheme shifts billions of dollars in costs from those who can afford rooftop solar to those who cannot.

The CPUC is working under a legislative mandate to revise the state’s net energy metering (NEM) tariff by next year.

Under the latest plan, the existing “net energy metering tariff and its sub-tariffs are revised to balance the multiple requirements of the Public Utilities Code and the needs of the electric grid, the environment, participating ratepayers, as well as all other ratepayers,” the Nov. 10 proposed decision says.

The new plan would not change the credits paid to current rooftop solar owners for excess electricity they export to the grid. Utilities compensate those homeowners at full retail electricity rates, which are much higher than the costs of utility-scale solar.

The subsidies are credited with making California the nation’s leader in rooftop solar over the past 25 years.

“Since 1997, California has supported the rooftop solar market through its NEM tariffs, which have enabled 1.5 million customers to install more than 12,000 megawatts of renewable generation,” the CPUC said in a news release.

The CPUC’s prior net metering reform proposal, issued in December 2021, would have slashed NEM bill credits by more than half and possibly up to 80%. (See California PUC Proposes New Net Metering Plan.)

Under the new proposal, future rooftop solar owners would be compensated differently from existing customers.

“In the successor tariff, the structure of the [current NEM] tariff is revised to be an improved version of net billing, with a retail export compensation rate aligned with the value that behind-the-meter energy generation systems provide to the grid and retail import rates that encourage electrification and adoption of solar systems paired with storage,” the proposed decision says.

“The successor tariff applies electrification retail import rates, with high differentials between winter off-peak and summer on-peak rates, to new residential solar and storage customers instead of the time-of-use rates in the current tariff,” it says. “The successor tariff also replaces retail rate compensation for exported energy with Avoided Cost Calculator values that vary according to grid needs.”

A fact sheet accompanying the proposed decision says the new rate structure would encourage customers to install battery storage so they can store solar electricity generated in the daytime and sell it to the grid on hot summer evenings, when prices are higher, and the state needs it most for reliability.

Strained grid conditions in the past three summers occurred during heat waves when solar ramped down in the evening but demand remained high from air conditioning use.

The state legislature approved $900 million in funding this year to spur adoption of rooftop solar and battery storage, including $630 million for lower-income households. Those who install solar or solar coupled with storage in the next five years will receive extra payments.

“Customers lock in these extra bill credits for nine years,” the CPUC said in the fact sheet.

The solar industry would benefit by selling more storage along with solar arrays, it said.

The new plan removes a controversial provision contained in the December proposal to impose an $8/kWh grid charge on solar customers’ bills, averaging about $48 per month for residential customers.

The CPUC estimated that under the new plan, residential customers installing solar will save an average of $100 a month on their electricity bills, and those installing solar and batteries will save $136 a month or more.

“With these savings … customers will fully pay off their solar systems in just nine years or less,” the CPUC said in the fact sheet.

Neither Side Happy

Both the solar industry and investor-owned utilities expressed dissatisfaction with the plan last week.

The California Solar and Storage Association said in a news release that “based on an initial analysis the [Nov. 10 proposal] would cut the average export rate [for rooftop solar] in California from $0.30 per kilowatt to $0.08 per kilowatt and make those cuts effective in April 2023, resulting in a 75% reduction in value of exports.”

The trade group’s executive director, Bernadette Del Chiaro, said in the statement that the “CPUC’s new proposed decision would really hurt. It needs more work, or it will replace the solar tax with a steep solar decline. An immediate 75% reduction of net energy metering credits does not support a growing solar market in California.

“If passed as is, the CPUC’s proposal would protect utility monopolies and boost their profits, while making solar less affordable and delaying the goal of 100% clean energy,” she said

Affordable Clean Energy for All, an advocacy group that includes the state’s three large investor-owned utilities, said the plan does not go far enough.

“The CPUC’s new proposed decision released today fails to make the meaningful reform necessary to ensure that all electricity customers, those with rooftop solar and those without, pay their fair share of the costs for electric grid reliability, wildfire mitigation and other state mandated programs that benefit all Californians,” the group said in a news release.

“It is extremely disappointing that under this proposal, low-income families and all customers without solar will continue to pay a hidden tax on their electricity bills to subsidize rooftop solar for mostly wealthier Californians,” the group’s spokesperson Kathy Fairbanks said in the news release.

Parties have 20 days to comment on the proposal. The CPUC plans to take it up for the first time at its Dec. 15 voting meeting.

Biden at COP27: Nations Must Step up, Double-down on Climate Action

Under new U.S. policies, federal contractors will have to disclose their greenhouse gas emissions and climate risks, and natural gas producers will have to respond quickly to reports of large methane leaks, President Biden announced at the U.N.’s 27th Conference of the Parties (COP27) in Sharm el-Sheikh, Egypt, on Friday.

“As the world’s largest customer, with more than [$630 billion] in spending last year, the United States government is putting our money where our mouth is to strengthen accountability for climate risk and resilience,” Biden said of the administration’s new guidelines for federal suppliers.

In a speech that highlighted his administration’s commitments to climate action at home and abroad, the president called on all countries to both raise their targets for emissions reductions and accelerate their progress toward achieving them.

“To permanently bend the emissions curve, every nation has to step up,” Biden said. “The United States is acting. Everyone has to act. That’s the duty and responsibility of global leadership.”

Current economic and political challenges — inflation, food and energy insecurity, and Russia’s invasion of Ukraine — make it “more urgent than ever that we double-down on our climate commitments,” Biden said. “True energy security means that every nation … is benefiting from a clean, diversified energy future” in which no country can “use energy as a weapon and hold the global economy hostage.”

He told a full conference hall, “with confidence,” that the U.S. would meet its commitment to reduce its emissions 50 to 52% below 2005 levels by 2030, the goal he set shortly after taking office in 2021. The U.S.’ flagship climate law, the Inflation Reduction Act, is expected to cut emissions 40%, according to estimates from the U.S. Department of Energy.

He also pointed to the U.S.’ recent ratification of the Kigali Amendment, which commits the country to cutting its use of hydrofluorocarbons — a potent greenhouse gas commonly used in air conditioning and refrigeration — by 45% by 2024 and 85% by 2036.

With the passage of the IRA, “we are proving that good climate policy is good economic policy,” Biden said. “It’s a strong foundation for durable, resilient, inclusive economic growth. It’s driving progress in the private sector. It’s driving progress around the world.”

Focusing on U.S. support for Africa, Biden announced a $500 million package, financed by the U.S., the EU and Germany, “that will enable Egypt to deploy 10 GW of renewable energy by 2030, while bringing offline 5 GW of inefficient gas-powered facilities.” The initiative will cut Egypt’s emission’s 10% and allow the country to increase its climate commitments, Biden said.

“If countries can finance coal in developing countries, there is no reason why we can’t finance clean energy in developing [countries],” he said.

He also pointed to “a partnership between American firms and the government of Angola to invest $2 billion to build new solar projects” in the country.

Biden’s announcements were primarily targeted at climate adaptation and mitigation, as opposed to the more sensitive issue of “loss and damage,” a key theme during the conference.

The issue turns on developing countries’ argument that while they produce only a small portion of the world’s greenhouse gases, they are more vulnerable to the impacts of climate change. Developed countries, who produce the majority of the world’s greenhouse gases, should therefore pay developing nations restitution for the loss and damage they have experienced from extreme weather events fueled by climate change.

While not mentioned in the president’s speech, Special Climate Envoy John Kerry earlier in the week included loss and damage in a list of climate initiatives the U.S. hoped to push forward at the conference.

Other funding the president announced included a doubling of U.S. contributions to support climate adaptation in developing countries from the $50 million pledged last year at COP26. The U.S. will also provide an additional $150 million for a range of adaptation initiatives across Africa, under the President’s Emergency Plan for Adaptation and Resilience (PREPARE), Biden said.

The funds will be used, in part, for an early warning system to alert countries to potential extreme weather events and other climate-related disasters, and to bolster adaptation programs aimed at increasing food security.

Federal Supplier Rules

The administration rolled out a range of climate-related initiatives in the week leading up to the president’s address in Sharm el-Sheikh, including the new proposed Federal Supplier Climate Risks and Resilience rule and more aggressive regulations for cutting methane emissions.

According to information from the White House Council on Environmental Quality (CEQ), the proposed emission reporting requirements for federal suppliers would depend on the amount of business they do with the government. Suppliers with contracts in excess of $50 million would be required to report on their Scope 1, Scope 2 and “relevant categories” of their Scope 3 greenhouse gas emissions, as well as on their climate-related financial risks, and set “science-based emission reduction targets.”

Scope 1 emissions are direct emissions from a company’s operations and owned assets, including emissions from a business’s vehicle fleet. Scope 2 covers emissions from the energy a company purchases, including electricity; while Scope 3 are the indirect emissions generated up and down a company’s value chain and not under the company’s direct control.

Federal suppliers with contracts between $7.5 million and $50 million would only have to report their Scope 1 and 2 emissions, and smaller suppliers, with contracts under $7.5 million, would be exempt from the requirements.

The CEQ’s announcement said that, like other sectors of the economy, the federal government has been affected by supply chain disruptions over the past year. The proposed rules “would strengthen the resilience of vulnerable federal supply chains, resulting in greater efficiencies and reduced climate risk.”

According to the White House, since the federal government adopted its own climate goals, energy use from buildings and vehicles has dropped 32%, with savings estimated at $11.8 billion per year.

A 60-day comment period on the proposed rules will close on Jan. 13, 2023, the CEQ said.

Super-emitter Program

The new proposed rules for cutting methane emissions from the oil and gas industry are part of an updated plan for increasing U.S. methane emissions reductions under the Global Methane Pledge launched last year at COP26.

Led by the U.S. and European Commission, the pledge is aimed at cutting methane emissions worldwide 30% below 2020 levels by 2030. At present, more than 130 countries have joined the pledge. A major driver of climate change, methane is 80 times more potent at trapping heat than carbon dioxide for the first 20 years it is in the atmosphere.

The new proposed regulations, released by EPA, would ensure regular monitoring of all well sites for leaks, while also providing “industry flexibility to use innovative and cost-effective methane detection technologies, and a streamlined process for approving new detection methods as they become available.”

In addition, a super-emitter response program would leverage “remote methane detection technology to quickly identify … large-scale emissions for prompt control.”

Backing up the proposed rules, EPA will also use $1.55 billion from the IRA to provide financial and technical assistance for emissions monitoring and reduction, including $700 million for conventional wells with only marginal production.

EPA said the proposed rules are based on extensive input from industry stakeholders and close to half a million public comments. A new public comment period on the rules will run through Feb. 13.

Pa. PUC Opens Proceeding on EV Rate Design

Pennsylvania regulators Thursday opened a rate design proceeding to encourage electric vehicle charging during off-peak hours.

Responding to a petition by a coalition of EV stakeholders and environmental groups, the Public Utility Commission voted unanimously to create a working group to provide the commission with recommendations by March 31, 2023 (P-2022-3030743). The commission’s directive calls for the issuance of an order responding to the recommendations by June 1, 2023.

The coalition, ChargEVC-PA, called for the proceeding in a petition filed Feb. 4, saying EV charging “will dramatically increase peak demand on the distribution system unless charging is directed to off-peak periods.”

“The significant increase in consumption due to EV charging has the potential to reduce system costs and rates for all customers because the fixed costs of the distribution system will be collected over a much larger number of kilowatt-hours,” said the group, whose members include the Electrification Coalition, Keystone Energy Alliance, Natural Resources Defense Council, Plug In America, Sierra Club and Gettysburg-based Adams Electric Cooperative.

Obstacle

The petition cited the state Department of Environmental Protection’s Electric Vehicle Roadmap, which identified as an obstacle the lack of utility rates designed to encourage EV adoption.

“Only two Pennsylvania companies offer time-varying (such as time-of-use, or TOU) rates for the supply portion of the bill (Duquesne [Light Co.] and, more recently, PECO [Energy]), and none of the electric distribution companies in Pennsylvania offers TOU rates for the delivery portion of the bill,” the group said. “Moreover, the TOU rates that Duquesne and PECO offer are for ‘whole house’ use. The roadmap recommends a strategy to advance EV deployment, where ‘each utility and electricity supplier could be encouraged to analyze and propose rate designs based on their own peak periods, timelines for introducing advanced meters, and other considerations and constraints.’”

Only 29,000 of the more than 12 million registered vehicles in Pennsylvania are electric, a penetration rate of less than 1%. But the group cited data showing global EV sales increased 41% in 2020 and projections that EVs will represent 25 to 30% of total sales by 2030 and 45 to 50% by 2035 as falling battery prices bring EVs to purchase price parity with internal combustion engine vehicles.

Pa EV Sales by Year (Pa Department of Environmental Protection) Content.jpgPennsylvania electric vehicle sales by year | Pennsylvania Electric Vehicle Roadmap, 2021 Update, Pa. Department of Environmental Protection

 

Pennsylvania expects to receive $171 million over five years from the Infrastructure Investment and Jobs Act to help build out an EV charging network.

The five PUC commissioners approved a joint motion by Chair Gladys Brown Dutrieuille and Vice Chair Stephen DeFrank, with Commissioner Ralph Yanora issuing a supporting statement saying the resulting rates should be “cost-based” and “not include subsidies.”

Commissioner Kathryn Zerfuss also issued a statement, saying that “affordability and equity should be paramount” in any resulting rates. “Our commonwealth should be a leader — proceeding without delay — to demonstrate to the federal government that our actions are deliberate and meaningful, so that we can maximize all potential federal funding available to Pennsylvania for EV infrastructure,” she said.

Other States’ Actions

The petition by ChargEVC-PA included descriptions to rate design initiatives by regulators in Arizona, Maryland and Minnesota.

Baltimore Gas and Electric, PEPCO, and Delmarva Power and Light told Maryland regulators last year that participants in their EV rate design pilot projects had responded to TOU rates by reducing and shifting consumption, with savings of 5.3 to 9.7% in the first year and 2.3 to 7.5% in the second year. The pilots also reduced peak demand in the summer season by 9.3 to 13.7% and by 4.9 to 5.4% for the non-summer season, the utilities reported.

In January, the Maryland Public Service Commission approved changes to the state’s pilot programs (Case No. 9478; Order No. 90036). “With two years remaining in the pilot, the commission recognizes the need to pivot toward deployment strategies that lean into charging gaps in order to engage a more diverse customer base to better understand different charging patterns,” it said. “The decision today reflects a measured approach, where the commission considered the proposals’ objectives along with potential impacts on the competitive market and cost implications for ratepayers.”

Appellate Judge Presses FERC on End-of-life Transmission Planning

PJM stakeholders asked a federal appellate court Wednesday to require the RTO to exercise more oversight over transmission owners’ end-of-life (EOL) projects, saying some of the replacements should be subject to regional planning and competition.

The D.C. Circuit Court of Appeals heard 80 minutes of oral arguments in a challenge to commission rulings that EOL projects are the exclusive province of the transmission owners (20-1449).

In August 2020, the commission accepted a TO-initiated filing adding EOL projects to the planning procedures of tariff Attachment M-3 (ER20-2046). Four months later, the commission rejected proposed tariff changes supported by stakeholders including American Municipal Power, LS Power and consumer advocates that would have moved such projects under the RTO’s planning authority. The commission upheld its rulings last August. (See FERC Rejects Challenges to Decision on EOL Projects in PJM.)

“When the need arises because a facility has been retired, we want PJM to be involved in deciding: Is that a need that gives rise to a plan or a project with regional benefits, in which case it should be regionally planned?” Erin Murphy, an attorney for appellants, told the D.C. Circuit panel, which comprised Judges Neomi Rao, J. Michelle Childs and David Tatel. “Or maybe it is a project that’s local and can be locally planned. What we don’t want is a world in which transmission owners get to make that decision for themselves and decide to locally plan projects, even when as here it’s clear that they actually have projects with regional benefits.”

The appellants said FERC’s rulings result in balkanized planning for EOL projects. In 2018, they noted in a brief, “there were $8.5 billion worth of transmission projects planned, with the largest driver being the need to address end-of-life conditions.”

Speaking on behalf of the TOs, attorney John Longstreth said PJM already has authority to override local EOL projects when there’s an overlap between the local project and a regional project. “PJM gets to plan that project. … We can’t stop that,” he said. “So that protects this regional planning authority.”

In rejecting rehearing, FERC concluded that the Consolidated Transmission Owners Agreement (CTOA) with PJM was “ambiguous” as to planning EOL projects. But the commission sided with the TOs, noting that they had continued to plan EOL projects after the agreement was signed, “with PJM’s acquiescence.”

Rao pressed FERC attorney Susanna Chu on why the commission did not consider the justness and reasonableness of the local planning of EOL projects. Locally planned projects are allocated only to a TO’s zone rather than regionally.

“FERC’s position here seems to me very peculiar,” Rao said. “By choosing the transmission owner proposal, you are choosing one particular allocation of cost. And then why isn’t it incumbent on FERC to determine whether that cost allocation is just and reasonable?”

Chu responded that the rulings did not involve complaints over cost allocation. “The commission accepted it as just and reasonable, but on the basis that it didn’t change the status quo — the existing cost allocation remained the same,” Chu responded.

“Actually, on FERC’s view, it did change the status quo,” Rao shot back. “So at least, at a minimum, FERC’s internal reasoning is unreasonable, maybe, or arbitrary and capricious.”

The TOs intervened to challenge FERC’s description of the CTOA as ambiguous, saying it “interferes with and adds uncertainty to” the transmission planning process. FERC said the TOs’ claim should be dismissed because they failed “to demonstrate that they have suffered any concrete injury.”

Glick’s FERC Tenure in Peril as Manchin Balks at Renomination Hearing

Sen. Joe Manchin (D-W.Va.) said last week he won’t call a hearing on President Biden’s nomination of Richard Glick to remain as FERC chair, dimming the five-year commissioner’s chance of returning for a second term.

Manchin, chair of the Senate Energy and Natural Resources Committee, said through a spokeswoman that he would not bring Glick’s renomination up for a hearing despite his backing from Biden. Manchin “was not comfortable holding a hearing,” spokeswoman Sam Runyon said in an email Thursday, declining further comment.

Glick joined the commission in November 2017 after serving as general counsel for the Democrats on the committee. Biden named him chair in January 2021 and renominated him for a new term in May.

But Manchin — who was angered earlier this year by the commission’s proposal to consider greenhouse gas emissions in natural gas infrastructure certificates — never endorsed him.

At an ENR Committee hearing in March, Manchin accused Glick of pursuing a partisan climate agenda that undermined U.S. energy security. Although Glick defended the original policy statement at the hearing, a month later FERC walked the policy statements back, labeling them as drafts and saying any new rules would apply only to future projects (PL18-1). (See FERC Backtracks on Gas Policy Updates.)

Richard Glick (FERC) FI.jpg

FERC Chairman Richard Glick took part in the commission’s annual technical conference on reliability last week.

| FERC

Glick’s fortunes also may have suffered from Manchin’s testy relationship with Biden.

When Manchin — a pivotal vote in the 50-50 Senate — announced in December that he would not support the president’s Build Back Better climate plan, the White House blasted him for what press secretary Jen Psaki called “a sudden and inexplicable reversal in his position and a breach of his commitments to the president and the senator’s colleagues in the House and Senate.” (See Manchin Says ‘No’ on Build Back Better.)

Relations appeared to have improved when Manchin agreed to the smaller Inflation Reduction Act, and the senator took part in Biden’s signing ceremony in August.

But Manchin was angered anew earlier this month when Biden referred to the Brayton Point power plant in Somerset, Mass., during a speech. Part of Brayton Point — New England’s largest coal-fired plant when it shuttered in 2017 — is being repurposed to a subsea cable manufacturing facility to service the offshore wind industry. “We’re going to be shutting these [coal] plants down all across America and having wind and solar,” Biden said on Nov. 4.

“Comments like these are the reason the American people are losing trust in President Biden,” Manchin responded in a statement Nov. 5. “Being cavalier about the loss of coal jobs for men and women in West Virginia and across the country who literally put their lives on the line to help build and power this country is offensive and disgusting. The president owes these incredible workers an immediate and public apology, and it is time he learn a lesson that his words matter and have consequences.”

White House Press Secretary Karine Jean-Pierre said later that Biden’s words had been “twisted.”

“The president was commenting on a fact of economics and technology: As it has been from its earliest days as an energy superpower, America is once again in the midst of an energy transition,” Jean-Pierre said.

Biden-Signs-IRA-(The-White-House)-Alt-FI.jpgSen. Joe Manchin joined colleagues as President Biden signed the Inflation Reduction Act into law in August. | The White House

 

Manchin’s surprising criticism of his party’s president — coming days before the midterm elections — was unconvincing to conservatives, who noted the senator’s crucial support for the IRA.

New York Post commentator Miranda Devine criticized what she called Manchin’s “faux outrage.”

“He knew what Biden was when he caved in and voted for the so-called ‘Inflation Reduction Act,’ which was the Green New Deal in disguise,” she tweeted.

“Well, sorry, Sen. Manchin, but you single-handedly gave this president more, not less, power to gut our fossil fuels with the idiotic climate bill!” commentator Laura Ingraham tweeted. “You helped create this monster.”

‘Confident’

Whatever the reason for Manchin’s decision, it appears to leave Glick little more than a month to complete his legacy at the commission. Although Glick’s term expired June 30, he can remain in his post through the end of the lame duck congressional session, scarcely enough time to complete all of the major rulemakings he began, including transmission planning and cost allocation (RM21-17) and interconnection policy (RM22-14), in addition to the pipeline policy statement.

News of Manchin’s rejection was not mentioned Thursday during FERC’s annual technical conference on reliability. (See related story, FERC Panelists Talk Cyber, Grid Transformation Challenges.)

“Like I’ve said before, I worry about the things I can control. The things I can’t control, I don’t worry about,” Glick told E&E News during a break in the conference. He added that he spoke to Manchin on Wednesday night and was not told much more than the statements released by the senator’s office. “We’ll see what happens,” Glick said.

Glick left the conference early, citing another appointment.

Speaking in October at the American Council on Renewable Energy’s (ACORE) Grid Forum, Glick said Senate Majority Leader Chuck Schumer (D-N.Y.) and his backers in the White House were “working hard towards confirmation.” (See Scenario Planning, Magical Thinking and Energy Efficiency.)

“They are confident,” Glick said, before turning fatalistic. “We have a lot of day-to-day work to do. [I] try to focus on that on a daily basis, and whatever happens, happens.”

ClearView Energy Partners cited Energy Information Administration data that West Virginia produced almost 91% of its power from coal in 2021, and noted that the state exports about half the power it generates.

“The impact of ‘shutting down’ all coal capacity appears to bode ominously for West Virginia’s economy, independent of Chairman Manchin’s personal investments in the coal sector,” ClearView said. “The White House’s overall decarbonization agenda may be overshadowing Chairman Manchin’s concerns over FERC policy — and the pending renomination may be one of the few levers available to him to push back against it.”

Deadlock?

News of Manchin’s decision sparked discussion on Energy Twitter over how long the commission might be without a fifth commissioner and whether it would face a deadlock between Democrats Allison Clements and Willie Phillips and Republicans James Danly and Mark Christie.

But while Christie was highly critical of the Democrats’ original pipeline policy statement, he has often sided with them on other issues, with Danly often the lone dissenter.

Former FERC Chairman Neil Chatterjee said a 2-2 party split would not deadlock the commission.

Christie “is already at the table negotiating on transmission. And if three votes come together on pipelines, they will move forward regardless of who is chair,” he tweeted. “I had 2-2 for almost a year, and we got a ton of significant things done. … Everything at FERC will be fine.”

FERC Panelists Talk Cyber, Grid Transformation Challenges

At FERC’s annual reliability technical conference on Thursday, commissioners focused on the work needed to prepare the bulk power system for a world of rapidly developing challenges.

Willie Phillips (FERC) FI.jpgCommissioner Willie Phillips | FERC

“Much has been said about mistakes that have happened in the past. Much has been said about some of the near-misses and misses that we’ve had on our system,” Commissioner Willie Phillips, who served as moderator, said in his opening remarks. “What I would like to focus on is the future. I would like for you to help me see around the corner [and] what your thoughts are on best practices that we can use.”

He continued, “Help us see where the gaps are with our regulatory regime, so that we can make sure that we direct the right and specific changes to [NERC’s] reliability standards, which I don’t think anybody can argue are a great foundation.”

The first of the day’s two panels focused on the reliability challenges emerging because of multiple transformations occurring, with the North American power grid becoming more decarbonized, more decentralized and more digital. NERC CEO Jim Robb outlined the issues that the ERO has identified in recent years, such as the behavioral differences between renewable and traditional generation resources; difficulties in controlling a large number of small, distributed generators; and the spread of cyberattacks from criminals and state-backed organizations.

Asked by FERC Chairman Richard Glick for their thoughts on the issues that the commission and NERC should be prioritizing, Robb’s fellow panelists had a wide range of responses. Michelle Bloodworth, president and CEO of America’s Power — a trade organization that advocates on behalf of the U.S. coal generation fleet and its supply chain — warned that the expected retirement of 93 GW of coal plants between now and 2030 would deprive the grid of generators with the “attributes” — including availability, fuel security and voltage stability — needed to maintain stable operation.

“I do think that it’s under FERC’s legal authority to ensure that we’re sending market signals so those resources do not exit the market,” Bloodworth said. “I also think that it’s in FERC’s responsibility under Section 215 [of the Federal Power Act] to … provide the financial support that is needed to retain those assets that provide those attributes, until resources with equivalent characteristics come online.”

But instead of incentivizing utilities to keep these assets and the safety they provide, Bloodworth said that current policies tend to have the opposite effect of encouraging entities to retire their coal plants prematurely. She urged FERC to “play a large role in … determining how we value those attributes” that contribute to reliability “with a sense of urgency” so that utilities can plan their generation needs properly.

Building on Bloodworth’s point, Mark Ahlstrom — vice president of renewable energy policy at NextEra Energy Resources, which calls itself the world’s largest producer of wind and solar energy — told commissioners they “need to actually get down to defining what ‘essential reliability services’ are.”

Calling himself “a representative from the inverter-based side of the world” — referring to the fact that solar and wind facilities, unlike coal plants, connect to the grid through inverters — Ahlstrom said the lack of agreement on what is necessary may have prevented his industry from pursuing the best paths.

“I’ve often said … give me some energy, some electronics, software and a definition of what you need, [and] we can give you anything you want. We just really haven’t clearly defined what is essential,” he said.

Asked by Commissioner Allison Clements about the challenges to managing the clean energy transition, Ahlstrom said that while there are “many pathways [that] all could reach the destination,” the difficult part is coordinating among the many different stakeholders helping to build the BPS. Tricia Johnstone, director of operational readiness at CAISO, added that while NERC’s reliability standards “provide a really good basis for us right now,” the ERO will have to work to ensure they are proactively adapting to the rapid changes.

“For an operator, your day-to-day measure [of] ‘are we doing a good job as a balancing authority’ is [NERC’s] BAL standards and measures, and that’s what we’re monitoring in the control room to make sure that we’re in balance,” Johnstone said, referring to the family of standards that govern resource and demand balancing. “But with some of the technologies — [for example], battery storage ramps very fast, and it will actually send our measurements where we don’t want them to be.”

She said the question for utilities and regulators should be how “those [standards] need to evolve in the future, so as the resource mix changes, do those measurements need to be adjusted?”

Emerging Cyber Challenges

In the second panel, which focused on cybersecurity, Phillips opened by noting that successful cyber defense requires “buy-in from the leadership” and full commitment to establishing a culture of safety, not just compliance. Phillips called NERC’s Critical Infrastructure Protection (CIP) standards a “floor” that can still “never keep up with the threats that we face,” and asked panelists “do you have the resources, do you have the intelligence, do you have the technical capability to … identify and respond to cybersecurity threats?”

SERC Reliability CEO Jason Blake acknowledged the cyber threat landscape as “daunting,” with “well funded [and] aggressive” adversaries who are “only getting more sophisticated.” Coupled with the dedication of the global cyber threat community, the increasing use of remote controls for grid monitoring and control, along with digital communications between utility staff, has expanded the “attack surface” available for these adversaries to target.

While Blake also reported taking “great pride [in] where this industry is today” and called the electric industry’s progress on cybersecurity far ahead of many other industries, he reminded the commission that considerable work will be needed on an ongoing basis just to stay even with the threats.

“We are not perfect, and we cannot rest, and you have to understand that concept as you move forward,” Blake said. “So how do you do that? I think you go in with the larger vision [and] overarching framework to make sure that you are constantly striving your organization, to advance it to meet the security challenges of today and tomorrow. It’s not enough just to try to achieve baseline compliance … what you’re wanting to do is … drive a continuous improvement mindset where you’re really advancing and pushing people.”

The work required to keep the CIP standards up to date was a major topic of discussion at the panel, with Clements suggesting that the deliberate pace of NERC’s standards development process might not be capable of keeping up with the emerging threats. She asked panelists for suggestions of how to make regulated entities more “nimble” while avoiding approaches that would “add another layer of bureaucracy or processes to it.”

Eric Miller, executive director of information technology infrastructure and real-time application support at MISO, suggested that there “could be benefit in trying to adopt existing frameworks.” For example, NERC collaborated with the National Institute for Standards and Technology (NIST) last year on a reference document mapping NIST’s Framework for Improving Critical Infrastructure Cybersecurity to the ERO’s CIP standards. (See NERC, NIST Update Cybersecurity Mapping.)

The benefit of this mapping, Miller said, is that at “a very high level, it’s very easy to communicate across the spectrum” the relationship between NERC’s standards and the NIST framework so that registered entities can identify actions that satisfy both. It can also help NERC’s standards development staff to find gaps in the standards and blind spots that are addressed by other frameworks.

All panelists felt that the CIP standards should not have to stand as the sole word on cybersecurity in the power industry. Brandon Wales, the executive director of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency, said that utilities should have the flexibility to look beyond the minimum required of them and find the tools needed to meet their goals.

“Standards are never going to be there to address the acute problems we deal with, and so I wouldn’t say all emerging issues are behind the power curve, because there are many that can be fit within the existing structures,” Wales said. “But I do think that there are potentially a class of emerging issues that really test the foundations of what we are doing, and … we may need new areas that the existing frameworks don’t sufficiently capture the complexities of the network environment we deal with today.”

CAISO Finalizing Plan for WEIM EDAM

CAISO is moving toward a final plan to add a day-ahead market to its real-time Western Energy Imbalance Market, with the aim of having its Board of Governors and the WEIM Governing Body vote on the proposal in February.

The ISO plans to review a draft plan for the extended day-ahead market (EDAM) in a day-long meeting with stakeholders on Nov. 14. Comments on the final draft are due by Nov. 22, and CAISO expects to publish a final plan in early December.

The draft final proposal published Oct. 31 “reflects significant stakeholder input and design changes” compared with the initial draft in April and a revised proposal in August, CAISO said.

“The draft final proposal is a result of continuing extensive, open and collaborative stakeholder engagement, including more than 500 pages of stakeholder comments on the straw and revised straw proposals and stakeholder discussions during the numerous stakeholder meetings this year,” it said.

Major changes include a requirement that supply offers into the day-ahead market must have “associated transmission reservations.”

“In particular, a resource must be a designated network resource under the terms of the Open Access Transmission Tariff (OATT), have reserved firm point-to-point transmission, or have a legacy transmission contract,” the draft final plan said.

Transmission commitments have been a source of contention in the planning process.

The draft final proposal gives transmission customers and others extra time to plan their daily transmission and resource use by extending the deadline for the voluntarily release of transmission to the market from 6 a.m. to 9 a.m. on the day before delivery.

The plan calls for unscheduled transmission rights to be released to the market to optimize EDAM transfers.

“Stakeholders expressed concern that the timeline for releasing transmission rights to the EDAM …  by 6 a.m. the day ahead is too early and may limit the ability of entities to enter into bilateral arrangements,” CAISO said in the draft. “They preferred to move the time closer to 10 a.m. when the day-ahead market runs.”

CAISO compromised with the 9 a.m. day-ahead deadline.

Resource Sufficiency

The EDAM’s resource sufficiency evaluation (RSE) proposal, meant to ensure that participants can meet their own internal needs before engaging in the market, has been another contentious issue during the EDAM design process.

The RSE is needed because balancing authority areas (BAAs) “across the West are not subject to a common resource adequacy or resource planning program” but EDAM must have a “common mechanism to ensure day-ahead supply sufficiency and avoid leaning on the pool of participants by any one EDAM participant,” the draft says.

The draft final proposal deals with the market’s approach to counting firm energy contracts in the day-ahead RSE, a particular area of concern for some stakeholders.

The contracts “are an important component of the supply portfolios of Western load serving entities and have been historically reliable and dependable sources of supply,” it said. But “for these types of firm energy contracts, while the delivery point to a BAA is known, the source and transmission path may not be known in time for the day-ahead market close [at 10 a.m.], when bids are submitted into the market.”

“Given the potential lack of resource and transmission specificity by the time of day-ahead market run at 10 a.m., stakeholders have expressed concerns regarding challenges that these arrangements raise, including the risk of the supporting resource potentially being double counted in how they are offered into the market and potential congestion price implications,” it said.

The draft final plan proposes allowing firm energy contracts to count toward the resource sufficiency evaluation while “strongly [encouraging] identification of the source or source BAA, particularly if it is located in EDAM footprint.”

“If [the] source BAA is not known, the arrangement will be modeled as a self-scheduled injection at the intertie of the sink BAA,” it says.

Tagging requirements, introduced in the revised straw proposal, are also meant to “instill confidence” in firm energy contracts, it said.

A tagging mechanism or “e-tag” is a means of electronically monitoring and recording energy transactions for firm energy contracts. The proposal requires “all non-source-specific forward supply contracts [to] be tagged within three hours following publication of the day-ahead market results.”

Penalties for failing the RSE have been debated repeatedly during the market’s design.

The draft final plan proposes revising the consequences for failing the RSE by including a “tiered structure that provides a tolerance band under which a relatively minor failure does not constitute a resource sufficiency evaluation failure, but failures above the tolerance band are subject to scaled financial administrative surcharges.”

Wind, Solar Opponents Defeat Four Proposals In Rural Michigan County

Montcalm County in rural north-central Michigan, a hotbed of anti-renewable energy activity since 2021, saw voters in four townships reject referendums that would have established guidelines for wind or solar projects.

Voters in three of the townships — Douglass, Maple Valley and Winfield — also recalled seven officials considered supporters of wind power. Three were the townships’ top officials: Supervisor Terry Anderson in Douglass Township, Supervisor John Schwandt in Maple Valley and Supervisor Phyllis Larson in Winfield.

Voters also rejected a proposal to regulate residential and commercial solar energy projects in Belvidere Township. Belvidere Township does have a wind regulation ordinance on the books that was approved earlier this year by the council.

With all four proposals defeated, wind or solar energy projects in those townships cannot go forward. Local governments’ zoning commissions must reconsider how to handle any potential projects that may come before them.

Facebook Group MTCABW (Montcalm County Citizens United) Content.jpgA group called Montcalm County Citizens United has led the fight against wind power in the rural county. | Montcalm County Citizens United

Disputes over renewable energy projects — to date, mostly wind farm projects — are not uncommon in Michigan. But in the past two years Montcalm County has been a center of local opposition, led by a group called Montcalm County Citizens United, which distributed lawn signs saying: “2 Tall, 2 Close, 2 Loud. Not In My Backyard.”

Apex Clean Energy has been working for four years to develop a wind farm in the county with up to 75 turbines (375 MW). The company has also added a solar energy component to the project.

Brian O’Shea, Apex’s director of public engagement, said the company was disappointed with some of the election results, charging voters had been misled by an “organized misinformation campaign.” But he said the company still planned to work with “with over 500 participating farmers and landowners to develop a responsible wind project in Montcalm County and help accelerate Michigan’s shift to clean energy.”

Michigan has at least 3,231 MW of wind power, 6.8% of its total generation, with 225 MW under construction, according to the Department of Energy.

Opponents of the Montcalm regulatory proposals overwhelmed supporters in all four townships. In Belvidere Township, with the solar proposal, the race was the closest with 600 against and 378 in favor. Douglass Township had votes on two proposals regulating wind farms, and both failed. The first proposal was defeated 812 to 297, while the second proposal went down 819 to 304.

The Maple Valley Township proposal failed 594 to 265. And the Winfield Township proposal failed 736 to 355.

Winfield Supervisor Larson lost her recall election by just 56 votes.  She said she was targeted because she had cast the deciding vote on the township’s wind ordinance.

Local media reported that the election results are leading some to call for the state — which has a goal of generating 60% of its power from renewables by 2030 — to take control of siting of energy projects.

“What happened in Montcalm is part of a larger chorus of [grassroots opposition] to these projects,” Ed Rivet, executive director of the Michigan Conservative Energy Forum, a nonprofit that advocates for clean energy, told Bridge Michigan. “I don’t see the trend (of local opposition) suddenly disappearing,” Rivet said. “The more that goes on, the more it will lead to a policy discussion.”

Charlotte Jameson, chief policy officer for the Michigan Environmental Council, told MLive there is a growing consensus that the state must become more involved: “The siting issue is definitely one where you have environmental groups, utilities and labor in agreement that there needs to be some kind of solution here.”

NY Considers Role for New Nuclear Generation

Low-Cost Nuclear Power (Climate Action Council) Content.jpgLow-Cost Nuclear Power Reduces Electricity System Costs by $1.1B | Climate Action Council

ALBANY, N.Y. — New York could reduce its decarbonization costs by $1.1 billion, an 8% cut, if forecasts of lower cost advanced nuclear reactors are realized, the New York State Energy Research and Development Authority told the Climate Action Council last week.

Carl Mas, director of NYSERDA’s Energy and Environmental Analysis Department, shared a sensitivity analysis during the Nov. 7 meeting that found that deploying 4 GW of small modular nuclear reactors in upstate zones A-F by 2050 could displace 12 GW of intermittent renewables and 5 GW of firm resources or battery storage under a low-cost nuclear scenario aided by new federal funding.

The low-cost scenario assumes 2030 capital costs of about $6,000/kW (2020 $) versus more than $9,000/kW under the high-cost scenario based on recent nuclear projects.

Proponents of advanced nuclear designs — such as the NuScale small modular reactor recently certified by the Nuclear Regulatory Commission — cite their passive safety features and potential economies of scale compared with traditional custom designs that have been prone to cost overruns. In addition to producing zero-emission electricity, such designs could be used in industrial process heat and hydrogen production.

New York’s four current reactors — Nine Mile Point units 1 and 2, James A. FitzPatrick and R. E. Ginna — total 3,358 MW of capacity and produced about one-quarter of the state’s in-state generation in 2021. Each of the plants has received license extensions from the NRC allowing them to run for a 60-year lifespan.

Prior analysis found the state’s electric system costs would increase by $9 billion on a net present value basis if the plants shut down after only 40 years. Their current license terms expire between 2029 and 2046.  

Installed Nuclear Capacity (Climate Action Council-2022 Gold Book) Content.jpgCurrent installed nuclear capacity & contribution in New York State | Climate Action Council / 2022 Go

Adding 4 GW of new nuclear capacity would more than double nuclear’s share of energy production from the current 31 terawatt hours. No new nuclear would be added under the high-cost scenario.

In both scenarios, Mas said, “a majority of the energy and installed capacity is from wind and solar in 2050.”

Nuclear’s competitiveness would be dependent on new lower-cost designs — aided by more than $2 billion in funding from the CHIPS and Science Act — and tax credits under the Inflation Reduction Act. The two bills represent a “significant ramp up” in federal investment in the technology, Mas said. (See A Nuclear Renaissance in the Making?)

Mas said transmission costs and a lack of operational flexibility could limit nuclear’s future role. “We could hypothesize that with more flexible new reactor designs, we might see nuclear playing a larger role,” he added. “If more transmission gets built for the whole system than what we modeled, you could see more energy flowing from upstate to downstate, and that could put a put additional economic value on upstate nuclear.”

The scenario assumes the technologies would not come online until at least 2040. The findings “reinforce the benefits of a more flexible policy framework that can adapt over time,” Mas said.

Low-Cost vs High-Cost Nuclear Scenarios (Climate Action Council) Content.jpgLow-Cost Nuclear Scenarios Adds 4GW by 2050 | Climate Action Council

 

“We’re looking at least a decade for when these types of projects can get up and going,” he added. “Frankly, we just don’t know yet … since some of these new modules are only now being authorized.”

Bob Howarth, a professor at Cornell University, questioned the assumption that New York’s nuclear fleet possessed a 90% capacity accreditation factor (CAF), saying that Europe’s fleet average is “closer to 72 or 74% CAF.”

Mas responded that market signals under deregulation had led to a “substantial uptick in the utilization and CAFs of the nuclear fleet.”

Gavin Donohue, CEO of the Independent Power Producers of New York, commended the presentation, saying it highlighted how the state needs to be flexible and “keep the door open” to new technologies.

Paul Shepson, dean at Stony Brook University, asked whether nuclear waste disposal was incorporated into the cost estimates.

Mas responded that “there is an end-of-life assumption in terms of cost” and that, in the absence of national plan to manage spent fuel, the waste will be stored “in-place” at reactor sites.

Next Steps

Sarah Osgood, executive director of the CAC, said that remaining redlines of the council’s scoping plan will be circulated for consideration throughout the month ahead of a planned vote on the document on Dec. 19.

Climate Protesters 2022-11-07 (RTO Insider LLC) Alt FI.jpgClimate protesters attending climate action council meets in Albany, N.Y. | © RTO Insider LLC

 

NYSERDA CEO Doreen Harris, the CAC’s co-chair, said the remaining meetings would be extended to four hours to accommodate the longer discussions that are expected as the council completes work on the plan.

The meeting on Dec. 5 would be used to reach final resolutions on outstanding items before the Dec. 19 vote.

Registration is open for the next Climate Justice Working Group meeting on Nov. 16.