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November 17, 2024

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FERC Again Prohibits MISO TOs from Financing Merchant Upgrades

FERC last week upheld its prior ruling blocking MISO transmission owners from self-funding network upgrades for merchant HVDC transmission lines.

The commission affirmed in its Friday order a decision issued in the spring that the self-funding option cannot be extended to merchant upgrades because their developers aren’t offered the same range of financing options as transmission owners under certain circumstances (ER22-477-002). (See FERC Blocks MISO Self-fund Rule for Merchant HVDC Line Upgrades.) 

FERC rejected arguments from MISO, its transmission owners and ITC Midwest that merchant HVDC developers and generation developers are interchangeable because they both require upgrades to the system for their projects.

The commission again emphasized that MISO doesn’t include an option to build or liquidate damage provisions in interconnection agreements for merchant HVDC developers without injection rights or a precertification from MISO that its system can handle the capacity and energy the line plans to deliver. The grid operator allows merchant HVDC lines to connect to the system without injection rights, but those lines are considered non-firm and the upgrades are classified as necessary upgrades instead of network upgrades.

MISO, TOs and ITC argued that necessary upgrades for HVDC lines are similar to the RTO’s other network upgrades, where the owners have the right to finance the upgrades before the interconnection customers are offered the chance.

“The thrust of MISO and MISO Transmission Owners’ and ITC Midwest’s argument on rehearing is that these two sets of customers are effectively indistinguishable, but neither grapples with how, then, MISO’s proposal to afford options to control risk and certainty during the design and construction process to only one set of customers is just and reasonable and not unduly discriminatory,” FERC wrote.

The commission said MISO’s case for applying initial funding to merchant HVDC lines “does not alter the fact that MHVDC connection customers with necessary upgrades are distinct because, unlike interconnection customers and MHVDC connection customers with network upgrades in MISO, they lack injection rights and are subject to different study requirements.”

Commissioner James Danly again protested the decision, as he did when it first came before FERC. He repeated a dissent that the decision denies “transmission owners’ right to receive a return on and of the capital costs of network upgrades, necessary upgrades and transmission owner system protection facilities.”

Commissioner Mark Christie separately concurred, contending that merchant developers are on equal footing with generation developers in RTOs. He said they should both pay the full “but for” costs of interconnection, including network upgrades.

“When … a generation developer or a merchant transmission line developer pays the full costs of its interconnection, it is the developer incurring a cost of capital, not the transmission owner,” he wrote. “Allowing the transmission owner a profit on someone else’s capital investment would be an unearned windfall. When the transmission owner incurs operations and maintenance costs associated with the upgrade, the transmission owner can seek cost recovery in compliance with applicable utility accounting rules or other acceptable procedures.”

The latest decision on HVDC self-funding is connected to a larger, still-unfolding saga over who has the right to finance line upgrades in MISO.

MISO reinstated TOs’ right to self-fund network upgrades necessary for new generation at the direction of a 2019 FERC order. The decision has been a hot-button issue, spawning three years’ worth of reopened contracts, refunds to interconnection customers, interconnection agreements left unexecuted in protest, and condemnation from FERC Chairman Richard Glick. (See FERC Upholds MISO Self-fund Order, Glick Dissents.)

The D.C. Circuit Court of Appeals in November ruled that FERC did not adequately explain why it recently reinstated transmission owners’ option to self-fund. It remanded the case back to the commission. (See FERC Must Clarify MISO Tx Funding Decision, DC Circuit Finds.)

MISO has revised various interconnection agreements for TOs who wanted to have first crack at network upgrades’ initial funding. (See FERC Accepts Documents in MISO TOs’ Self-fund Selection.)

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FERC Upholds MISO’s Cost Allocation for LRTPs

FERC continues to sanction MISO’s separate-but-equal postage stamp rate that is divided between its Midwest and South regions for major transmission buildout.

The commission rejected rehearing requests with an order Friday that keeps MISO’s subregional cost-allocation method for long-range transmission planning (LRTP) projects in place (ER22-995-001).

FERC said it continues to believe that it’s appropriate for the RTO to allocate project costs “broadly within a single subregion rather than solely on a systemwide basis.”

MISO is using a FERC-approved 100% postage stamp to load rate for the first two cycles of projects coming out of its LRTP studies. The costs are confined to the grid operator’s Midwest region, where the projects are physically located. (See FERC OKs MISO’s Bifurcated Cost-allocation Tx Design.)

When the RTO begins addressing needs in its South region during the final two LRTP portfolios’ work, it said it might use a new, more specific cost-allocation design that accounts for more beneficiaries. (See “Zeroing in on Cost Allocation,” ‘Conceptual’ Tx Planning Map Troubles MISO Members.)

MISO has already approved $10 billion in projects with its first LRTP portfolio. It may recommend up to $30 billion of work as part of its second portfolio.

Sequestering MISO Midwest from MISO South continues a transmission-planning tactic that staff has used since integrating the South in 2013. Through separate cost-allocation treatment and study deferrals, MISO shields its South region from footprint-wide system planning and allocation impacts.

American Municipal Power (AMP) and MISO’s industrial customers said FERC blindly accepted a “crude” cost allocation method that isn’t supported by analysis and will require transmission customers to foot steep bills, even when a project benefits a neighboring RTO. They argued that the commission neglected its duty to independently assess the rate proposal and said MISO failed to devise a more precise allocation when it had the means to do so.

The intervenors said FERC was wrong to characterize the new LRTP cost allocation as essentially the one used for 2011’s Multi-Value Project (MVP) portfolio with only “limited” changes. AMP argued there’s a “fundamental distinction between regional and subregional planning and cost allocation.” The MVP portfolio was allocated systemwide with a postage stamp rate in 2011, when the footprint didn’t extend beyond southern Missouri.   

The industrial customers said that FERC “cannot transfer its duties to the RTO stakeholder process or assume that state regulatory support or majority support in the RTO stakeholder process indicates widespread consumer satisfaction or provides evidentiary support for a just and reasonable rate outcome.”

They also said that the “promise of a more granular cost allocation for future LRTP projects does not justify acceptance of an allocation of over $10 billion in costs that are not sufficiently tied to roughly commensurate project benefits.”

MISO’s first LRTP portfolio alone could raise costs by as much as $2.80/MWh, the customers said.

They also contended that MISO relied on “stale” data to back up its allocation design. The RTO used a Brattle Group analysis that showed the 2011 MVP projects’ benefits were overwhelmingly confined to the Midwest region. The consulting firm said that benefits’ spread will likely continue unless MISO secures more transfer capability between the subregions. (See “Brattle: South Benefits Unlikely from Midwest,” MISO Finalizes Long-range Tx Cost Sharing Plan.)

FERC said that MISO was not required to “re-justify the MVP category from scratch,” nor was it required to “analyze the data from future LRTP portfolios.” The commission pointed out that courts have repeatedly found that a rate should be reasonable, not that it should be “the most reasonable or the best one out of possible alternatives.”

“It is not unduly discriminatory for the [c]ommission to accept a subregional option while MISO continues to discuss with stakeholders a different approach for future projects,” FERC said. “Therefore, arguments concerning future cost allocation method filings are premature.”

The commission said MISO’s LRTP allocation divvies costs on a “basis that is at least roughly commensurate with the estimated benefits” and was the product of “an extensive, multi-year stakeholder process.” It also defended the Brattle analysis, highlighting its “large data set of 16 actual — not just proposed ― projects.”

It said industrial customers’ request to allocate costs to customers outside of MISO is beyond the scope of the order.

In planning meetings, some MISO stakeholders have voiced concerns of disparate treatment between LRTP portfolios, saying a different cost allocation for projects in MISO South will violate FERC’s cost-allocation principle that differing allocations must not be applied to the same class of projects.

Commissioners James Danly and Mark Christie agreed with the order in short concurrences. Danly said although he had misgivings over the postage stamp method in general, he could not say definitively that its use is unfair.

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Experts Call for More Granular Clean Energy Procurement

A parade of experts extolled the virtues of more granular clean energy purchasing at Raab Associates’ New England Electricity Restructuring Roundtable earlier this month, calling it essential to meeting climate goals in the region and around the country.

Citing the limitations of the widespread annual matching that makes up most corporate and institutional clean energy procurement, the academics and policymakers also called for grid operators to develop data to help lead the charge.

“In order to fully decarbonize our electric grid in New England, we will very likely need to realign our policies, procurements and supporting data from its current broad-brushed monthly and annual matching frameworks to ones that focus either on a much shorter period time, such as hourly, or on marginal emissions rates, or both, as well as more granular locational matching,” said Jonathan Raab, convener and one of the moderators at the event Dec. 9.

Jesse Jenkins, a Princeton University professor and prominent energy expert, laid out the problem: While voluntary clean energy procurement through long-term contracts has helped finance renewable projects, it has significant limitations that are becoming more clear.

“There are times when the production from wind and solar is quite a bit lower than the consumption from the procuring consumers,” Jenkins said. It’s a mismatch that “limits the ability to reduce CO2 emissions associated with the buyer’s consumption.”

A solution that’s coming to the fore, led by some major corporate buyers, is 24/7 matching, where companies try to purchase clean energy that matches their demand hour by hour, from within the same region.

“I think 15, 20 years ago, probably the best we could have done was annual matching. It made sense to make an assumption that all clear resources are equal,” said Kathleen Spees, a principle at the Brattle Group. “It’s certainly not always true now.”

Hour-by-hour carbon-free procurement enables “deeper emissions reductions than annual matching,” Jenkins said.

And it drives early deployment of advanced technologies, helping to create “niche markets” that can help pull forward technology like clean firm generation and long-duration storage.

But there’s a key reason why more companies aren’t doing this yet: It’s expensive.

“There is a cost premium for first movers who want to go from annual matching all the way up to 100%, or near 100% hourly,” said Mark Dyson, managing director for carbon-free electricity (CFE) at RMI.

Dyson worked on a project with Microsoft last year to assess the costs, emissions impacts and system transformation impacts of procuring CFE on an hourly basis to match their load.

It’s the tech giants that have been the earliest movers in the space. Along with Microsoft’s work, Google is one of the first companies to start diving deep into 24/7 matching.

At the second panel of the day, moderated by Janet Gail Besser, vice president of the Smart Electric Power Alliance, Google’s head of energy market development and policy, Caroline Golin, laid out the company’s plans.

“Our goal is that every hour of every day, all of our facilities will match our energy use with carbon-free energy, and that all of that energy will be procured locally within the balancing authority or RTO in which we operate,” Golin said.

It’s an evolution of the company’s goal to use 100% renewable energy to power its operations.

“Google’s a large company that has invested a lot of internal resources and deployment of capital to meeting our clean energy goals. We recognize that we’re a unique player in the field,” Golin said.

It’s also trying to help other companies learn from its experience, sharing information about its business model.

“The leadership that we’re seeing from corporate buyers is really exciting,” said Spees, who noted that they don’t have the same constraints as public entities. “They can just sign a contract around a corporate objective they believe in.”

A Data Problem

Another challenge with more granular matching is that it requires a heavier lift with data, both for companies looking at their consumption and for grid operators or other entities measuring emissions.

“There is no market structure to date that is built for a completely decarbonized electricity system,” noted Golin.

Misti Groves, vice president of the Clean Energy Buyers Association, said that her members need more to go on.

“To do more, customers need accessibility, transparency and a standardized format,” she said, adding that a centralized database would be ideal.

“Right now, companies are using inferior datasets that are not reconciled,” she said.

A number of corporations can’t accurately measure their consumptions, she said.

“You’d think a fundamental question is, what’s your load? What’s your consumption?” Groves said. “A baseline is incredibly important.”

Tanuj Deora, director of clean energy at the White House Council on Environmental Quality, laid out the framework, in the form of an executive order, that the Biden administration has set to increase the government’s procurement of carbon free electricity.

“We wanted to have a strategic shift, recognizing that we are the largest buyer in the country and therefore have a lot of influence with suppliers,” he said.

Geography matters, Deora added.

“We focused on the idea that high levels of CFE are possible, and that there are going to be different pathways, balancing area by balancing area,” Deora said.

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MISO, PJM Staffs Endorse 1 TMEP Joint Project

MISO and PJM have endorsed one small interregional project this year after their Targeted Market Efficiency Project (TMEP) study.

The grid operators said they will pursue $200,000 of line work on the Powerton-Towerline 138-kV flowgate in central Illinois. The project is expected to yield $1.8 million in annual congestion savings benefits; PJM is projected to realize about 72% of the savings benefits and MISO 28%.

The project is one of two that survived a final round of analysis. The RTOs also considered an upgrade to a congested 138-kV flowgate near Chicago.  (See MISO, PJM Down to 2 Possible TMEPs.)

PJM’s Nick Dumitriu said during a MISO-PJM Interregional Planning Stakeholder Advisory Committee meeting Thursday that the Chicago constraint’s congestion is not persistent enough to proceed with a project. He said staffs’ additional analysis confirmed that a significant part of the flowgate’s historical congestion is caused by neighboring outages.

Both RTOs will recommend early next year that their respective boards approve the Powerton-Towerline project. The project must be in service no later than June 1, 2025.

The grid operators require TMEPs cost $20 million or less, be in service by the third summer peak from approval and must completely cover installed capital costs within four years through congestion benefits.

MISO and PJM studied about $328 million of congestion from 2020-2021 in this year’s TMEP process. They originally identified 23 flowgate candidates that might benefit from a TMEP project and reviewed potential problem spots for interregional solutions.

Clean Grid Alliance’s Natalie McIntire asked that the RTOs consider raising the $20 million cost threshold to increase the chances for other potential projects.

“There’s certainly been a significant amount of inflation and overall cost increases,” McIntire said.

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Glick Bids Farewell to FERC

WASHINGTON — FERC Chair Richard Glick said Thursday that he will leave the commission when the 117th Congress adjourns, likely by the end of the year, ending five years as a federal energy regulator.

President Biden nominated Glick for a second term in May, but Sen. Joe Manchin (D-W.Va.), chair of the Senate Energy and Natural Resources Committee, has refused to hold a confirmation hearing for him. (See Glick’s FERC Tenure in Peril as Manchin Balks at Renomination Hearing.)

Glick’s term ended June 30, but if they are not nominated for another term, FERC commissioners are allowed to continue serving past the end of their current terms until a replacement is confirmed or until the current Congress adjourns sine die. (Congress’ adjournment is typically before the end of the calendar year, though it could be in session until noon on Jan. 3.)

Given how late it is in the year and how long the confirmation process takes in the Senate, “I think it’s pretty clear there’s not a path forward anymore” for his nomination, Glick said at the commission’s last open meeting of the year.

Richard Glick and his binder of grievances (FERC) Alt FI.jpgFERC Chair Richard Glick jokingly refers to his “binder of grievances.” | FERC

 

Although Glick remains the nominee until the end of Congress, he told reporters after the meeting that he has already declined to be nominated again next year.

“I’m still a candidate out there, but just given the timetable and the time it takes to move a nominee forward, I don’t really foresee” being confirmed this year, Glick said in a press conference after the meeting. “I have notified [the White House] that I’m not interested in coming back, in large part because I know this [nomination] process pretty well. Even under the best of circumstances, I know it would take a number of months. I can’t do that to my family; I can’t do that to myself, for that matter.”

And unless something unexpected happens, Glick added, “Sen. Manchin is still going to be chair of the Energy Committee. I don’t know why things might be different next year versus this year, so I think it’s better that they [the administration] move on.”

Manchin was angered earlier this year by the commission’s proposal to consider greenhouse gas emissions in natural gas infrastructure certificates.

Glick did not participate in several orders that were part of the meeting’s consent agenda: two that involved MISO (ER22-477-002 and ER22-995-001, both of which had not been published as of press time), and one that involved utilities in the WestConnect transmission planning region (ER22-1105). Last month he did not participate in an order that involved PJM (ER22-2110).

Glick told reporters he recused himself from these orders because once it became clear to him that he would not be confirmed, he had expressed interest in an available job. Though he did not end up getting the job — nor had he even formally applied — under FERC’s ethics rules, “you not only have to recuse when you’re negotiating … you also have to recuse afterward during a ‘cooling-off’ period,” he said.

When asked if he had any work lined up for after he leaves, Glick joked, “Not unless you know something.”

“You know, people say this all the time: ‘I’m leaving the job to spend more time with my family!’” he said during the meeting, citing the demands of the commission that often require working late Fridays and weekends and taking late-night phone calls. “But that’s what I intend to do, and I really look forward to it.”

Fierce, but (Mostly) Collegial, Debates

Glick was nominated by President Donald Trump and joined the commission in November 2017. Biden, upon becoming president in 2021, named Glick chair to replace Republican Commissioner James Danly.

His tenure at the commission — both as a commissioner in the Democratic minority, and as chair with a majority — was marked by a fierce divide along party lines. Glick wrote scathing dissents to the Republican majority’s decisions in many high-profile dockets and butted heads with Chairman Neil Chatterjee and Commissioner Bernard McNamee. He was then on the receiving end of many equally scathing dissents from Danly — sometimes joined by fellow Republican Commissioner Mark Christie — when he was chair.

Chatterjee and Glick did find common ground, however, on several notable issues, such as Orders 841 and 2222 — which directed RTOs and ISOs to open their markets to energy storage and distributed energy resource aggregations, respectively. And since leaving the commission, Chatterjee has often called Glick his friend. Though he frequently issues separate concurrences noting his concerns, Christie has also sided with the Democratic majority often.

In contrast, Glick and Danly’s debates have not just played out in concurrences and dissents, but also at open meetings, normally tightly scripted affairs. Glick once compared Danly to a Chicken Little-like Paul Revere; during the same meeting, Danly said Glick was being snide. (See FERC Rejection of Weymouth Rehearing Leads to More Barbs.)

James Danly Richard Glick (FERC) Content.jpgFERC Commissioner James Danly, who famously clashed with Chairman Richard Glick over the past five years, praised the chairman for being “unfailingly gracious.” | FERC

 

At the close of Thursday’s meeting, both commissioners somewhat sheepishly acknowledged the tension.

“And now we come to Commissioner Danly,” Glick said after praising his other three colleagues. “It’s an understatement to say we’ve had our difference of opinions. And we’ve certainly said some harsh things about each other. … But we’ve kept our lines of communications open. In our conversations, we’ve kept things civil. … And I think it’s very important on a going-forward basis that even when there’s differences in opinion … it’s important to keep those lines of communications open and figure out where you can work together and how you can work together.”

Danly, who served as FERC general counsel before he became a commissioner, told Glick that he “breathed a massive sigh of relief and gratitude when you appointed Matt [Christiansen] general counsel. You know, when I was GC, he created a great deal of work for me with all the dissents, and I think the score is almost settled at this point.”

He also affirmed “that it is true that we have wrangled a lot and disagreed a lot. … It has been more than five years that we have been fighting over substance, and we both have the scars to prove that. …

“When you read the press accounts — ‘Glick, Danly Spar on…’ — sure, we are, but in reality we have quite a bit of collegiality,” Danly said. He also praised Glick’s graciousness in helping him with “problems or resource needs” and for being accommodating given the “vast number of orders we have to push through.”

Glick concluded his remarks at the meeting by expressing gratitude for “five exciting and engaging years.”

“I can honestly say that we have not had one boring day at the commission. Not at all boring. These days, it’s inextricably linked to … the transition that’s underway to the way we produce, the way we consume and the way we transport energy. It’s, from a technological standpoint, amazing. The speed at which we’re moving forward is amazing. And from a societal perspective — whether it be from an economic perspective to the United States, or just in terms of the environment — it’s just tremendous.”

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NYSERDA Gets Funding Boost as Energy Transition Continues

The New York State Energy Research and Development Authority is getting a funding boost to hire more people as it administers the state’s Clean Energy Standard program, but not as large a hike as it had sought.

The state Public Service Commission on Thursday approved a $33.4 million administrative budget for NYSERDA for next year. The agency will use part of the increase to hire more people to manage the renewable energy contracts that are continuing to increase in number and complexity in the wake of the state’s Climate Leadership and Community Protection Act.

The budget for 2022 is $30.2 million.

NYSERDA had sought $38.8 million for 2023 and authorization to add 19 full-time equivalents to the 22.5 FTEs currently working on CES administration. Its petition drew supportive comments from several clean energy and environmental advocacy groups and no comments in opposition.

However, Department of Public Service staff pared back the request, eliminating five of the prospective hires and $4.1 million in spending on technical services. Staff said the reduced budget request would strike a balance between the ratepayers who are footing the bill and the growing demands placed on NYSERDA.

PSC Chair Rory Christian said the CES is the tool by which New York will reach its statutory requirements for decreasing emissions and increasing renewable energy deployments.

“What we see here today highlights how far we’ve come since 2016,” he said. “Adoption of the NYSERDA administrative budget today will enable the continued growth of renewable generation in New York state.”

Commissioner Tracey A. Edwards went a step further, saying that she would have supported the original $38.4 million and that the PSC should not micromanage NYSERDA.

“We can cut the legs off and really make sure that this doesn’t work by not giving it proper funding,” she said.

Commissioner John B. Howard came at the issue from a different angle. NYSERDA is not funded through the state budget process and its staff are not subject to civil service requirements, nor represented by a union, he said. The PSC provides the primary oversight and needs to do a better job of it, he said.

“Given that NYSERDA will issue hundreds of billions of dollars’ worth of contracts as part of the CLCPA mandates, it is time for greater oversight of NYSERDA, not just from DPS, but I believe from the comptroller’s office as well,” Howard said.

He clarified he was not criticizing NYSERDA but calling for transparency, because New Yorkers footing the bill for decarbonization need to see the money being spent wisely. Having said that, he voted in favor of the budget, because the increases would be covered by NYSERDA’s surplus funds, rather than new money from ratepayers, he said.

The lone vote against the budget came from Commissioner Diane Burman, who said the cuts to the original budget request were not deep enough and there was not sufficient explanation of the benefits to the ratepayers who fund NYSERDA.

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Manchin Permitting Bill Falls Short in Senate

The Senate on Thursday night rejected Sen. Joe Manchin’s (D-W.Va.) bid to tag his controversial permitting bill to the National Defense Authorization Act (NDAA).

Needing 60 votes to append his bill to the NDAA, Manchin won only a 47-47 tie, despite an endorsement Thursday morning from President Biden, who said it would “cut Americans’ energy bills, promote U.S. energy security, and boost our ability to get energy projects built and connected to the grid.”

Roger Marshall (C-SPAN) Content.jpgSen. Roger Marshall (R-Kan.) speaks against Manchin amendment. | C-SPAN

The Building American Energy Security Act of 2022, which would accelerate permitting of energy and mineral infrastructure projects, faced opposition from Democrats — who saw it as a concession to the oil and gas industry — and Republicans upset with Manchin’s vote for the Inflation Reduction Act. (See Manchin Presses Permitting Proposal Excluded from Defense Bill.)

It also faced opposition from state regulators upset by provisions increasing federal transmission siting authority. “States are not the problem,” the National Association of Regulatory Utility Commissioners said in a letter. “Rather, existing federal law and policies have been the biggest barrier to infrastructure rollout.”

Americans for a Clean Energy Grid, the American Council on Renewable Energy, the International Brotherhood of Electrical Workers, the Solar Energy Industries Association and Third Way issued a statement supporting the transmission provisions.

“A comprehensive approach to advancing new transmission investment is long overdue and urgently needed,” the groups said. “While it is not comprehensive, we believe the transmission portion of the Building American Energy Security Act of 2022, as updated last week, will make incremental, yet meaningful, progress.”

Vote on Manchin amendment (C-SPAN) Content.jpgSenate votes on Manchin permitting bill. | C-SPAN

 

Manchin gave an impassioned 11-minute speech on the Senate floor before the vote. Afterward, he issued a statement putting the blame for the bill’s failure on Republicans.

“Once again, Mitch McConnell and Republican leadership have put their own political agenda above the needs of the American people,” he said.

“As frustrating as the political games of Washington are, I will not give up,” he added.

Among the “yes” votes were five Republicans. Nine Democrats and Independent Bernie Sanders of Vermont voted “no.” Six Republicans abstained.

The $858 billion NDAA passed later Thursday evening on an 83-11 vote.

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California PUC Adopts Contested Net Metering Plan

The California Public Utilities Commission on Thursday adopted a controversial proposal to revise the state’s net-metering scheme for rooftop solar arrays, including by reducing bill credits for new solar owners and incentivizing battery installations.

“We are launching the solar and storage industry into the future so that it can support the modern grid,” CPUC President Alice Reynolds said in a statement issued after the vote. “The new tariff promotes solar systems and battery storage with a focus on equity and advances the new clean energy technologies we need to meet our climate goals and help ensure grid reliability.”

The vote came after months of wrangling over the plan, which was originally proposed a year ago, then postponed amid public outcry and rewritten to mollify homeowners angry about the possibility of losing their solar subsidies.

The modified proposal, approved by a unanimous vote Thursday, says it tries 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.”

It will not change the credits paid to current rooftop solar owners for excess electricity they export to the grid. The state’s investor-owned utilities compensate those homeowners at full retail electricity rates, which are much higher than the current costs of utility-scale solar.

The subsidies shift the costs of solar panels from ratepayers who can afford them to those who cannot, Pacific Gas and Electric (NYSE:PCG) and other IOUs argued. The “cost shift” amounts to $3 billion to $4 billion a year, the utilities estimated.

The generous payments to those who install PV panels 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 MW of renewable generation,” the CPUC said in a news release last month.

The CPUC’s previous net energy metering proposal, issued in December 2021, would have slashed NEM bill credits by more than half and possibly up to 80%, including for homeowners who installed solar panels prior to the plan’s adoption. (See California PUC Proposes New Net Metering Plan.)

Under the revised plan, future rooftop solar owners will be compensated differently from existing customers through “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 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 that accompanied the proposed decision when it was released in November said the new rate structure will 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 will benefit by selling more storage along with solar arrays, it said.

The adopted plan removed 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 panels 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.

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FERC Moves to Implement New Backstop Transmission Siting Authority

FERC on Thursday approved a Notice of Proposed Rulemaking that would pave the way for overriding state regulators’ rejections of certain transmission projects (RM22-7).

Congress originally gave FERC this backstop siting authority for transmission projects in Department of Energy-designated National Interest Transmission Corridors as part of the Energy Policy Act of 2005. But the 4th U.S. Circuit Court of Appeals ruled this only applied to those projects that state regulators did not act on, not to those that states denied (Piedmont Environmental Council v. FERC (2009)).

A provision in last year’s Infrastructure Investment and Jobs Act essentially overturned that ruling, expanding FERC’s backstop authority over state-rejected projects. The NOPR is intended to implement that provision.

“The NOPR clarifies the commission’s siting authority by expressly stating that the commission may issue a permit for the construction or modification of electric transmission facilities in DOE-designated national corridors if a state has denied an application to site transmission facilities,” Abigail Christoph, an attorney-adviser in the Office of General Counsel’s, said in a presentation at FERC’s open meeting Thursday.

E-1 panel (FERC) Content.jpgAbigail Christoph and Kim Smaczniak, of the FERC Office of General Counsel, and Enakpodia Agbedia, of FERC’s Office of Electric Reliability, brief FERC commissioners on the NOPR. | FERC

 

It would also allow developers to begin prefiling proceedings for their projects with FERC while its state applications are pending, instead of waiting for one year after they submit them.

“This change will allow applicants to simultaneously pursue approval before a state and the commission if they so choose,” Christoph said.

Transmission wonks generally consider federal backstop siting authority necessary for building large, interregional projects, as just one state can unilaterally kill a multistate project if it rejects its developer’s application. It is a deeply unpopular concept with state regulators, however.

FERC acknowledged this in the NOPR by proposing several rule changes aimed at ensuring a thorough process if a developer requests that it override a state’s rejection.

The commission would create a new applicant “code of conduct” for how potential permit holders engage with landowners. It would also require three “resource reports” be included in applications: on environmental justice, tribal resources, and air quality and environmental noise.

Republicans Tentatively Approve

All five FERC commissioners voted to approve the NOPR, but they didn’t agree on whether it will actually help build out any transmission projects.

“Infrastructure is extremely difficult to site in the United States,” Chair Richard Glick said. “It’s something that, as a country, we need to come to grasp with, especially in regards to transmission. … We have to get it done as a country, and I think this is a step in the right direction.”

Fellow Democratic Commissioner Allison Clements pointed to the provisions that add new requirements for engaging with landowners and other stakeholders as helpful to getting projects done and avoiding litigation.

“It’s really hard to build infrastructure because that impacts people. So let’s find ways to bring people into the conversation early on and get satisfactory outcomes,” she said.

But Republican Commissioner Mark Christie challenged both the premise of the new rules — that states are blocking transmission buildout in a meaningful way — and their function.

“This narrative that’s being pushed — that the states are standing in the way of critically needed infrastructure — is a false narrative,” Christie said.

He noted that the transmission rate base around the country has almost tripled in the last 10 years.

“The states are not standing in the way of critically needed transmission projects. The states are by and large approving them. If the states need anything, they need more authority to vet projects, not less,” he said.

Christie also said the rule changes would not be a “magic bullet” that results in more transmission. Instead, he said, they would create multiple lines of attack for litigation opposing new transmission lines.

“The first time FERC overturns a state after the state has said ‘no,’ once the state has held its own formal process and said ‘no’ either on the route or the need or the prudence of cost … that’s going to be litigated 16 ways from Sunday,” he said.

Still, Christie said he would approve the NOPR, though he said he wanted to hear from state regulators and consumer advocates.

“I question the purpose of fidelity to the IIJA in a NOPR that has what I think in many cases are unnecessarily burdensome requirements, but … I solicit comments on that,” Commissioner James Danly said.

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NERC Warns of Ongoing Extreme Weather Risks

The coming decade will be marked by “extraordinary reliability challenges and opportunities” amid rapid changes in the climate and the North American electric grid, NERC staff said while introducing the organization’s Long-Term Reliability Assessment (LTRA) on Thursday.

“Year after year, we’ve seen extreme weather leading to increased reliability events. … It’s clear that the bulk power system is impacted by extreme weather more than it ever has,” John Moura, NERC’s director of reliability assessment and performance analysis, said at a media event accompanying the report’s release. “So, as we transition our system so rapidly, it’s vitally important that we’re planning and operating a [BPS] that can be resilient to the extreme weather we’re seeing.”

NERC produces the LTRA every year in coordination with the regional entities to assess North American resource adequacy and identify trends, emerging, issues and potential risks during the coming 10 years. This year’s report found most of the continent as either high-risk — meaning energy shortfalls may occur at normal peak conditions in one or more years — or elevated, in which case reserves meet normal resource adequacy criteria but severe heat or cold could lead to shortfalls.

MISO, Ontario at High Risk

MISO and NPCC-Ontario led the high-risk areas, with projected shortfalls for each region exceeding 1,000 MW. Most urgent is the 1,300 MW in MISO, where NERC now expects the reserve margin to fall below the reference margin level beginning next year — a year earlier than the prediction from last year’s LTRA. Mark Olson, NERC’s manager of reliability assessments, explained in Thursday’s call that generation retirements in MISO are “outpacing the new resource additions, and not keeping up with resource adequacy criteria.”

Shortfalls are expected to begin in NPCC-Ontario as early as 2025, with the anticipated reserve margin (ARM) dropping below the reference margin level by 1,700 MW in that year and 2026, driven by “planned retirements and lengthy outages for nuclear units undergoing refurbishment.”

Five-year projected reserve (NERC) Content.jpgFive-year projected reserves for MISO (left) and NPCC. | NERC

 

Regarding the nuclear outages, NERC observed that Ontario Power Generation has proposed to extend the operation of Pickering Nuclear Generating Station, which is currently expected to retire in 2025, through September 2026. The LTRA’s ARM for NPCC-Ontario was calculated under the assumption this proposal would be approved by Canada’s Nuclear Safety Commission.

The last high-risk area is California. Although the state now seems set to avoid the shortfall that last year’s LTRA predicted would begin in 2026, thanks to added capacity, NERC noted it “remains dependent on electricity imports to manage periods of extreme electricity demand or low resource output.” A probability assessment for 2024 showed that while most months show a low risk of load loss and unserved energy in the state, August and September had high risks of more than two hours of load loss due to warm temperatures and “potentially volatile electricity demand.”

Olson said California’s Diablo Canyon nuclear plant was not included in the LTRA due to uncertainty around its continued operation, but that it “would certainly help alleviate risk.” The 2.2 GW plant was scheduled to close by 2025, but the state this year determined that its baseline contribution was essential for reliability, and the Department of Energy last month awarded PG&E $1.1 billion to help keep it in operation. (See DOE Grants PG&E $1B for Diablo Canyon Extension.)

Variable Generation a Continuing Concern

Areas at elevated risk include the U.S. Northwest and Southwest, SPP, Texas and New England. In those regions, capacity should be sufficient to meet normal peak demand; however, conditions under NERC’s 90/10 forecast — which has a 10% chance of being exceeded — could lead to outages.

Tier 1 and 2 planned resources (NERC) Content.jpgTier 1 and 2 planned resources projected through 2032. | NERC

For Texas, the report noted that “ERCOT’s winter peak load varies substantially … between the coldest temperatures of an average year and a more extreme year.” Although changes by state regulators, ERCOT and generator owners since the winter storm of February 2021 should reduce the risk of disruption, NERC said the state still has cause for concern.

The biggest risk for New England continues to be dependence on natural gas for electricity and the risk of gas supply bottlenecks due to increased heating demand in severe cold. The report reminded readers that stored backup fuels are “critical” to ensuring grid reliability.

WECC and SPP face risks due to high demand and variable output, highlighting an ongoing issue in the BPS. As in previous years, projections for planned resources for the next decade show that wind, solar and gas “are the overwhelmingly predominant generation types in the planning horizon.”

Michelle Bloodworth, CEO of coal industry advocate America’s Power, said in a press release that the increasing presence of weather-dependent resources in the electric grid is worrying. She called for utilities not to abandon conventional generation sources without a better understanding of how to maintain reliability.

“We remain deeply concerned that the grid is being forced to rely on less dependable electricity sources in the future because of coal retirements. We strongly urge the Federal Energy Regulatory Commission and grid operators to act as quickly as possible to value all reliability attributes,” Bloodworth said. “In addition, we urge utility commissioners to pause coal retirements until grid operators have identified and valued all reliability attributes.”