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November 16, 2024

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California Energy Commission Approves $2.9B Clean Transportation Plan

The California Energy Commission on Wednesday approved a broad investment plan for $2.9 billion in state clean-transportation funding through 2026, with most of the money allocated to charging infrastructure for light-, medium- and heavy-duty electric vehicles.

“I just want to acknowledge how transformational this plan is,” said Commissioner Patty Monahan, who led the effort. “In terms of the level of investment, it’s 30 times what our [Clean Transportation Program] budget was in 2019, so that’s just an eye-popping number, but I would say that it is commensurate with the level of ambition in the state.

“We are seeking to zero-out emissions from all sources of transportation in the next 15 to 25 years,” she continued. “Historically, I would say lack of investment by the auto and vehicle industry largely was the biggest obstacle to zeroing out emissions from transportation. Now I wouldn’t say that. Now it’s infrastructure, and we need to build out infrastructure in a way that’s really attentive to the needs of communities and ensures that people are not left behind.”

The Energy Commission’s funding plan mainly adheres to requirements imposed by the State Legislature in the two most recent state budget cycles, which dedicated a total of $10 billion to accelerate the state’s transition to zero-emission vehicles.

The plan includes $1.7 billion for medium- and heavy-duty ZEV infrastructure and $900 million for light-duty EV charging infrastructure.

The remaining $300 million will go to promote in-state ZEV manufacturing, hydrogen fueling stations, low- and zero-carbon fuels, workforce development, vehicle-to-grid integration, and emerging technologies in zero-emission planes, trains and ships.

Funding for the current fiscal year of more than $1 billion is guaranteed, but future years will require legislative appropriations. The CEC intends to distribute the funds through competitive grant solicitations and direct-funding agreements.

“CEC staff estimates the plan will result in 90,000 new EV chargers across the state, more than double the 80,000 chargers installed today,” the commission said in a news release. “Combined with funding from utilities and other programs, these investments are expected to ensure the state achieves its goal to deploy 250,000 chargers by 2025.”

CARB Funding

The commission’s charging infrastructure investment plan complements $2.6 billion in incentives for clean cars and trucks that the California Air Resources Board approved Nov. 17.

CARB’s funding included $2.2 billion in incentives for clean trucks, buses and offroad equipment; $326 million for the purchase of zero-emission light-duty vehicles; and $55 million for clean mobility projects, such as community shuttles and bike-share programs. (See CARB Approves $2.6B in Clean Vehicle Incentives.)

Together, the $5.5 billion in ZEV funding is intended to help the state reach its decarbonization targets: All new passenger cars sold in-state must be emissions-free by 2035; all new medium- and heavy-duty vehicles sold must be ZEVs by 2045; and greenhouse gas emissions must be 40% below 1990 levels by 2030.

A series of bills, regulations and executive orders established the mandates, mostly in the past five years.

The CEC estimates the state will need to install 1.2 million light-duty EV chargers and 157,000 medium- and heavy-duty EV chargers over the next decade if it hopes to achieve its goals.

CPUC Actions

In support of EV charging needs, the California Public Utilities Commission has authorized the state’s three large investor-owned utilities to install thousands of EV chargers in recent years. In August 2020, for example, the CPUC approved Southern California Edison’s plan to install 38,000 charging ports at a cost of $437 million.

Last month it approved a $1 billion, five-year effort to provide charging infrastructure for EVs. Approximately 70% of the funds will be dedicated to charging medium- and heavy-duty vehicles; the rest will be for light-duty EV charging at or near multifamily housing complexes, with priority given to investments in low-income, underserved and tribal communities.

On Thursday, the CPUC authorized Pacific Gas and Electric to install 2,822 light-duty Level 2 chargers and direct-current fast chargers at multifamily housing complexes, workplaces and public-destination sites, “which typically face the biggest barriers to EV charging and transportation electrification,” the commission said in a news release.

The first phase of the program will run from 2023 to 2025 with $52 million in funding. PG&E must spend at least 65% of the funds in underserved communities, the CPUC said.

In a separate move Thursday meant to accelerate charger installations, the CPUC established a 125-day timeline for utilities to connect customers with EV infrastructure to the grid, “referred to as energizing new EV electric load,” the news release said. The timeline includes 25 days to obtain local permits.

The CPUC also required the utilities to make the energization process clearer to customers.

“Today’s energization decision takes big steps to speed up the process of connecting new EV chargers to the electric grid and to make sure utilities provide customers information about how that process works,” Commissioner Clifford Rechtschaffen said in a statement following the vote.

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APS Can Adopt Flowgate Methodology, FERC Rules

FERC on Thursday approved Arizona Public Service’s proposal to begin using the flowgate methodology to calculate available transfer capability (ATC) within its transmission system.

In approving the change, the commission rejected a protest by the Southwest Public Power Agency (SPPA), which complained that APS did not sufficiently explain the impact the move might have on transmission customers and other transmission facility owners in the region.

The commission also denied APS’s request to waive a requirement that the utility continue to post total transfer capability (TTC) on its Open Access Same Time Information System (OASIS) after transitioning to the new methodology (ER22-2476).

Provider Discretion

The APS proceeding has its roots in FERC Order 890, which sought to “increase nondiscriminatory access to the grid by eliminating the wide discretion that transmission providers currently have in calculating” ATC. The order required utilities to develop consistent methodologies for performing the calculation and to publish those methodologies for review.

Issued in 2007, Order 890 revised the pro forma Open Access Transmission Tariff (OATT) to require that transmission providers clearly identify the methodology and mathematical algorithms used “to calculate firm and non-firm ATC (and [available flowgate capability] AFC, if applicable) for its scheduling, operating and planning horizons.”

APS sought to revise its OATT by replacing the rated system path methodology with the flowgate methodology to calculate ATC across the three horizons.

According to NERC, the flowgate methodology identifies key transmission facilities as flowgates, a mathematical construct used to analyze the impact of power flows on the bulk electric system.

Under the method, NERC explains, “total flowgate capabilities (TFC) are determined based on facility ratings and voltage and stability limits. The impacts of existing transmission commitments (ETC) are determined by simulation. The impacts of ETC, capacity benefit margin (CBM) and transmission reliability margin (TRM) are subtracted from the total flowgate capability, and postbacks and counterflows are added, to determine the available flowgate capability (AFC) value for that flowgate.”

In Thursday’s order, the commission explained that “In order to have consistent posting of ATC, TTC, capacity benefit margin, and transmission reliability margin values on OASIS, the commission directed public utilities working through NERC to develop the available transmission system capability reliability standard, a rule to convert available flowgate capability values into ATC values.” The commission also affirmed that providers relying on the flowgate methodology are required to convert their AFC values to ATC and post the associated calculations on their OASIS and web sites.

The commission noted that, in response to a deficiency letter, APS had provided the required documentation for its various calculations, including those related to AFC and ATC — as well as its process for converting AFC to ATC.

But the proposed changes prompted a protest by SPPA. While claiming no objection to the use of the flowgate methodology, the power agency said it would be more “sensible” for all entities with component facilities on the APS system to adopt the methodology together.

SPPA also contended that APS’ filing with FERC lacked key details about the utility’s implementation of the methodology and that APS failed to inform the commission, transmission owners and customers how the methodology would affect transmission allocation and scheduling.

SPPA additionally argued that APS failed to explain how the new methodology would affect other transmission facility owners and transmission customers, particularly those in the Palo Verde area. It asked FERC to reject the changes or suspend APS’ filing for five months to either set the issue for settlement judge procedures or a technical conference.

The commission acknowledged SPPA’s concerns about transitioning to the flowgate methodology but agreed with APS that Order 890 gives transmission providers discretion in choosing their ATC calculation methodology.

The commission found that SPPA had “not identified any specific concerns with APS’ proposed OATT revisions,” and that APS had “appropriately revised its OATT to reflect the transition consistent with FERC requirements, finding the revisions to be just and reasonable.”

FERC also rejected SPPA’s requests to suspend the filing or convene settlement judge procedures or a technical conference, saying “there are no issues of material fact that would warrant a hearing.”

‘Industry-wide Consistency’

Thursday’s ruling also denied APS’s request for waiver of the requirement to post TTC values on its OASIS site. The utility had argued that while Order 890 references TTC as a component of ATC, TTC is not actually a component of ATC for providers relying on the flowgate methodology, who instead use TFC in their calculations. APS said the requirement to post TTC on OASIS would be a “burdensome, manual process” with little customer value.

In denying the waver, the commission said Order 890 “addressed the potential for undue discrimination by requiring industry-wide consistency and transparency of all components of the ATC calculation methodology and certain definitions, data and modeling assumptions. The commission [in Order 890] noted its concern that the lack of consistent, industry-wide ATC calculation standards poses a threat to the reliable operation of the bulk-power system, particularly because a transmission provider may not know its neighbors’ system conditions and how that might affect its own ATC values.”

The commission also found that APS erred in citing previous FERC cases, specifically 2009 rulings involving SPP (127 FERC ¶ 61,207) and Midwest ISO (126 FERC ¶ 61,107) to support its argument. It noted that the applicant in SPP requested only a temporary waiver of the requirement to post ATC, TTC, CBM and TRM values on its OASIS site. In Midwest ISO, the commission granted MISO a waiver of the requirement to post certain ATC components on its OASIS site for paths internal to the MISO system, but not for other transmission service requests, the commission added.

“APS has also failed to adequately explain how requiring APS to convert TFC to TTC would impose significant burdens on its staff,” the commission determined.

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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.