New York transmission owners have proposed tariff amendments that would clarify their ability to exercise a right of first refusal (ROFR) for public policy transmission (PPT) network upgrade facility (NUF) upgrades identified in the interconnection study process.
FERC in March approved tariff changes that confirmed TOs could exercise a ROFR for upgrades that are proposed by other developers, but they lacked provisions on whether this applied to upgrades identified later by NYISO as necessary to reliably interconnect a project (EL22-2-001). (See FERC Approves ROFR for NY Transmission Upgrades.)
The Operating Committee on Thursday recommended that the Management Committee and Board of Directors authorize NYISO to file the proposed revisions, presented at the meeting by Stu Caplan, partner at Troutman Pepper, which represents the eight TOs.
In a statement to RTO Insider, Caplan said the proposed revisions would “merely apply a similar mechanism to upgrades that are identified in the interconnection process for the public policy transmission projects that are selected by the NYISO board.”
The revisions are the “logical extension of the process FERC approved in March of this year for upgrades identified at the project proposal stage,” he said.
Caplan told stakeholders that the proposal would replace a bilateral process that lacks certainty and timelines, provide for a transparent process that closely replicates approved standards, and define the ISO’s role in identifying which of the NUF components might qualify as an “upgrade” subject to a ROFR.
“It is the only current solicitation for a public policy transmission projects, and the first project that may result in the identification of upgrades in the interconnection process for a public policy transmission project,” Caplan said.
During Wednesday’s Business Issues Committee meeting — where the proposal was also presented — Howard Fromer, who represents the Bayonne Energy Center, asked whether NYISO had expressed support for the changes.
Caplan answered that the ISO has said the TOs are “free to carry this forward as a TO-led effort.”
This response was followed up by NYISO attorney Brian Hodgdon, who said that “nothing has jumped out as an immediate concern” to the ISO.
The proposed amendments now move to the Nov. 30 MC meeting for approval.
Winter Capacity Assessment
NYISO expects sufficient capacity margins for this winter but anticipates continued year-to-year declines as more fossil fuel generators retire.
The ISO told stakeholders that that they expect a total of 477 MW worth of generation to be deactivated and a total of 672 MW of new generation to be added during the upcoming seasonal assessment period.
SRIS Scopes Amended
The OC unanimously approved revisions to the system reliability impact study (SRIS) scopes for 35 generation projects, which the ISO identified as possessing evaluations that could either be removed, were redundant or could be conducted later.
NYISO had recommended that these previously OC-approved SRIS scopes be narrowed to expedite interconnection processes and streamline transmission studies (See NYISO Identifies 35 Projects for Narrowed SRIS Scope.)
Intermittent Resources Update
For the first time, NYISO shared the total nameplate value of installed intermittent power resources in the New York Control Area:
Land-based wind: 2,191 MW
Behind-the-meter solar: 4,123 MW
Front-of-the-meter solar: 74 MW
NYISO promised to expand this list to more intermittent resources, such as OSW, as they are installed in greater amounts, and promised to consider including battery storage in the future.
BIC & OC Elections
NYISO stakeholders unanimously elected Scott Leuthauser of Hydro Quebec Energy Services and Greg Yozzo of Central Hudson Gas & Electric as the new vice chairs of the BIC and OC, respectively.
[Editor’s Note: An earlier version of this article incorrectly attributed Brian Hodgdon’s quote to Brian Hurysz.]
FERC last week partially granted three complaints by SPP members alleging
the grid operator violated its tariff’s terms and
generator interconnection agreements (GIAs)
and engaged in unduly discriminatory and
preferential practices related to its revenue
crediting process under Attachment Z2 (EL19-75, EL19-96, EL19-93).
The commission, however, rejected a similar complaint from Oklahoma Gas & Electric (EL19-77).
EDF Renewables, Enel Green Power North America, NextEra Energy Resources and Southern Power filed a joint complaint in May 2019 under three sections of the Federal Power Act. They argued that they are entitled to revenue credits associated with transmission service that could not have been provided but for the use of network upgrades for which they paid.
Under Attachment Z2, SPP transmission customers that fund network upgrades can be reimbursed through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrades. FERC in 2020 approved the RTO’s request to replace revenue credits with incremental long-term congestion rights. (See FERC Approves SPP’s 2nd Go at Dropping Z2 Credits.)
The developers argued their companies had together funded, through their respective GIAs, almost $95 million in network upgrades owned by SPP transmission owners on the RTO’s system. The first of the upgrades became operational in 2010, they said, but SPP took until 2016 to add the software required for Z2, collecting charges for service that relied on network upgrades.
In their complaint, the developers pointed out that FERC said in a 2016 response to an SPP waiver request that the grid operator had already determined that they are eligible for revenue credits associated with their funded creditable upgrades.
FERC agreed with the complainants that SPP had violated the tariff, GIAs and the filed-rate doctrine, but it denied the remaining allegations. It also declined to set the proceeding for hearing and settlement judge procedures and to grant the developers’ requested relief, that being the full revenue credits and interest for transmission service SPP provided over the creditable upgrades since 2010. The commission said the underlying facts were “materially the same” as a D.C. Circuit Court of Appeals ruling in an OG&E complaint against SPP.
“We believe that exercising our authority under [Section 309 of the Federal Power Act] under these circumstances would be inappropriate for the same reasons,” FERC said.
FERC Commissioner James Danly agreed in a concurring statement to all four orders, writing that “FPA Section 309 cannot be invoked to provide equitable exceptions or retroactive modifications to the filed rate. … It is not a matter of discretion.”
The commission used the same arguments and reached the same decisions in complaints filed in September 2019 by Cimarron Windpower II.
It relied on some of those arguments in accepting and rejecting parts of Western Farmers Electric Cooperative’s August 2019 request that it be able to recover and retain revenue credits that it said it was entitled to under its network integration transmission service agreement and Attachment Z2. FERC found the attachment does not guarantee full cost recovery for network upgrades “but merely provides the opportunity to recover such costs.”
FERC rejected OG&E’s complaint, filed in May 2019, that being required to refund revenue credits related to the use of OG&E’s transmission facilities would violate Attachment Z2, the filed-rate doctrine, and the sponsored upgrade agreement between OG&E and SPP. The utility had also argued SPP must pay restitution if it required the revenue credits be refunded.
The commission responded by saying the upgrade agreement does not supersede the tariff, as OG&E suggested, because the agreement expressly incorporates the tariff. SPP does not have the revenue credits to provide as restitution to OG&E; those funds are with the transmission customers, who cannot be invoiced for credit payment obligations because of the tariff’s one-year billing adjustment limitation, FERC said.
SPP had been trying to replace Z2 credits since 2016, when controversy arose after the grid operator identified eight years of retroactive credits and obligations that had to be resettled after staff failed to apply credits. (See SPP Invoices Lead to Confusion on Z2 Payments.)
The commission granted the grid operator a retroactive waiver of its tariff so that it could invoice transmission service customers for Z2 credit payment obligations dating back to 2008. However, it reversed course in March 2019, saying its original decision was prohibited by the filed-rate doctrine and the rule against retroactive ratemaking.
FERC in March 2019 issued a voluntary remand of the waiver following a D.C. Circuit ruling in a separate waiver case involving PJM. The court ruled in 2021 that the commission acted correctly in reversing the retroactive waiver. (See DC Circuit Upholds FERC Ruling on SPP Z2 Saga.)
A new study by National Grid suggests that states and utilities must move swiftly to equip the grid to support the travel needs of what’s expected to be an explosively growing segment of electric vehicles.
The utility (NYSE:NCG) this month offered an assessment of EV charger infrastructure needs, releasing a report on what the future might look like across its service area in New York and Massachusetts.
The report draws a buildout model of 71 charging plazas from westernmost New York to Cape Cod and forecasts they are each likely to have a peak demand of up to 5 MW by the early 2030s and up to 10 MW by the early 2040s.
As early as 2030, some of these sites will exceed delivery limits of the low-voltage distribution grid, the report predicted. But the main east-west and north-south routes where the 71 sites were envisioned overlap in many places with the high-voltage transmission system, the report said.
With bans on the sale of gas-powered light vehicles arriving in 2035, and with transmission and interconnection upgrades happening at a slow pace, the report flags the need to start building out EV charging infrastructure now.
Other factors will exacerbate the need, said Dave Mullaney of RMI, a nonprofit advocate for sustainability that contributed to the study.
“The Inflation Reduction Act will close the cost gap between diesel and electric trucks and create a surge of demand from buyers and investment from suppliers in the near future,” he said in a news release accompanying the report. “The biggest challenge to deploying those electric trucks will be finding the power to charge them. This study takes the first steps to overcoming that barrier and serves as a roadmap for the rest of the country to follow.”
The ratio of light- and heavy-duty battery-electric vehicles using a charging plaza will factor into its actual power needs, the report’s authors noted. Unknown factors such as the adoption of other zero-emission technologies also will determine how much charging capacity is needed.
The report notes that some projections show charging plazas drawing as much power as an outdoor pro sports stadium or small town when 20 or more fast chargers are in use simultaneously. The highest-demand sites could approach 40 MW of peak demand, as much as a major industrial site.
On-route charging will be part of an ecosystem to support electrical vehicles, along with chargers at homes, workplaces and truck depots. The National Grid report focuses on the site-specific impact of these highway charging stations rather than the regional, statewide or grid impacts examined in other studies.
The report offered six major takeaways:
A typical site will require more than 20 fast chargers.
Light-duty EVs will increase the power demand in the near-term but medium- and heavy-duty EVs will drive the increase in the longer term.
Managed charging and load management offer potential benefits, but many highway charging plazas will likely still require transmission interconnection.
A charging station’s proximity to transmission lines will drastically impact its construction cost and timeline and should receive the same degree of consideration as traffic volume, land availability and expected utilization in the siting process.
Any new electric infrastructure upgrade that is required should be scalable and suited to long-term needs; this will limit future duplication and cost.
Planning must start now for transmission and interconnections, because they can take four to eight years to complete while a new charger can be installed in a matter of months.
No Headroom
There is no way around transmission upgrades if the EV transition happens as envisioned, the report adds: The electrical grid as it exists does not have headroom for highway charging plazas.
And highway corridor charging is a key component of the EV transition. It will reduce range anxiety for drivers of light vehicles; supplement or replace depot charging for medium-duty trucks; and be indispensable for regional and long-haul operation of heavy-duty trucks, which have long and variable daily duty cycles.
To project the charging needs of light-duty vehicles, the study drew from more than 2.5 years of usage data at 3,000-plus direct-current fast chargers nationwide. Since no comparable data exist for large commercial trucks running on battery power, the study assumed they would operate the way internal-combustion trucks do today.
The authors also noted that the study did not factor in the negative impacts of cold weather on duration of battery charge, which might boost the demand for electricity, or the possible adoption of fuel cell technology in medium- and heavy-duty trucks, which might decrease power demand.
The study also did not adjust for holiday traffic or other limited circumstances when calculating peak demand.
An underlying theme in the report is that utilities such as National Grid should have a greater and more proactive role in planning the EV ecosystem, rather than assuming their historically reactive stance.
In the news release, National Grid’s chief operating officer for New York Electric, Brian Gemmell, said: “This kind of holistic, long-term infrastructure planning will be critical to delivering a clean energy transition as efficiently as possible. We have a responsibility to make smart investments that get it right the first time and to make sure the electricity is there when drivers need it. This study will help us do that.”
The PJM Markets and Reliability Committee endorsed an RTO-sponsored package to standardize variable operations and maintenance costs, with nearly 90% sector-weighted support.
An alternative measure from Constellation Energy — which would have removed nuclear unit refueling as VOM — did not receive a vote during Wednesday’s meeting. (See “Two Proposals Remain on Variable Operations and Maintenance Costs,” PJM MRC Briefs: Oct. 24, 2022.)
If accepted by the Members Committee, the language would create default adders for minor maintenance and operating costs as an alternative to generators submitting unit-specific information, and provide definitions of major maintenance and minor maintenance for more clarity on which costs fall into each.
The default adders would be calculated based on historical maintenance values provided to PJM and would be adjusted annually using the Handy-Whitman Index.
PJM accepted a friendly amendment suggested by Adrien Ford of Old Dominion Electric Cooperative to maintain the status quo for the submission deadline, rather than moving it to March as was originally written in the proposal when it was believed the RTO and the Independent Market Monitor would be reviewing submissions in succession rather than parallel.
Constellation’s Jason Barker said the company is in agreement with PJM on the key points of the VOM measure, with the exception of maintenance unique to nuclear units during planned outages, which he said can be scheduled up to three years in advance and does not vary with run time or number of starts.
Monitor Joseph Bowring said the costs of major maintenance shouldn’t be included in energy offers, and called the determination from PJM and FERC to do so a mistake, but he disagreed with the notion that nuclear generation should be treated differently from other resources.
Paul Sotkiewicz of E-Cubed Policy Associates said many resource types have the sort of time-based expenses Barker outlined and asked if he would accept a friendly amendment to expand the nuclear carveout to all time-dependent maintenance. Barker responded that the amendment was too large of a change to make on the fly.
The topic isn’t a “make-or-break issue for the nuclear industry,” said Alex Stern,= of Public Service Electric and Gas, but it does make the economics of operating a carbon-free resource harder.
“The country and the region have been spending a lot of time trying to figure out how to preserve zero-emissions generation like nuclear exactly because we need baseload generation as we move toward this changing generation mix, Stern said. “So there’s been a lot of customer expense being thrown at — properly so — trying to preserve reliable generation from nuclear. And I think that the concern here that Constellation is raising is that we’re throwing money at trying to make nuclear economic, but we’re going to take a step here that’s incorrectly putting costs on nuclear.”
Bowring responded that the PJM proposal does not impose any costs on nuclear or make any changes to the economics or margins for resource owners. Rather, it changes the markets to which the costs are assigned, not what they are. “For example, the Constellation proposal does not change the capacity market offer caps for nuclear units in any way. There is no good reason to exempt nuclear units from the rules that apply to all other units.”
Stakeholders Approve Quick Fix for Capacity Replacement Transactions
The committee voted to approve an issue charge and solution under PJM’s quick-fix rules to allow generators to replace capacity sold in a Base Residual Auction in years where there is only one Incremental Auction. The new language was approved by acclamation with two objections.
Michael Borgatti of Gabel Associates, representing Eagle Point Power Generation, said the current compressed timeline, in which there is one instead of three IAs each year, limits the opportunities for generators to engage in replacement resource transactions.
The revisions allow for capacity to be replaced if a “financially and physically firm commitment to an external sale of its capacity for the entire delivery year [has been] demonstrated with supporting evidence.” The changes are limited to currently scheduled delivery years during which there is only one IA scheduled.
Stakeholders expressed some reticence about the use of quick-fix rules to make the change, noting the possibility of those with objections not having adequate time to make their voices heard, but Borgotti said there is limited time to make manual revisions in time for the next auction date.
Bowring pointed out that for any resource facing the referenced issue of wanting to sell capacity outside PJM, there are defined steps in the tariff and in the manuals.
“This proposal provides an incentive to ignore the tariff rules about how to qualify for a must-offer exemption in the capacity market, to offer and clear and then to later withdraw the commitment to sell the capacity. That affects the market prices received by all other market participants,” Bowring said. “Approval of this proposal as a quick fix is effectively saying that any market participant that does not like the rules can come to the MRC at the last second and get the rules changed in their favor.”
Coal Resource Permitted to Enter Maximum Emergency for Fuel Shortages
Stakeholders also approved a manual change to allow coal generators to elect to enter into maximum emergency should their fuel stores fall below 10 days, effectively exempting them from the must-offer requirement while they rebuild their inventories. Facility owners can only make the voluntary determination to seek maximum emergency status from PJM should the fuel shortage be outside of their control and not the result of economic decisions.
PJM’s Chris Pilong said examples of legitimate issues beyond a facility operator’s control are mine fires, floods and tight supply chains. So long as those events are reported to PJM, it can examine whether permitting maximum emergency is warranted. The revisions passed by acclamation with no objections and one abstention. (See PJM Considers Changes to Max Emergency Status for Coal Plants.)
A facility cannot be granted maximum emergency status if PJM has issued a hot or cold weather alert or conservative operations, and the RTO can deny a request for any reason. A generator can remain under maximum emergency until it has reached 21 days worth of fuel inventory, if the owner elects to terminate the condition or if PJM issues one of the aforementioned conditions.
Bowring said there are legitimate reliability concerns related to coal inventories, but the responsibility of taking on and mitigating that risk should fall on the facility owners, not PJM.
“PJM is proposing a short-term fix that is unnecessary and is inconsistent with PJM’s stated objective of providing incentives for flexibility,” he said.
Susan Bruce, representing the PJM Industrial Customer Coalition, questioned if the markets are realizing the full benefits of coal resources if their inventories can’t be guaranteed and said there should be an oversight role to ensure owners are not managing inventories to be economically or physically withholding.
Because the changes were limited to manual revisions, only MRC approval was required, and the changes go into effect immediately.
TCPF Adjustments Permitted for Issues with Ongoing Solution
Stakeholders approved allowing PJM to modify the transmission constraint penalty factor (TCPF) in situations where the issues causing congestion are being addressed by in-progress Regional Transmission Expansion Plan projects. The revisions to the manual, tariff and Operating Agreement were passed by acclamation with one objection.
PJM’s Susan Kenney said the purpose of the penalty factor is to incentivize supply or load to address constraints through short-term solutions and develop long-term investments. When such investments are already underway and there are not feasible short-term solutions, applying the penalty factor may not make sense, she said.
Kenney noted the spark for taking a look at the functioning of the penalty factor came after one of three transmission lines into Virginia’s Northern Neck peninsula was put on outage for a planned upgrade in 2020.
The outage caused congestion into the peninsula, which pushed the TCPF to its default of $2,000/MWh in the real-time energy market. Because the completion of the upgrades would resolve the issue and it wouldn’t be possible for new generation to be added prior to the work being finished, PJM successfully argued to FERC that the design of the penalty factor created “unjust and unreasonable energy market rates” for consumers. (See FERC Approves Pause of PJM Tx Constraint Penalty Factor in Va.)
A second proposal from the IMM would have broadened the criteria for adjusting the TCPF and used a different methodology to determine when to do so, but it received limited support and did not advance from the Energy Price Formation Senior Task Force. Bowring argued during the MRC’s first read of the PJM package that the proposal would allow the RTO to subjectively determine penalty factors and does not address why penalty factors are triggered so often. (See “MRC Discusses Transmission Constraint Penalty Factor Revisions,” PJM MRC Briefs: Oct. 24, 2022.)
1st Read on Proposal to Allow Flexibility for Market Participation During Defaults
PJM presented a first read of a proposal to grant flexibility for parties to continue participating in markets after a default under certain circumstances. The OA currently uses conflicting language regarding market participant involvement during a default, with some sections using “shall” and others saying “PJM may limit,” though Associate General Counsel Colleen Hicks said the OA generally uses mandatory language.
The factors that could warrant allowing continued market involvement are: grid reliability, the ability to generate revenues in the future and the ability to post collateral. A fourth consideration recognizes that certain transmission customers cannot have their service terminated without FERC approval and acts more as a clarification in the package under consideration, Hicks said. The proposal would also modify the tariff with reciprocal provisions.
Other Committee Actions
The MRC also passed with no objections:
proposed governing document changes to prohibit critical natural gas infrastructure from participating in demand response or price-responsive demand programs. The language was the same as the first read during the Oct. 24 MRC meeting. (See “Reworked Language on Critical Gas Infrastructure Participation in Demand Response Presented,” PJM MRC Briefs: Oct. 24, 2022.)
proposed tariff revisions that would require that financial transmission rights bilateral agreements to be reported to PJM with certain data within 48 hours of their execution. The primary economic term data that must be reported alongside the agreement includes the FTR start/end, quantity, source and price.
An anticipated vote on packages to create a “circuit breaker” that would limit extended price increases was deferred until the next MRC meeting to give sponsors time to work on the possibility of a compromise package. (See “Support for Circuit Breaker Remains Mixed,” PJM MRC Briefs: Oct. 24, 2022.)
PJM opened a poll on Friday to gauge support for dueling proposals to revise the rules for load behind-the-meter (BTM) of a co-located generator.
The two packages, the first jointly drafted by Constellation Energy and Brookfield Renewable Partners and the second from the Independent Market Monitor, largely differ in how they would account for the power being consumed by the load when determining how much capacity the generator can offer into the PJM markets. Under Constellation’s proposal, the facility’s capacity offer would not be reduced because the energy would remain available for PJM to call upon when needed, with the BTM load curtailed.
The IMM, however, argues that the power consumed by behind-the-meter load should not be counted toward the generator’s capacity offer. Its package would subtract the net peak load from the unit’s installed capacity.
Constellation Energy displays the envisioned configuration of co-located load, which would not be directly interconnected with the PJM grid. | Constellation Energy
Speaking during a Nov. 17 Market Implementation Committee special session to discuss the packages prior to the opening of the poll, Constellation’s Jason Barker said his company’s language would expand customer choice by providing options for companies whose loads are curtailable and don’t require the full services of the transmission grid.
“What we have seen is we have new large commercial customers that are choosing to locate highly interruptible loads behind-the-meter of generation resources, both to reduce their costs and ensure physical supply of carbon-free power,” he said.
Since the amount of power produced and consumed would remain the same regardless of whether the load is placed behind or in front of the generator’s meter, Barker argued that there would be no impact on prices. The arrangement would also allow for the behind-the-meter to rapidly be curtailed and that power shifted to PJM when LMPs exceed the facility’s market offer, or when called upon by the RTO.
“The response time is the same as a [synchronized] reserve product. And I highlight for all of the folks on the call that we have many, many, many capacity resources that provide capacity commitments today for which their energy is callable not in minutes, but in hours or in some cases even days. So this is a superior product to most of the capacity commitments you’re getting in that respect,” he said.
PJM’s Independent Market Monitor Joe Bowring told the MIC that even if capacity prices remain unchanged, allowing generators to sell a portion of their energy to behind-the-meter customers while keeping that output in the capacity market would effectively reduce the amount available to PJM and send incorrect incentives to the markets about the amount of additional capacity needed to maintain reliability.
“The Constellation proposal is to sell the capacity twice, once to the behind-the-generator load and once to PJM customers,” he said
“What this is really doing when you think about it is taking a resource which is providing low-cost energy, 8760 [hours a year], and providing energy for a small number of hours a year. … That will create potentially very significant issues, depending on the level of the megawatt hours taken off the system,” he said. “Removal of this level of energy inputs at key points in the transmission system that was designed around these units would have extremely significant impacts on the grid. PJM should provide analysis of the impacts. PJM’s analyses to date do not address the real issues, including the combined impact of multiple such requests.”
Bowring said the rules need to be finalized before investments in the behind-the-meter load configurations under discussion start coming in, calling Constellation’s proposal a “sea change.”
To date, PJM has received requests to add 4,469 MW of co-located load behind-the-meter of 18 existing generation units, with a combined installed capacity of 15,800 MW. Of the new load requests, 3,906 MW is proposed to be configured to receive power from the generator without being interconnected to the PJM grid.
“The IMM’s approximate calculations show that removal of 20,000 MW of low-cost energy could raise energy costs for other customers by billions. There is no indication that the referenced loads would join PJM in the absence of the proposal. If the loads did join PJM, they should follow the same rules as all other load,” Bowring said. “There are current provisions for interruptible load that would address the stated goals.”
Studies have been completed for 864 MW of the co-located load requests, which are being treated as amendments to the generators’ existing interconnection service agreements under the existing rules, said Augustine Caven, PJM’s manager of infrastructure coordination.
Jurisdiction Over Co-located Load Disputed
The MIC also debated the issue of whether co-located load falls under federal or state regulation at the Nov. 17 meeting. Several stakeholders argued that such loads receive the benefit of synchronized reserve, regulation and ancillary services through the generator’s interconnection to the PJM grid, even if the load is not directly interconnected itself.
PJM Senior Counsel Chen Lu, who presented the RTO’s perspective that co-located load is state regulated, said during the Oct. 13 MIC special meeting that the issue is similar to the question of power consumed by generators.
“To me this really isn’t that different from the station power cases that FERC has decided. And in those cases when a generator is receiving station power, they may still be benefitting from the grid. But FERC has explained since those are not sales for resale, they weren’t FERC jurisdictional and those are ultimately state jurisdictional retail sales. And so just by virtue of the fact that they may have some benefit from the grid, doesn’t necessarily make it FERC jurisdictional,” he said.
PJM Director of Market Settlements Initiatives Lisa Morelli said a logical extension of requiring co-located load to pay for services such as synchronized reserve would be that generators could also then be required to pay that as well.
“I think if you continue pulling that thread, that is where you would land,” she said.
The Bonneville Power Administration last week proposed to hold key power and transmission rates mostly flat over its next two-year rate cycle — and said it might cut rates this year — in light of a “strong” financial performance over the past 12 months.
The federal power marketing agency said steady rates will provide a “buffer against market volatility” for its customers, which largely consist of publicly owned utilities across the Pacific Northwest. Those utilities serve residents with some of the cheapest power in the U.S., most of which is generated by the region’s extensive network of hydroelectric dams.
“This is one of those bountiful years where all the elements and timing came together in such a manner that we can consider staving off inflation for another two years by keeping rates flat for our power and transmission customers,” BPA Administrator John Hairston said in an announcement Friday.
The agency said it earned $964 million in net revenues during fiscal year 2022, far outdistancing its target of $172 million.
“Each quarter, we have signaled our expectations that Power and Transmission were expected to have a solid year, and I’m happy to report that was in fact the case, with both business lines significantly beating net revenue targets,” Marcus Harris, BPA’s acting CFO said in a press release Thursday.
During its quarterly business review on Wednesday, the agency said it would consider using its financial reserves to reduce rates in FY 2023, which began Oct. 1.
Friday’s announcement kicked off the formal process for BPA’s power rate case (BP-24) and transmission rate proceeding (TC-24) for fiscal years 2024/25 (Oct. 1, 2023 to Sept. 30, 2025). Agency staff will officially publish initial proposals for the new power and transmission rates on Dec. 2, the same day as a pre-hearing conference to discuss the plans, but both plans are already available online. The proposed rates were the subject of a series of stakeholder meetings held this summer.
BPA’s power rate schedule consists of four categories of primary rates for federal energy sales, including the:
Priority Firm Power Rate (PF-24), or “Tier 1,” which applies to firm power sales to BPA’s public body, cooperative and federal agency customers;
New Resource Firm Power Rate (NR-24), which applies to firm sales to investor-owned utilities and public customers serving new large, single loads. (BPA is forecasting no sales at this rate during the BP-24 period);
Industrial Firm Power Rate (IF-24), which is applicable to firm power sales to Direct Service Industrial customers; and
Firm Power and Surplus Products and Services Rate (FPS-24), applicable to “sales of various surplus power products and surplus transmission capacity for use inside and outside the Pacific Northwest.”
Tier 1 “non-slice” contracts represent the majority of BPA’s power sales. “Non-slice” refers to a type of contract in which the customer is guaranteed a specified volume of energy regardless of conditions on the hydro system; in contrast, total volumes delivered to “slice” customers can vary based on availability.
In a notice filed in the Federal Register on Friday, BPA said non-slice rates will remain flat at an average rate of just under $35/MWh. But when slice rates are considered, average Tier 1 prices should actually decline slightly, according to the notice.
“The individual experience — slight increase/decrease/flat — of customer utilities will vary based on what products they use and the ways in which they use them,” BPA spokesperson Kevin Wingert told RTO Insider in an email.
In the notice filed Friday, BPA said it expects to sell power to only one industrial customer at the industrial rate over 2024/25, but that customer can expect to see significantly higher costs during the most energy-constrained months, with December prices rising from $51.99/MWh to $63.40/MWh, and August rising from $49.10/MWh to $73.29/MWh. That is in part a reflection of changing expectations for river flow patterns in the Northwest — as well as summer cooling needs — caused by climate change.
BPA’s proposal would extend current transmission rates unchanged into FY 2024/25, with “main grid” and “secondary system” — or lower-voltage — charges remaining at $0.0774/mile and $0.76/mile, respectively.
The agency operates about 15,000 miles of transmission, about 75% of the system in the Northwest.
The U.S. Department of Energy said Monday it will award Pacific Gas and Electric’s Diablo Canyon nuclear power plant $1.1 billion in first-round funding from the Civil Nuclear Credit Program, established last year to support the continued operation of nuclear plants at risk of closing for economic reasons.
Diablo Canyon, the last nuclear plant in California, had been scheduled to close in stages in 2024 and 2025, but this year the state deemed its 2.2 GW of baseline power essential for reliability as CAISO faces continuing summer shortfalls.
“This investment creates a path forward for a limited-term extension of the Diablo Canyon Power Plant to support reliability statewide and provide an onramp for more clean energy projects to come online,” Gov. Gavin Newsom said in a news release. “I thank the Biden-Harris Administration for this critical support.”
Newsom’s office had asked DOE in May to change the eligibility criteria for the Civil Nuclear Credit Program, or CNC, which was created last year as part of the $1.2 trillion Infrastructure Investment and Jobs Act.
The department said in April that CNC funding was only for nuclear plants that do not recover more than half their costs from ratepayers. PG&E recovers nearly all its Diablo Canyon costs from customers under rate cases approved by the California Public Utilities Commission.
Newsom’s office asked DOE to exclude the cost-of-service requirement to allow Diablo Canyon to qualify for the federal funds. The plant provides 8.5% of in-state generation, which will be needed as the state tries to switch to 100% clean energy by 2045, the governor’s office said.
The transition to renewables has exacerbated strained grid conditions in California. CAISO declared energy emergencies during heatwaves the past three summers, as solar power ramped down in the evenings, but air conditioning demand remained high. It said it could face similar shortfalls this summer and beyond.
On June 30, DOE announced it was making the changes requested by Newsom’s office “given the request’s potential applicability to reactors nationwide.”
“This change affects the eligibility of reactors who may apply in the first round of awards,” the department’s Office of Nuclear Energy said in a statement.
Newsom signed a budget trailer bill in June that allocated $75 million toward keeping the plant open, and in September he signed a bill granting PG&E a $1.4 billion forgivable loan to keep Diablo Canyon operating five years beyond its scheduled retirement. The measure, Senate Bill 846, told PG&E to seek federal funds to offset the loan and lower customer costs if Diablo Canyon’s license was renewed.
PG&E filed its application for federal funding on Sept. 2. On Oct. 31, the utility said it had formally applied to the Nuclear Regulatory Commission to renew the plant’s license and postpone its decommissioning.
The moves reversed courses for the state and PG&E.
The utility had been planning to shut down Diablo Canyon since 2016, when it signed an agreement with environmental, labor and anti-nuclear groups to close the plant on the state’s Central Coast rather than invest billions of dollars in environmental and safety upgrades.
On Monday, PG&E CEO Patti Poppe called DOE’s funding decision “another very positive step forward to extend the operating life of Diablo Canyon Power Plant to ensure electrical reliability for all Californians.”
“While there are key federal and state approvals remaining before us in this multiyear process, we remain focused on continuing to provide reliable, low-cost, carbon-free energy to the people of California, while safely operating one of the top performing plants in the country,” Poppe said in a news release.
The $1.1 billion in funding is conditional, PG&E said.
“Final award amounts will be determined following completion of each year of the award period, and amounts awarded will be based on actual costs,” it said in the news release.
Energy Secretary Jennifer Granholm said in a statement Monday that DOE’s Diablo Canyon funding decision was “a critical step toward ensuring that our domestic nuclear fleet will continue providing reliable and affordable power to Americans as the nation’s largest source of clean electricity. Nuclear energy will help us meet President Biden’s climate goals, and with these historic investments in clean energy, we can protect these facilities and the communities they serve.”
The California Air Resources Board last week approved $2.6 billion in incentives for clean cars and trucks, the agency’s largest budget yet for the incentive programs.
The budget includes $2.2 billion for clean trucks, buses and off-road equipment. Another $326 million will go toward incentives for the purchase of clean light-duty vehicles, and $55 million is earmarked for clean mobility projects, such as community shuttles and bike share programs.
Along with the funding package, the CARB board on Thursday approved several changes to the agency’s incentive programs, including the Clean Vehicle Rebate Project, Clean Cars for All, and the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project.
“These incentives provide important steps to accelerate the transformation of the transportation sector to zero tailpipe emissions, powered by the lowest carbon energy sources,” CARB Executive Officer Steven Cliff said.
Cliff said the incentive programs will complement CARB regulations. Advanced Clean Cars II, which the board approved in August, will require all new cars sold in the state to be zero-emission or plug-in hybrid by 2035. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)
And Advanced Clean Fleets, which the board is expected to adopt early next year, aims to achieve a zero-emission truck and bus fleet in California by 2045 where feasible and even sooner for vehicles such as last-mile delivery and drayage trucks.
CARB estimates that more than 70% of the $2.6 billion will benefit priority populations, including low-income neighborhoods and areas hit hard by air pollution.
“This is a really historic day,” said CARB board member Diane Takvorian. “The key thing is not the amount of money, although that’s awesome. It’s really because it pulls together so many of the priorities that CARB has been working so hard for, for so long.”
Light-duty Incentives
Electric car sales have grown substantially in California, hitting 1.3 million vehicles at the end of the third quarter of 2022. The EV market share was 17.7% during the first nine months of the year, according to the California Energy Commission’s ZEV dashboard.
But EV prices have skyrocketed, CARB said, averaging $63,821 at the end of 2021 compared to $47,000 for a gasoline-powered car.
“In addition to ongoing supply chain issues, inflation and rising interest rates have made both new and used vehicles more expensive,” CARB said.
As a result, car buyers — especially those with lower incomes — are having a hard time finding an electric vehicle they can afford, even with CARB’s incentives.
Under the Clean Vehicle Rebate Project (CVRP), rebates for low-income buyers will increase to $7,500 for a fuel cell car (FCEV) or a battery-electric vehicle (BEV), and $6,500 for a plug-in hybrid (PHEV). That compares to current low-income rebates of $7,000 for an FCEV, $4,500 for a BEV and $3,500 for a PHEV.
Car buyers with annual incomes exceeding 400% of the federal poverty level but below the CVRP income cap may be eligible for the program’s standard rebate: $4,500 for an FCEV, $2,000 for a BEV and $1,000 for a PHEV.
Rebates are also increasing in the Clean Cars for All (CC4A) program, which is for low-income drivers scrapping an old vehicle. Participants can receive up to $10,000 for a new or used BEV or FCEV, $9,500 for a plug-in hybrid, or $7,000 for a conventional hybrid. An additional $2,000 will be available for residents of disadvantaged communities who are buying a plug-in hybrid or zero-emission vehicle.
Current incentive amounts under CC4A are up to $9,500 for a new or used BEV, FCEV or PHEV.
Low-income buyers can stack the CVRP and CC4A rebates to receive as much as $19,500 in incentives. A low-interest financing program is also available to low-income drivers, as is a $2,000 prepaid card for public EV charging.
Plug-in hybrids will no longer be eligible for CVRP as of Jan. 1, 2025, and conventional hybrids will lose CC4A eligibility by November 2024.
CC4A is currently available in five of the state’s air districts, but a statewide expansion of the program is underway.
Heavy-duty Incentives
The Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP), which CARB considers “the cornerstone of advanced technology heavy-duty incentives,” will receive $1.8 billion in the 2022/23 funding plan.
Of that amount, $157 million is set aside for drayage trucks, $70 million for transit buses, $135 million for zero-emission public school buses, and $1.1 billion for school bus replacement grants to local agencies.
CARB had previously proposed limiting the HVIP incentive to fleets with 100 vehicles or fewer starting in 2023. But the agency decided to postpone the fleet-size restriction until 2024, when fleets with 50 vehicles or fewer will be eligible.
In another new restriction, fleets of more than 500 trucks are required to buy 30 zero-emission vehicles without the HVIP incentive before being eligible for HVIP funds.
“Large purchases of ZEVs encourage manufacturers to scale up their assembly lines and support economies of scale,” CARB said in its funding plan.
The CARB board heard from several members of the public who are opposed to the fleet-size limit for HVIP.
“Large fleets play a pivotal role in proving out new technologies and driving scale, while small fleets rely on purchasing these trucks from large fleets,” said Madison Vander Klay, a senior associate with the Silicon Valley Leadership Group (SVLG).
SVLG also opposes the bulk purchase requirement for fleets larger than 500 trucks, which Vander Klay called “unreasonable.”
CARB staff noted that if smaller fleets aren’t using up all the HVIP funding, money would be released for larger fleets.
HVIP incentives are based on the type of vehicle being purchased. For heavy-duty buses, for example, the incentive ranges from $85,000 to $240,000, depending on the model. Another change to the HVIP program will increase the base incentive for fleets of 10 vehicles or fewer and decrease the incentive for fleets larger than 100 vehicles.
In addition to HVIP, the CARB funding plan allocates money to other heavy-duty vehicle programs, including $273 million for the Clean Off-Road Equipment voucher program (CORE); $60 million for commercial harbor craft pilot projects; and $29 million for truck loan assistance for small businesses.
The Biden administration last week invited applications for more than $6 billion in funding to expand and modernize the U.S. electric grid, opening the first round of transmission loans and grants under the Infrastructure Investment and Jobs Act (IIJA).
The Grid Resilience Innovative Partnership (GRIP) and Transmission Facilitation Program represent the largest single direct federal investment in transmission and distribution, according to the Department of Energy.
All told, the administration plans to invest more than $20 billion under its Building a Better Grid Initiative, which seeks to identify national transmission needs to reach President Biden’s goal of 100% clean electricity by 2035 and a zero-emissions economy by 2050. DOE cited estimates that the U.S. needs to expand the grid by 60% by 2030 and may need to triple capacity by 2050 to decarbonize the economy. (See Industry Welcomes DOE’s Better Grid Initiative.)
GRIP
Under GRIP, DOE opened applications for $3.8 billion for fiscal years 2022 and 2023 to improve grid flexibility and resilience against extreme weather and climate change. The IIJA allocated $10.5 billion in total for:
Grid Resilience Utility and Industry Grants ($2.5 billion), to fund transmission and distribution technology solutions against wildfires, floods, hurricanes, extreme heat, extreme cold, storms and other hazards to the power system. Among those eligible to apply are “electric grid operators, storage operators, generators, transmission owners or operators, distribution providers and fuel suppliers.”
Smart Grid Grants ($3 billion), intended to increase the “flexibility, efficiency, reliability and resilience” of the power system, with particular focus on increasing transmission capacity, preventing faults that can cause wildfires and integrating renewable energy, electric vehicles and electrified buildings. DOE will accept applications from state and local governments, tribal nations, universities, and for-profit and nonprofit entities.
the Grid Innovation Program ($5 billion), which will provide financial assistance to states, tribes, local governments and public utility commissions to “collaborate with electric grid owners and operators to deploy projects that use innovative approaches to transmission, storage and distribution infrastructure” to improve resilience and reliability.
“DOE believes there are significant benefits to be realized by coordinating the implementation of the three [IIJA] programs focused on power sector infrastructure, grid reliability and resilience,” it said.
Applicants must submit “concept papers” for the Grid Resilience Utility and Industry Grants and Smart Grid Grants by Dec. 16, with concept papers for the Grid Innovation Program due Jan. 13, 2023. A public webinar to provide more information will be held on Nov. 29.
Transmission Facilitation Program
The Transmission Facilitation Program is a revolving fund to help attract private investments into large-scale new transmission, upgrades of existing transmission lines and microgrids.
The Biden administration is hoping to encourage more large-scale transmission like the 5,000-MW Greenlink West project, a 525-kV line that would run 350 miles from Las Vegas to Yerington, Nev. | NV Energy
The IIJA authorized DOE to borrow up to $2.5 billion to prime the pump for new transmission and expansions that otherwise would not get built.
DOE will purchase up to 50% of the capacity of such projects, serving as an anchor tenant to attract other customers. “By initially offering capacity contracts to late-stage projects, DOE will increase the confidence of additional investors and customers and reduce the risk of project developers under-building or under-sizing needed transmission capacity projects,” DOE said.
Applications for the first phase are due Feb. 1, 2023. A public webinar will be held on Nov. 30.
Applications will be judged based on two equally weighted criteria: that a project is “unlikely to be constructed in as timely a manner or with as much transmission capacity” without the capacity contract and that DOE’s proceeds from capacity sales will recover the cost of its contracts.
The IIJA funding is in addition to the Inflation Reduction Act’s $3 billion in transmission funding, including $2 billion that DOE said “will unlock additional billions in federal lending for projects designated by the secretary of energy to be in the national interest.”
MISO, SPP Eye JTIQ Projects
Marcus Hawkins, executive director of the Organization of MISO States, said OMS is discussing with the SPP Regional State Committee seeking funding for the Joint Targeted Interconnection Queue (JTIQ) projects, a $1 billion portfolio of transmission between MISO and SPP.
“I’m sure individual PUCs will also apply for funding for other types of projects, but the JTIQ projects are the only ones I have direct knowledge of,” Hawkins said in an email.
MISO spokesman Brandon D. Morris confirmed the RTO’s interest in the funding, saying five projects in the JTIQ portfolio may be candidates. “These projects span seven states (Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota and South Dakota) and seem to align with DOE’s priorities,” Morris said.
CAISO spokeswoman Anne F. Gonzales said the RTO cannot accept the federal funding but will consult with organizations that can. “CAISO supports research and development efforts that enable innovative and comprehensive grid resilience solutions. The ISO provides support letters and serves as a member on many projects’ Advisory Boards,” she said. “In this advisory role, the ISO provides the system operator perspective and informed contribution to the role of grid operators in managing grid reliability as the complexity of the grid infrastructure and grid operational scenarios evolve.
SPP, NYISO and ISO-NE said they were reviewing the funding opportunity but otherwise declined to comment. The Organization of PJM States Inc. and the New England Power Generators Association also declined to comment. PJM and ERCOT did not respond to requests for comment. The Edison Electric Institute, the Independent Power Producers of New York and the Electric Power Supply Association also did not respond to queries.
“While each of these programs is targeted to address specific problems and solutions, I think the biggest benefit from these programs is that collectively they reduce the overall cost to consumers of getting needed transmission infrastructure built and put into service and ultimately will lower the impact on individual customer bills,” said Larry Gasteiger, executive director of transmission trade group WIRES.
Beyond the federal funding, Gasteiger said, “we need a moonshot effort to build more transmission on a faster timetable than we have ever built before at all levels, including interregional, regional and local transmission.”
About 70% of the grid is more than 25 years old, according to DOE. Gasteiger said much of the nation’s aging transmission is at the local level. “Yet there seems to be a glaring disconnect between the White House and DOE on the one hand and FERC on the other as to the importance of addressing those local transmission needs. Too much of FERC’s focus is on efforts that are likely to discourage or inhibit the development of needed local transmission.” (See Transmission Owners, RTOs Defend Planning, Cost Control Practices.)
DOE Criteria
DOE laid out the priorities for GRIP in its 140-page funding opportunity announcement, citing “insufficient development of projects” to increase transfer capacity between regions, reduce increasing interconnection queue times or increase the supply of “geographically and technologically diverse” resources to improve resource adequacy and reduce correlated generation outages.
It noted that the U.S.’ largest electric utilities have been investing more than twice as much in their distribution systems as in their transmission systems.
“Investments should prioritize driving innovative approaches to achieving grid infrastructure deployment at scale where significant economic benefits to mitigate threats and impacts of disruptive events to communities can be attained,” it added. “DOE is looking for proposals that will leverage private sector and non-federal public capital to advance deployment goals. These efforts will be aligned with state, regional or other planning activities and goals. As state resilience plans continue to be updated annually and evaluate future risks, DOE is interested in how federal funds will leverage industry investments towards hardening their system and/or advancing innovative solutions to enhance system resilience.”
Among the technologies it cited as candidates were “adaptive storage deployment, microgrid deployment, and the undergrounding of distribution and transmission lines.”
It also made a plug for grid-enhancing technologies (GETs), noting real-time congestion costs in CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM totaled $4.8 billion in 2016. Deploying three GETs nationally — advanced power flow control, dynamic line ratings and topology optimization — could save $5 billion in annual energy production costs, “with upfront investment paid back in just six months, and double the amount of renewables that can be integrated into the electricity grid prior to building new large-scale transmission lines,” it said.
DOE also said it would welcome applications to help grid operators quickly rebalance the electrical system with autonomous controls through data analytics, software and sensors.
Funding also will be available to appliance manufacturers who spend money on giving their products the ability to engage in smart grid functions and utilities that install smart grid monitoring and communication devices.
DOE urged applicants to team up with a wide range of stakeholders, including grid operators, technology vendors, system integrators and community leaders.
And in case there was any question, DOE said it will reject applications “for proposed technologies that are not based on sound scientific principles (e.g., violates the laws of thermodynamics).”
Federal buildings in Arkansas could, in the near future, be running on 100% carbon-free electricity (CFE), at least half of which would match the facilities’ demand hour for hour, 24/7, according to a new memorandum of understanding signed by the U.S. General Services Administration and Entergy, the state’s largest investor-owned utility.
The MOU was announced Tuesday at the 27th Conference of the Parties (COP27) in Sharm el-Sheikh, Egypt, in line with a new U.S.-led Net Zero Government initiative, with 18 other countries signing on to cut greenhouse gas emissions from their national government operations to net zero by 2050.
Brenda Mallory, Council on Environmental Quality | U.S. Department of State
The countries have also each agreed to develop a roadmap for achieving their net-zero goals, including interim targets, and to publish this plan all before COP28 next year in the United Arab Emirates, according to Brenda Mallory, chair of the White House Council on Environmental Quality (CEQ). Australia, Austria, Belgium, Canada, Cyprus, Finland, France, Germany, Ireland, Israel, Japan, Korea, Lithuania, the Netherlands, New Zealand, Singapore, Switzerland and the U.K. are the founding members of the initiative, along with the U.S., Mallory said at a launch event on Thursday in Sharm el-Sheikh.
“By joining this initiative, countries are — for the first time on a global stage, in a unified fashion — explicitly articulating the leadership role of government in catalyzing economywide climate actions and supporting their countries’ achievement of broader climate targets,” she said.
“We know that national governments are frequently the largest employers, electricity consumers, vehicle fleet owners, real estate holders and purchasers of goods and services in their countries,” Mallory said. “As a result, efforts to green our government operations can spur demand for clean industries and technologies, accelerate innovation … and lower decarbonization costs across all sectors.”
Entergy is one of the federal government’s top 10 electricity suppliers, serving a federal load in Arkansas of about 241,000 MWh per year, spread over 3,485 federal facilities in the state, according to a GSA spokesperson.
The MOU calls for the GSA and Entergy to collaborate on a plan that would provide all the utility’s federal customers 100% renewable power or CFE by 2030, with 50% matching demand 24/7. Entergy’s existing nuclear plants — one each in Arkansas and Mississippi, and two in Louisiana — will be part of the mix, along with “regionally sourced” renewables, including solar, wind and hydropower, the agreement says.
Entergy and the federal government will also pick up all costs of developing and delivering the clean power, with no cost-shifting to other customers, who may eventually have access to the 100% clean power. The MOU specifically calls for the utility to design and file a CFE rate by the end of 2022, which “would provide the appropriate pricing and other terms” needed to meet the 100% clean electricity target.
According to a GSA press release, “once [the plan is] fully developed and approved, it is anticipated that Entergy Arkansas customers in both the public and private sector will have a cost-competitive and reliable option for CFE that matches their electricity consumption for all hours of the day.”
GSA Administrator Robin Carnahan said the MOU is a potential model for similar utility-government partnerships that will “spur demand for carbon pollution-free electricity — when and where people need it.” Other benefits include “helping to promote local, clean energy sources and catalyze utility-scale energy storage, and create a more resilient grid,” she said.
Entergy has not commented on the MOU.
Close of the COP
COP27 closed in the early hours of Sunday, with exhausted delegates approving a historic agreement establishing a structure and process for creating a fund to help developing nations build back from the loss and damage they have already experienced from extreme weather caused by climate change.
After years of opposing any action on loss and damage, the U.S. signaled it would sign on to the agreement, which also calls for developing a range of financing options for addressing loss and damage, for example, climate risk insurance. The agreement also does not set any targets or call for any commitments for funding from developed countries.
With the Republicans taking control of the House of Representatives in January, it is unlikely that President Biden would be able to get additional climate funding for loss and damage approved.
In a statement posted to Twitter, U.N. Secretary-General Antonio Guterres said the agreement in and of itself “would not be enough, but it is a much needed political signal to rebuild broken trust.”
At the same time, the lack of a strong commitments on accelerated emission reductions and the phasedown of fossil fuels in the final conference decision at COP27 left the goal of limiting global warming to 1.5 degrees Celsius still on “on life support,” according to COP26 President Alok Sharma, speaking at the closing plenary.
Measures that would have contributed to “emissions peaking before 2025 as science tells us is necessary, not in this text; clear follow-through on the phasedown of coal, not in this text; a clear commitment to phaseout of all fossil fuels, not in this text,” Sharma said.
These and other issues left unsettled in Sharm el-Sheikh underline the importance of international efforts like the Net Zero Government initiative.
‘Show It’s Doable’
Both the initiative and the GSA-Entergy MOU build on Biden’s own plan for cutting U.S. government emissions, as laid out in an executive order issued in December 2021. The order first set the 2030 target for all 300,000 federal buildings to run on 100% clean power, matching demand 24/7 50% of the time. (See Biden Calls for Federal Procurement of 100% Clean Energy by 2030.)
The order also spelled out Biden’s intention for the federal government to “lead by example” and catalyze both technological innovation and economic and job growth. In addition to its clean power target, the order also requires that all new light-duty vehicles bought for the federal fleet to be zero-emission by 2027, with zero-emission procurement for all new vehicles in the fleet by 2035. The federal fleet currently has about 600,000 vehicles.
Other emission0reduction goals in the order include
for all federal government buildings: net-zero emissions by 2045, with an interim goal of a 50% reduction by 2032;
for all federal government operations: net-zero by 2050, with an interim target of a 65% reduction by 2030; and
for federal procurement: net-zero by 2050, via a “Buy Clean” policy that will promote the use of low-carbon construction materials and other low-carbon materials across the supply chain.
Other governments in the initiative are adopting similar goals and using their purchasing power to set examples and develop best practices for businesses, cities and schools.
Australia has adopted a stretch goal for its government operations to be net zero by 2030, said Christopher Bowen, the country’s minister for climate change and energy.
“I think it’s more important in terms of the example we set,” Bowen said during a panel at Thursday’s launch event. “If we’re asking companies to drive lower emissions; if we’re asking households to drive lower emissions, we have to set the example; … show it’s doable, show it’s possible.”
The Australian roadmap includes installing solar panels on all government buildings and converting existing power purchase agreements to renewable energy, he said.
From Ireland to Singapore
Eamon Ryan, Ireland’s minister for the environment, climate and communications, also pointed to governments’ ability to set budgets and policy as key drivers for emission reductions. An Post, Ireland’s state-owned postal service, started electrifying its vehicle fleet in 2019, beginning with delivery vehicles serving Dublin’s city center and then expanding to other cities across the country.
“Everyone thought that was crazy, but it actually worked,” Ryan said. More than half of the company’s fleet is now electric, according to the An Post website.
Grace Fu, Singapore | U.S. Department of State
Responding to the current energy crisis, the government has also decided to install solar panels on every school building in the country, he said. In addition to cutting the schools’ electric bills, the panels also can be used for “education, for each school to be able to monitor and see how this works,” Ryan said.
“Schools are the center of community, so if we can get it working there, we can spread this to the local shops, the local housing and so on,” he said.
Similarly, Grace Fu, Singapore’s minister for sustainability and the environment, said that while net-zero government initiatives are important, they can not only be top down. Singapore’s all-of-government approach includes “encouraging all our ministries in their outreach to the community to build in that [net zero] shift in mindset,” Fu said.
“We like every one of [our] employees to be our champion; to be a sustainability champion,” she said. “If every public sector employee is really going out there to lead the charge, I think we can really cause a wave of movement in Singapore.”
