LANSING, Mich. — Environmental, health and urban activists called last week for Michigan to up the ante on electric vehicles, saying the state should ban sales of new gasoline-powered cars by 2030 — five years earlier than the 2035 date set in August by the California Air Resources Board.
California’s decision could mean similar bans in 15 other jurisdictions — New York, Virginia, Connecticut, Delaware, Maryland, Maine, Minnesota, New Jersey, New Mexico, Nevada, Oregon, Pennsylvania, Rhode Island and Vermont, along with Washington, D.C. — which have tied their automotive rules to those in California. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)
Michigan, the long-time home of the American auto industry, has never tied its automotive rules to those in California or any other state. And none of the participants speaking at the press conference Thursday mentioned California’s well-publicized action.
But in adopting its plan to be carbon neutral by 2050, Michigan already is calling for the state to have 2 million electric cars and trucks on the roads by 2030. Last year, General Motors (NYSE:GM) said it aspired to have 100% of its fleet electric, and Ford (NYSE:F) said it expected 40% of its vehicle sales would be EVs by 2040.
Having all new passenger vehicles sold in Michigan be EVs by 2030 shouldn’t be too far a stretch, said Amy Rogghe, chair of the Michigan Electric Vehicle Alliance.
“It will put Michigan in the driver’s seat” of leading other states to the same goal, she said.
The activists made their call for the state to allow only emission-free new car sales about one week after Democratic Gov. Gretchen Whitmer announced a new proposal, the MI Future Mobility Plan, that among other things calls for the state to install 100,000 electric chargers by 2030. The state’s Department of Transportation intends to use more than $100 million in federal funds to help finance the proposal.
While Rogghe acknowledged the price of electric vehicles is higher than gas models now, prices are coming down, more models are coming on to the market and the vehicles are cheaper to operate, when fuel and maintenance costs are factored in.
Many of the advocates speaking at the press conference touted the health benefits of a non-polluting fleet.
Kathleen Slonager, executive director of the Asthma and Allergy Foundation of Michigan, said switching to an all-EV fleet could reduce asthma in Michigan, where rates are higher than in other states. While improving gas mileage has helped reduce the levels of the disease, bringing rates down further must happen at a faster rate.
And Kareem Scales, executive director of the Greater Grand Rapids NAACP, said switching to all electric or other clean cars could have a big effect on the health of “black and brown areas” that suffer greater effects from air pollution. “We’re not asking people to give up their cars, just for cars to be carbon free,” he said.
No legislators were part of the press conference, and neither lawmakers nor Whitmer have endorsed the idea. Whitmer did back the state net-zero plan’s goal of 2 million EVs on the road by 2030 and called for the state to provide tax incentives to EV purchasers.
Participants said they have met with lawmakers to discuss legislation encouraging efforts to reach a 2030 goal, instead of promoting penalties for not reaching the goal.
Tim Minotas of the Sierra Club of Michigan and Charles Griffith, energy program director of the Michigan Ecology Center, also spoke in favor of the 2030 ban and Whitmer’s proposed tax credit.
California regulators last week approved a plan that sets a 2025 target date for enacting a ban on sales of new natural gas-powered space and water heaters.
If the California Air Resources Board (CARB) approves the ban on schedule, it would take effect in 2030. Sales of new space and water heaters in California would be restricted through a zero-emission standard for the appliances.
The measure wouldn’t require replacement of gas heaters in existing buildings. But all new space and water heaters sold in California, either for new construction or to replace appliances in existing buildings, would need to meet the zero-emission standard.
“It is expected that this regulation would rely heavily on heat pump technologies currently being sold to electrify new and existing homes,” CARB said.
The potential ban on gas heaters is part of the 2022 State Implementation Plan, which CARB’s board voted to approve on Thursday. CARB will submit the plan to the U.S. EPA to show how California plans to meet the federal air quality standard for ozone.
In California, 19 areas are designated as being in nonattainment for the ozone standard, according to CARB. That includes the San Joaquin Valley and the South Coast Air Basin — the only two areas in the nation that are considered to be in extreme nonattainment.
The SIP contains an array of ozone-reduction strategies. CARB has already started rulemaking for some of the measures, such as the Advanced Clean Fleets regulation, which aims to achieve zero-emission truck and bus fleets in the state by 2045, where feasible. The regulation is expected to go to the CARB board for possible adoption next year, with implementation beginning in 2024.
A few of the other proposed measures in the SIP are an in-use locomotive regulation, new emission standards for motorcycles, and updated commercial harbor craft rules that the board approved in March and that will be phased in starting next year.
The measures are expected to improve air quality while also reducing greenhouse gases, helping California meet its climate goals.
The SIP is a commitment from CARB to pursue each measure in the strategy. For measures that involve a regulation, CARB is committing to bring a proposed rule to its board in the stated timeframe or explain why a rule wouldn’t achieve the desired emission reductions.
Regarding a zero-emissions standard for space and water heaters, CARB would work with other agencies, including the U.S. Department of Energy, California Energy Commission and the state Building Standards Commission. Stakeholder feedback would be gathered, and the proposal would be “subject to a full public process,” CARB said.
In addition, the agency said it “would work carefully with communities to consider any housing cost or affordability impacts, recognizing that reducing emissions from space and water heaters can generate health benefits and cost-savings with properly designed standards.”
According to CARB, almost 90% of nitrogen oxides emitted from buildings are from space and water heating. The remainder comes from cooking, clothes drying and other uses. Nitrogen oxides react with other chemicals in the air to form ozone.
CARB said that as it crafts zero-emission standards for space and water heating, the measure could potentially be expanded to include other end uses.
Expanding SPP’s full RTO into the grid operator’s Western Energy Imbalance Service (WEIS) could produce up to $89 million in annual savings, according to a study commissioned by WEIS members.
The Brattle Group study evaluated adjusted production cost (APC) savings and reported potential market benefits for expanding the SPP RTO into the WEIS footprint. The study estimates adjusted production cost savings of $71 million per year under average hydrology conditions. Those savings increase to $89 million per year under severe drought conditions.
Summary of Brattle study’s APC, wheeling revenue benefits | Brattle Group
Westside benefits range from $68 million to $81 million a year, according to the study. Eastside benefits are $3 million to $8 million annually under the study’s base and low-hydro scenarios.
“We’re pleased that the study reinforces the promise of an organized power market and our partnership with [SPP],” Colorado Springs Utilities CEO Aram Benyamin said in a statement. “The benefits are clear — millions of dollars in annual savings by having access to regional energy producers and the reliable and cost-effective integration of additional carbon-free energy resources into our system. The future is exciting.”
The utility was one of several prospective SPP RTO West participants who asked for the studies. Others included Basin Electric Power Cooperative, Deseret Power Electric Cooperative, Tri-State Generation and Transmission Association, Municipal Energy Agency of Nebraska (MEAN), and the Western Area Power Administration’s (WAPA) Upper Great Plains and Rocky Mountain regions and its Colorado River Storage Project.
All participate in SPP’s WEIS, which has been in operation since February 2021. They also receive reliability coordinator services from the grid operator. Tri-State, WAPA UGP region, Basin Electric and MEAN are already SPP RTO members in the Eastern Interconnection.
The study used an integrated east-west model based on data from SPP and WECC. It updates a 2020 Brattle study for SPP that projected $49 million in annual savings for current and new members by using new modeling assumptions about participant footprints, generation portfolios, natural gas prices and projected hydrology conditions.
The utilities said the APC study did not quantify other potential operational and reliability benefits such as balancing authority operations, coordinated resource adequacy and an integrated wholesale market that optimizes real-time, day-ahead and ancillary services. They said SPP’s RTO processes could improve transmission planning and development needed to support growing electricity demand and add more generation resources, including renewables.
WAPA CEO Tracey LeBeau said the study will help inform the agency’s next steps at it evaluates SPP membership.
“As always, we are committed to collaborating with our customers and stakeholders as we assess this opportunity,” she said. “Any decision to move forward with final negotiations for SPP RTO membership will be consistent with our statutory requirements and involve the appropriate public processes.”
“SPP understands the need for prospective SPP RTO members in the Western Interconnection to perform a revised Brattle study with their unique sensitivities,” SPP CEO Barbara Sugg said in an emailed statement. “We’re pleased the results of the updated study show a continued value for all participants.”
The study does not mean the utilities will join the SPP RTO, they said. The participating organizations will each continue their internal review and approval processes to determine whether they will proceed on the next steps to RTO membership.
“The most critical thing we do for our members and consumer-owners is to provide reliable, affordable and responsible electricity,” Basin Electric CEO Todd Telesz said. “We are pleased that the savings outlined in the study align with what our experience has shown so far — participation in regional transmission organization markets brings increased value to our membership.”
Speakers at the Global Clean Energy Action Forum last week in Pittsburgh were almost giddy with excitement over Washington’s record climate funding commitments.
The conference followed a string of legislative actions: the CHIPS and Science Act, which could provide as much as $67 billion for climate research and zero-carbon energy development and deployment; the Infrastructure Investment and Jobs Act, which includes $8.5 billion to support battery supply chains and “clean” hydrogen manufacturing; and the Inflation Reduction Act, which includes almost $370 billion in energy and climate spending. Over the next decade, think tank RMI says, the three laws will more than triple the federal government’s historic climate spending.
It’s a stark turnabout from 2017, when President Donald Trump announced the U.S. would withdraw from the Paris Agreement, saying famously, “I was elected to represent the citizens of Pittsburgh, not Paris.” (See Trump Pulling U.S. Out of Paris Climate Accord.)
But the government funding will not ensure the transition needed to mitigate climate change, speakers at the conference said, without philanthropies continuing to provide grants, networking and expertise.
Mike Boots, Breakthrough Energy | Global Clean Energy Action Forum
Philanthropies will remain important in bridging funding gaps in the “innovation arc,” said Mike Boots, executive vice president of Breakthrough Energy.
In addition to the federal and state governments “providing more public money that’s ever been available … there’s a lot more private capital also in that mix,” he said during a panel discussion Thursday. “And yet, there is a need for philanthropic capital also to help [technologies overcome] technical … operational and engineering risks.”
Philanthropies also help connect governments with communities and help communities access funding, said Heidi Binko, executive director and co-founder of the Just Transition Fund. “It’s an incredible opportunity, where we’ve got billions of dollars available for transitioning energy communities through the American Rescue Plan; through the bipartisan infrastructure law; and now in a very exciting way through the Inflation Reduction Act,” she said. “But we also know that just because the money is there does not mean that it’s going to flow to the people who need it the most.”
Charities also are key to helping emerging countries skip fossil fuels in their economic development, said Ashvin Dayal, who leads the Rockefeller Foundation’s Power & Climate program.
“Internationally, there’s over 700 million people who still lack access to a basic electricity connection. There’s about 2.5 billion people who are considered energy poor, i.e., they need to consume significantly more, not less, energy in order to lift themselves up,” he said. “Even if the OECD [Organisation for Economic Co-operation and Development] economies and China achieve their net-zero ambitions … if the rest of the emerging world continues to grow their energy consumption on a business-as-usual fossil fuel-dependent path, we will not get anywhere close to 1.5 degrees [Celsius], let alone 2 degrees.”
‘Blended Finance’
Billionaire Bill Gates founded Breakthrough Energy — a network including investment funds, nonprofit and philanthropic programs — to scale the technologies need to reach net-zero emissions by 2050.
Boots said there are many emerging technology startups that have received venture capital and other private funding. “And yet, at the end of their venture capital run, often their product is still too expensive in the market to get the uptake. It needs to scale.”
The funding promised by Washington and European governments is “a significant amount of public money.”
“And yet, even with that public money, and even with some private money coming off the sidelines, there’s not often enough of the right flavor of capital … to fully flesh out that capital stack and to make those projects get over the finish line.”
Boots said the organization’s new initiative, Breakthrough Energy Catalyst, will be a “blended finance platform.”
“What we imagine is some of the money from the infrastructure bill and some of the money from the Inflation Reduction Act will capitalize part of that stack. We are going to come in then with a blend of some philanthropic capital — some very concessional equity that will allow those hydrogen projects and those [direct air capture] projects and those long-duration energy storage projects.”
Building ‘Capacity’ in Community Groups
Just Transition Fund’s Binko said philanthropies can help under-resourced communities overcome barriers to obtaining the funding becoming available.
She cited a $62.8 million Build Back Better Regional Challenge grant recently awarded by the U.S. Department of Commerce’s Economic Development Administration (EDA) to the Appalachian Climate Technology Coalition (ACT Now) in West Virginia.
Heidi Binko, Just Transition Fund | Global Clean Energy Action Forum
“Without philanthropy, they would have not built up the capacity to be able to access those federal funds. And so we’re in a moment where that’s needed now, but in a really coordinated and big way,” she said.
In recent months, Binko said, her group has been contacted by numerous federal agencies, including EDA, EPA, the Department of Energy and the Appalachian Regional Commission, a partnership of the federal, state and county governments. “They know that we’ve been working really closely with energy transition communities for over a decade. And they’ve reached out and they’ve said to us, ‘Who are the hardest hit? How do we reach them?’”
Binko said her organization is about to launch a Federal Access Center, which will share with the agencies recommendations it hears from its community partners. Among the plans: town hall listening sessions with agency leads “so they can hear the best and brightest of ideas from our communities,” Binko said.
Role in Emerging Markets
The Rockefeller Foundation’s Dayal said philanthropies have a crucial role in helping emerging markets deploy new technologies, provide capital to decarbonize coal and develop “the business models that can help scale up innovative distributed renewable solutions, or even get grid-tied renewables deployed at scale.”
“In economies like South Africa, Indonesia or my own country, India, that is going to require a momentous coming together of different types of capital,” he said. Philanthropy should be “at the base of that stack, providing that first loss; taking the highest risk possible to test and scale a solution.”
He cited the “de-risking” needed to build “metro grids” in a country like the Democratic Republic of Congo, where “100 cities could be electrified with off-grid large-scale solar.”
Ashvin Dayal, Rockefeller Foundation | Rockefeller Foundation
“But you don’t exactly have companies rushing in because there’s political risks; there’s demand risks; there’s contract risk — there’s all of these risks that have to be taken off the table,” he said.
To address the gap, the Rockefeller-funded Global Energy Alliance for People and Planet is seeking to bring together “different shades of investment capital” from private sources, philanthropies and development finance institutions like the World Bank and African Development Bank.”
“[We’re] trying to build an alliance that can go after transformational projects in a much more coordinated and accelerated way,” he said. “Because right now, it’s too slow; it’s too fragmented. And we’re not going to get there.”
Proving a technology in the OECD countries does not mean that it will be affordable in emerging nations, he said.
In Nigeria, which is 50% unelectrified, distributed diesel accounts for about 60 GW of generation, compared to only 10 GW on the grid. “So there’s a huge amount of interest in deploying solar microgrids, electrifying markets, businesses, small communities,” Dayal said. “But the cost of lithium ion … in Nigeria is still three times what it is here. The cost of even PV is still 20% or 25% more than what it is in the United States.”
In response, Dayal’s organization is working with local financiers and technology companies to create a “pool procurement vehicle.”
“We piloted it just last year, and even before the ink was dry, we were able to drop the costs by about 30%, because you brought 15 or 20 small developers together and do a single procurement,” he said.
Dayal said he is often asked why his foundation is contributing funding to the U.S.’ Net Zero World Initiative — which will match developing countries with DOE’s National Laboratories to create and implement climate solutions — when the government “has all of these resources.”
“And the answer is, because this is about building new types of partnerships that don’t currently exist. And that’s really the key to this: We have to really unlock the synergy. And that’s where I think philanthropy has to be more risk-taking and, frankly, be putting more of its resources into this space. It’s still woefully underfunded.”
The New York Power Authority on Friday reported success in a hydrogen-natural gas hybrid demonstration project at a 45-MW power plant it operates on Long Island.
NYPA said the Brentwood Small Clean Power Plant maintained full operational status while decreasing carbon emissions during the test.
The project was a collaboration with EPRI, General Electric and Airgas, among others, and was the first utility-scale hydrogen-blending project in New York, NYPA said.
The plant’s GE LM-6000 turbine was tested with fuel mixtures of 5% to 44% hydrogen from the fall of 2021 through spring 2022.
At steady state conditions, the exhaust stack ammonia, carbon monoxide and nitrogen oxide slip levels showed that emissions could be maintained below the state Department of Environmental Conservation Title V Regulatory Permit limits using the existing post-combustion emissions reduction systems, NYPA said.
Carbon dioxide emissions decreased as the hydrogen percentage increased, the test found. At 35% hydrogen by volume, CO2 output was down by about 14%.
Carbon monoxide decreased by as much as 88% as the hydrogen mixture increased, apparently due to greater oxidation in the presence of hydroxyl radicals resulting from hydrogen combustion.
However, NOx increased by as much as 24% as the hydrogen content was increased, unless the water injection rate also was increased. This performance is specific to the technology of the LM-6000 and may not apply to dry-low emissions combustors, authors of a report on the test said.
Engine control was stable throughout the duration of the test. Combustion equipment was in good condition before, during and after the test; periodic borescope inspections found no apparent damage to the turbine due to hydrogen combustion.
Takeaway lessons from the tests included:
Maintain a stable hydrogen supply so the hydrogen system does not trip off; the manual hydrogen regulators at Brentwood required continuous monitoring and adjustment, which would not be practical in normal plant operations.
Ensure adequate natural gas supply pressure, which must increase as the hydrogen ratio increases. This proved to be a limiting factor on the percentage of hydrogen used in the test.
Allow sufficient time for concept review and permit exceptions. Hydrogen is not well-defined in National Fire Protection Association codes and standards, and securing permits needed to operate the Brentwood plant in an experimental mode took an extended time.
Adopt a collaborative design approach earlier on in the process. The large number of teams involved in the Brentwood project progressed with their work at different speeds, requiring rework to be done late in the process.
Many partners joined for the NYPA project:
GE assisted in building the hydrogen/natural gas blending system.
EPRI’s Low-Carbon Resources Initiative helped design the project and served as advisors on the technical evaluation.
Airgas supplied the renewable hydrogen for the testing.
Sargent & Lundy, the original architect engineer of the Brentwood plant, provided engineering expertise as well as safety reviews.
Fresh Meadow Power developed the piping system that delivered the hydrogen to the GE-designed mixing skid and into the turbine.
NYPA interim CEO Justin E. Driscoll said in a news release that this type of collaborative, multi-pronged approach is what is needed to advance the technology New York will rely on to meet its ambitious climate-protection goals: 70% renewable energy generation by 2030, 100% renewable by 2040 and an 85% reduction in greenhouse gas emissions in 2050 compared with 1990 levels.
Not all the technology needed to accomplish this exists in scalable or economically viable form. Green hydrogen — hydrogen generated through zero-emissions means — is just one of what will likely be many components of the strategy to reach the decarbonization goals set by New York and other governments.
“Today, NYPA is pleased to share the results of our hydrogen study with the industry and the public so that our key learnings can help illuminate future decarbonization efforts,” Driscoll said.
Eric Gray, CEO of GE Gas Power, said: “Efforts like the Green Hydrogen Demonstration Project are vital to validate the important role that hydrogen can play in lowering carbon emissions from power generation while also providing reliable and affordable power.”
The report on the demonstration project is offered for sale by EPRI here. The executive summary is available for free download here.
The owner of a large gas plant in Illinois has secured a temporary injunction against emissions-control provisions laid out in the state’s Climate and Equitable Jobs Act (CEJA).
J-Power USA’s 1,350-MW Elwood Power Plant is temporarily exempted from the Illinois Environmental Protection Agency’s (IEPA) enforcement of an annual emissions threshold under CEJA. In granting the mid-September injunction, Illinois’ 7th Judicial Circuit Court decided that enforcement of the pollutant cap predated the rules’ official implementation and J-Power didn’t have fair notice (2022-CH-50).
Sangamon County Judge Raylene Grischow ruled that if the IEPA were allowed to enforce emissions caps on Elwood beginning October 2021 as attempted, the plant would be forbidden from producing energy and J-Power would suffer irreparable harm. She said J-Power was unaware in 2021 that its operations would be monitored under a yet unreleased rule.
“The compliance rule is arbitrary and capricious because it demands compliance prior to IEPA’s announcement of how emissions caps were to be calculated. IEPA’s rule, issued in January 2022, declared that ‘any 12-month period’ meant a rolling, 12-month calculation, starting with the period October 2021 through September 2022. Prior to January 2022, energy producers did not have the necessary information to calculate their emissions caps or monitor their ongoing emissions for CEJA purposes,” Grischow wrote.
CEJA established emissions caps for investor-owned, gas-fired units with three years of operating history; those units must not annually exceed an average of their emissions from 2018 through 2020.
J-Power said that Elwood was “obligated to generate power at a higher-than-normal capacity” in the fall of 2021, before the IEPA issued the new emissions caps. The company claimed that by the time the agency announced a retroactive compliance period in January 2022, Elwood already used up more than 80% of its allotted run time for the year based on its emissions, with two of its nine units already maxed out.
After higher-than-normal deployments continued in the spring, J-Power predicted in early summer that Elwood would likely be vulnerable to noncompliance beginning in July. The plant stopped operating completely in September, and J-Power claims it has since lost millions of dollars.
The court said Illinois permitted a “significant implementation gap” and that the IEPA’s “retroactive application of its gap-filling rules” violates the due process clauses of both the U.S. and Illinois constitutions.
“Injunctive relief is necessary to safeguard the benefit Elwood provides to Illinois residents: the grid stability necessary to avoid and recover from blackouts and helping to control energy prices,” Grischow wrote. “If Elwood were to close due to a magnifying injury over the next few weeks, Elwood would no longer exist to operate when the grid needs it. Allowing Elwood to operate in the short term and provide electricity that the citizens of Illinois need is a reasonable and equitable measure.”
The temporary injunction isn’t a statement on the merits of CEJA’s emissions regulations, Grischow said, adding that it’s not the court’s function to answer that “ultimate question.” She also said the injunction is narrow and doesn’t stand to disrupt CEJA in the long run.
CEJA requires all fossil plants in Illinois to close by 2045.
The Illinois Clean Jobs Coalition said it wasn’t surprised that companies dealing in fossil fuel generation would challenge and try to “flout” the emissions limitations.
“The Climate and Equitable Jobs Act’s steady path to eliminating pollution from gas and coal plants is gradual, achievable, good for public health and essential to becoming a leader in the clean energy economy,” the group said in a statement. “We are confident the provisions will ultimately be upheld by the judicial system and thwart Elwood’s efforts to avoid compliance.”
The California Public Utilities Commission on Friday proposed replacing the state’s largest natural gas storage facility, Aliso Canyon, with a combination of non-gas-fired generation, building electrification, energy efficiency and storage.
The proposal accompanied a ruling in which the CPUC detailed its findings from the second phase of its investigation of Aliso Canyon, site of a massive methane leak in October 2015. The underground facility remains necessary for grid reliability and to serve gas customers in the Los Angeles Basin, the commission found.
“As California pursues its decarbonization goals, natural gas demand will decline over time,” it said. “Currently, however, millions of individuals and businesses continue to rely on natural gas for essential services. Given that flowing gas capacity alone is not sufficient to meet peak seasonal or hourly demand, natural gas storage at Aliso Canyon continues to be a key part of the state’s energy infrastructure.”
The commission’s ruling instructs the state’s major utilities, including Aliso Canyon owner Southern California Gas (NYSE:SRE), to provide input on how they would increase supply and reduce demand to allow the facility’s eventual closure. It poses a series of questions to the companies including, “What is the earliest reasonable time a portfolio can be adopted for reduction and elimination of California’s reliance on Aliso Canyon?”
The staff proposal said that to meet demand in 2027 without the facility, utilities would need to annually reduce peak gas demand by 214 MMcfd (about 4% of the peak total) or annually increase their non-gas generation by 1,084 MW of (2% of the state’s electric capacity) — or do a combination of both.
The facility’s fate has been controversial since a ruptured pipe at the SS-25 well poured more than 100,000 tons of natural gas into the air, leading to a blowout and sickening nearby residents. The leak was contained after four months in February 2016.
A few months later, Gov. Jerry Brown signed Senate Bill 380, which told the CPUC to determine “the feasibility of minimizing or eliminating the use of the Aliso Canyon natural gas storage facility … while still maintaining energy and reliability for the region.”
The facility reopened at a reduced capacity in July 2017, but last November the CPUC increased its storage limits by 7 Bcf amid concerns about winter gas supply.
“Our decision today helps ensure energy reliability for the Los Angeles Basin this winter in a safe and reliable manner,” former Commissioner Martha Guzman Aceves said at the time. “We continue to move forward on planning how to reduce or eliminate the use of Aliso Canyon, and to ultimately reduce our reliance entirely on such natural gas infrastructure as we transition to a clean energy economy.”
The non-utility owner of a Washington gas-fired power plant can receive an initial allocation of free cap-and-trade allowances from the state, a government board decided Tuesday.
Washington’s Energy Facility Site Evaluation Council (EFSEC) unanimously approved extending the allocation to the 620 MW Grays Harbor Energy Center, which is owned by independent power producer Invenergy. The council’s discussion was limited to tweaking the language of the approval document.
The Grays Harbor plant is the only gas-fired facility in Washington that is not owned by a public utility, which means it did not receive the same no-cost carbon allowances granted to utility-owned power plants under the state’s new cap-and-trade program, which goes into effect on Jan. 1, 2023. Carbon emissions are calculated the same way for both utility- and non-utility-owned plants under the program.
The plant’s officials protested this discrepancy to the Washington Department of Ecology in June. “All the state’s power plants need to be on the same footing,” Grays Harbor Energy representative Torey Mielke said during a June 21 public hearing. (See Independent Power Producer Sees Risk from Wash. Cap-and-trade.)
Invenergy officials also expressed concern about their plant having to compete with out-of-state power producers that don’t have to spend money on the carbon-combating measures now required in Washington.
Under cap-and-trade, carbon emitters must acquire allowances for specific amounts of carbon dioxide pollution, which they can buy, sell or trade with other businesses. The maximum volume of statewide emissions would decrease over time.
The Ecology Department’s plan calls for an undetermined number of emissions allowances to be auctioned four times a year to smokestack industries. The first two auctions are scheduled for the first half of 2023, and the state will set the number of allowances 60 days prior to the auctions.
Companies would bid on the allowances in clusters of 1,000 individual allowances. The number of allowances will be decreased over time to meet 2035 and 2050 decarbonization goals. If Washington chooses to join the Western Climate Initiative, which includes California and Quebec, participants would expand their purchase and trading territory to those two areas.
For each auction, a specific number of allowances would be made available to bidders. All bids must be above a certain price level set in advance by the state. The highest bidder would get first crack at the limited number of allowances, while the second highest bidder would get the second crack, followed by additional iterations. The auction ends when the last of the designated number of allowances is bid upon. Then all the successful bidders pay the same clearing price set by the lowest successful bid.
Bidding companies are limited to acquiring 4-10% of the total number of allowances, depending on various criteria.
FERC last week revoked Tri-State Generation and Transmission Association’s market-based rate authority in the Western Area Power Administration’s Colorado-Missouri balancing authority area (WACM), but it found the cooperative may retain that authority in other BAAs (ER20-681, EL22-28).
The commission said information provided by Tri-State “failed to rebut the presumption of market power” in WACM. “As a result, we find that it is not just and reasonable for Tri-State to continue to have market-based rate authority in the WACM balancing authority area,” it said.
The data showed consistent screen failures across measurements, season/load periods and price sensitivities in the BAA, FERC said. It directed the cooperative to submit within 30 days a revised market-based rate tariff limiting sales at market-based rates to areas outside of WACM in which it retains MBRA.
The commission also ordered Tri-State to respond with a separate tariff to provide for the default cost-based rates in WACM or to make clear its intent to use its current cost-based tariff on file.
FERC opened an investigation into Tri-State under Federal Power Act Section 206 after it submitted its triennial updated market power analysis and a change-in-status notice last December.
The commission allows power sales at market-based rates if the seller and its affiliates do not have, or have adequately mitigated, horizontal and vertical market power. An applicant that fails one or more of the indicative screens is provided with several procedural options, including the right to challenge the market power presumption by submitting a delivered price test (DPT). However, the revised DPT indicated the consistent screen failures.
FERC did find that Tri-State passed the horizontal market power indicative screens for the Public Service Company of New Mexico and Public Service Company of Colorado BAAs and CAISO’s Western Energy Imbalance Market.
The commission on Thursday also rejected SPP’s proposed tariff revision to include an annual transmission revenue requirement (ATRR) for certain GridLiance High Plains facilities in Oklahoma’s Panhandle, affirming in part and reversing in part a decision by an administrative law judge in hearing and settlement procedures (ER18-2358).
FERC said that SPP’s 2018 filing to revise the tariff and allow recovery of the ATRR for GridLiance’s facilities was unable to prove the change was just and reasonable. It said that in protesting the filing, Xcel Energy Services (NASDAQ:XEL) was able to show “adequate evidence” that the facilities should be declassified as transmission under the commission’s seven-factor test.
FERC rules GridLiance’s Oklahoma facilities do not qualify for rate recovery. | GridLiance
Xcel also said GridLiance’s inclusion of its Oklahoma Panhandle facilities in its ATRR would result in a cost-shift to its Southwestern Public Service subsidiary, which shares the same transmission pricing zone (Zone 11). (See GridLiance, Xcel Battle over Tx Qualifications.)
The commission reversed an ALJ decision last year that the transmission facilities were eligible for recovery in transmission rates under SPP’s tariff. FERC directed GridLiance and SPP to issue refunds within 45 days to customers in GridLiance’s ATRR in Zone 11.
“We find, among other things, that … SPP and GridLiance failed to meet their burden to prove by a preponderance of the evidence that the GridLiance facilities are transmission facilities eligible for recovery,” the commissioners wrote.
FERC said that because it resolved the case’s central issue, it did not reach the merits of the rate impact, cost causation, prudent decision-making, and other arguments raised by Xcel and other intervenors.
The commission also dismissed a pair of Xcel’s formal challenges to GridLiance’s 2021 and 2022 annual formula rate updates as moot, citing the 2021 order over Xcel’s previous informal contention that GridLiance’s inclusion of the Oklahoma assets’ costs in its updates was improper (ER21-1438, ER22-1353).
It said that given the decision in the earlier proceeding and GridLiance’s implementation of the Zone 11 ATRR in the 2021 and 2022 annual updates, Xcel’s formal challenges were moot.
Just Energy OK’d for MBRA
FERC also granted power marketer Just Energy’s authority to make wholesale sales of energy and capacity at market-based rates and found it met the criteria to be a Category 1 seller in all regions (ER22-2044, ER22-2044-001).
The commission determined that because Just Energy does not own or control generation or transmission facilities, it satisfies FERC’s requirements for market-based rates regarding horizontal and vertical market power.
The ruling allows Just Energy to supply retail power in competitive markets, as one affiliate already does in ERCOT. It will contract with third parties to procure supply for its other affiliates and to provide them scheduling, settlement and bid/offer submission services once it registers with grid operators.
MISO continues to suss out a new availability-based capacity accreditation method for renewable generation, despite some stakeholders’ qualms with the early design.
The grid operator held a workshop Wednesday to dissect its proposed methodology for wind and solar resources. It will dole out capacity credit based on a unit’s availability during times of system need.
Jordan Bakke, MISO’s director of policy studies, said the goal is to fit renewable-resource accreditation into the “mold” of thermal units’ recently approved availability-based accreditation. He said MISO must make some assumption adjustments for a “different resource type with different characteristics.”
The RTO is creating “different swim lanes” between thermal, renewable and load-modifying resources, Bakke said.
The grid operator will use a modified effective load carrying capability (ELCC) calculation for renewable resources, then adjust those values for availability based on what it calls “resource adequacy hours,” or historical hours over a year that contain tight supplies and reliability risks.
MISO introduced the concept of resource adequacy hours when it overhauled its ELCC for thermal resources. They represent the top 3%, or 65, riskiest hours per three-month season and include the hours spent in maximum generation events. (See FERC OKs MISO Seasonal Auction, Accreditation.)
“Our bias is to remain somewhat close to what we filed at FERC” for thermal units, MISO planning adviser Davey Lopez said.
Bakke said ELCC is a “comparable method” when compared to thermal generation’s unforced capacity calculation (UCAP).
Clean Grid Alliance’s Natalie McIntire said she didn’t see how the calculations are comparable because UCAP relies on units’ forced outage rates but ELCC doesn’t.
Bakke said the divergence is necessary because wind and solar performance contain a lot of “availability variability” during tight operating periods. On the other hand, thermal output is steadier.
“The performance is much more uniform over time,” he explained.
Bakke said PJM and ISO-NE have made similar arguments to FERC when getting their renewable capacity accreditation designs approved. He said MISO could pursue a more complex calculation only to end up with a “comparable outcome” to the simpler ELCC method. He said MISO isn’t convinced that more labor-intensive number crunching would be worth the effort.
MISO plans on tweaking its current ELCC computation to apply to its ever-expanding renewable fleet.
Renewable energy accreditation will move from being derived using an individual, unit-level ELCC based on peak hour contribution to a resource portfolio-based standard ELCC that will be applied to a unit’s availability during pre-defined resource adequacy hours. Staff said they will create separate portfolio-level ELCCs for wind and solar generation and said they might adjust those based on whether units are located in MISO Midwest or MISO South.
Some stakeholders called the proposed ELCC method difficult to understand. Others said using a fleet-based average is too broad to apply to diverse wind units and will condemn renewable generators to lower capacity values.
Bakke said the portfolio-wide ELCC is “not a wholesale change” but necessary for MISO to have sustainable and consistent renewable accreditation moving forward.
Whether the ELCC should remain an average of unit performance across the portfolio or a become a marginal value, reflecting the capacity value of the most recent renewables additions, remains an open question.
MISO Independent Market Monitor David Patton advocated for a marginal value because he said renewable capacity contributions become less valuable from a reliability perspective as more are added.
“Every conceivable loss of load risk compounds when the wind isn’t blowing; therefore, building more wind at the margins is futile,” Patton explained. “You need more and more capacity for every megawatt you build of an already saturated technology.”
MISO hasn’t yet settled on a marginal versus average approach.
The renewable accreditation won’t cover battery storage or hybrid resources that pair a renewable energy resource with a storage facility. Bakke said MISO wanted to tackle the large amounts of wind, solar and load-modifying resources first before evaluating next year the accreditation of the “more emergent” resource types.
The grid operator has proposed using historical availability data collected from its existing demand-side resource interface to accredit LMRs. It said its control room operators “see a significant reduction in LMR availability when compared to what clears in the PRA.”
Stakeholders have asked MISO to compare the amount of LMRs’ load reduction that is weather dependent during the workday with weekend dependent.
