Search
`
November 5, 2024

Posted on

Power Plant Emission Rules Up in the Air as Technologies Change

The battle over federal rules controlling power plant emissions is heating up again as the Biden administration’s EPA prepares to issue revised regulations by the end of the year.

The agency is developing the rule even as the Supreme Court considers an appeal of rules issued by the Trump administration and thrown out by the D.C. Circuit Court of Appeals. The high court listened to oral arguments two weeks ago and is expected to issue an opinion in June. (See Supreme Court Hears Arguments on EPA Authority Over GHGs.)

Some of the same issues that cropped up in the Obama administration’s Clean Power Plan (CPP), finalized in 2015, may persist: “beyond the fence line” emission rules, generation shifting, and the even trickier standards promulgated in the Affordable Clean Air Energy (ACE) rule issued by the Trump administration in 2019 for heat rate efficiency.

In a webinar produced Wednesday by D.C.-based OurEnergyPolicy, four of the industry’s top legal minds examined some of these issues.

“I think [among the] things that are being discussed even while we wait for the decision is what should EPA base the standard on,” said Carrie Jenks, executive director of Harvard University’s Environmental and Energy Law Program.

“The power sector has changed [since] the Clean Power Plan was designed and also when ACE was designed. And how does EPA look at that what has happened with technologies? What’s the basis for the standard? What should companies and states be allowed to do in terms of complying with that standard?” she said.

Emily Sanford Fisher, general counsel for the Edison Electric Institute, also noted that technologies have changed since the CPP was introduced.

“Actually quite a lot has changed. One way to think about it is that the Clean Power Plan was aiming to achieve a 32% reduction in industry-wide emissions by 2030. And at the end of 2020, as an industry we were at 40% below 2005 levels.

“So obviously something that EPA in 2015 thought we wouldn’t be able to achieve until 2030 we accomplished without the Clean Power Plan and actually before it even would have taken effect,” she said, adding that the Obama administration gave the industry until 2022 to achieve the lower emissions.

The growth of renewable energy, which Sanford-Fisher noted “is a very competitive form of generation,” and state renewable portfolio standards have also been responsible for making the industry cleaner, she said.

Another factor that changed total emissions was the Obama administration’s decision to issue the final Mercury and Air Toxics Standards, which led to the retirement of about a third of the coal fleet, she said, adding that about 50 of the 65 member companies in EEI have long-term commitments to continue to reduce emissions.

Ben Longstreth, senior attorney with the Natural Resources Defense Council, said he “concurred entirely” with Fisher but added that the emphasis should not be taken off the power sector because it will become even more important as the number of electric vehicles grows.

He also said that EPA is facing mandates that Congress put into the original law.

“NRDC always had a program thinking about the conventional air pollutants — the SOx, NOx, mercury — and while the sector has improved a lot, [the pollutants] remain significant,” he said.

Posted on

WECC Sets May 1 Target for Resumption of In-person Meetings

WECC is planning to resume in-person meetings at its Salt Lake City headquarters, asking for “grace” as it plots a way to accommodate all stakeholders, CEO Melanie Frye said Wednesday.

“March 23 actually marks the two-year anniversary of us closing the WECC office,” Frye said during a quarterly meeting of WECC’s Board of Directors.

She pointed out that the regional entity’s last in-person event was the March 2020 board meeting, held just before the COVID-19 pandemic drove office workers into quarantine and established widespread use of remote working and virtual meetings.

WECC will retain elements of that now well-established practice in its approach to stakeholder gatherings, adopting a “hybrid” model of face-to-face meetups with the continued option of participating virtually, Frye said.

“Beginning May 1, we’ll start to consider on a case-by-case basis moving to hybrid meetings, which probably will be our new normal at work,” she said. “We know that many companies are still in limited travel arrangements, so as we contemplate having technical committee meetings, we know there will probably always be an element that is hybrid, with people remotely participating and, [for] those who are able to travel, in person.”

In a roundtable discussion during a meeting of the WECC Member Advisory Committee on Tuesday, stakeholders expressed a desire to get back to in-person meetings as their states and employers begin relaxing pandemic restrictions.

“Our policy is allowing for travel where appropriate, and we would love to see it happen,” MAC member Brian Evans-Mongeon, president of Utility Services, said.

Russell Noble, reliability compliance manager at Cowlitz County Public Utility District in Washington, said the “last vestiges” of his state’s COVID regulations would be expiring March 12. “We are looking towards getting back to normal and definitely be allowed to make necessary travel arrangements for necessary meetings.”

But WECC’s Canadian members still face uncertainty about crossing the border into the U.S., said Diana Wilson, director of enterprise risk management and compliance at the Alberta Electric System Operator. “I think it’s going to really have to be a matter of how things unfold,” she said.

Frye asked for forbearance as WECC attempts to transition to hybrid meetings.  

“The final point I’ll make is just to really ask grace as we start to implement hybrid meetings,” Frye said. “We’ll be evaluating the technology that we have in our meeting rooms, [and] it will be something new and different to have a combination of in-person participants and remote participants. So there may be some technology bumps along the way, and we’ll keep learning and evaluating what we might need on our end to provide the best experience for all of our stakeholders.”

Restrictions Relaxed, FlexWork Begins

Frye on Wednesday also informed the board that WECC will begin welcoming all staff to return to the Salt Lake City office on April 4, relaxing existing limits on the number of people allowed to work in the building on any given day.

“We have announced to our employees that we think now is the time to start to transition to our FlexWork — new normal — that we’ve developed,” Frye said.

WECC announced its decision to implement the new FlexWork program last June. The program is designed to give most employees the option to work from home, while also holding out the requirement that they might need to put in “core hours” at the office to attend trainings, committee meetings, regulatory audits and board meetings. FlexWork was postponed in September as the Delta variant fueled a surge in COVID cases.

“Our FlexWork program is a strategic business initiative that provides flexibility in work schedules that best fits WECC’s business objectives and expectations, and fulfills individual and team needs on the job in a collaborative and flexible work setting,” Julie Booth, WECC manager of communications and outreach, told ERO Insider Wednesday.

With the rollout of the program next month, WECC will lift current pandemic-related restrictions, including the 50% cap on attendance, the requirement to use the ClearPass application to sign in to work a day in advance to provide a health attestation and the need to wear a mask.

“For FlexWork, we will keep in place extra cleaning measures, hand sanitization stations and mask wearing when requested,” Booth said.

Posted on

New Yorkers Support 10-GW Solar Target — with Reservations

Consumers, environmentalists, utilities, developers and labor organizations expressed support for New York’s plan to expand state solar incentives by $1.5 billion through 2030, but many are concerned with who pays, how much, and how often (Case No. 21-E-0629).

The groups filed comments in response to the Public Service Commission’s roadmap for achieving 10 GW of distributed solar by the decade’s end. Installed distributed solar and projects under development already total more than 93% of the previous state goal of 6 GW by 2025. The roadmap defines distributed solar as including residential, non-residential and commercial/industrial projects, including community distributed generation, distinguishing them from utility-scale projects (greater than 20 MW). (See New York Issues 10 GW Solar Roadmap for 2030.)

McGowan Southworth, a solar advocate and consultant said owners of small buildings that have taken out solar loans tied to the value of solar production under the NY-Sun program will not be able to make monthly loan payments if Con Edison doesn’t distribute value stack credits accurately and consistently.

“This would in turn harm their credit [and] also erodes fragile trust between the end customer and all parties related to solar, utility and PSC included,” Southworth said. “Would the PSC allocate funds for auditing community solar accounts on behalf of subscribers who are otherwise bearing this cost and administrative headache?”

Cost Concerns

New York utility customers already are overburdened and contribute billions of dollars annually to a large and rapidly growing list of customer-funded programs and initiatives, said Multiple Intervenors (MI), an ad hoc group of more than 50 large commercial, industrial and institutional energy consumers.

The state’s economy is continuing to experience the disruptive impacts of the COVID-19 pandemic, as well as energy prices that have skyrocketed this year, the group said.

MI asked for scrutiny of costs, as it did recently regarding National Grid transmission projects proposed for western New York. (See Large NY Consumers Oppose National Grid Tx Upgrades.)

“The solar roadmap fails to demonstrate why certain proposed costs, such as supplementing the labor costs of solar developers, even should be funded by utility customers,” MI said. “The commission … should evaluate such proposals collectively with the other programs and initiatives that customers already are being required to fund. This type of comprehensive evaluation is long overdue and should be undertaken expeditiously.”

NY Solar Comparison (NYSERDA) Content.jpgC/I projects sized between 1-5 MW occupy an important space in New York’s solar portfolio, with economies of scale producing lower development costs compared to residential rooftop and small commercial sectors. | NYSERDA

New York City said it supports expanding incentives, noting that for Con Edison customers, the average bill impact in 2024 — the year of highest impact — is estimated to be 0.52% for residential customers and 0.97% for commercial and industrial (C&I) customers.

“The estimated bill impacts are modest and reasonable when weighed against the benefits that customers should realize in return for their investment,” the city said. Solar developer Ecovis Group said the rules requiring the payment of prevailing wages for distributed energy resources over 1 MW will tax the finances of small local companies.

“We are asking the PSC to add requirements for monthly progress payments to the contractors for work completed the previous month. This will help to offset cash flow changes,” Ecovis said. “Developers are going to receive additional funds through [New York State Energy Research and Development Authority] grants; however contractors will bear the brunt of the cash requirement.”

Climate Jobs NY, a coalition of labor unions representing 2.6 million workers in the state, said it supports the program expansion, which the state says should create 6,000 new jobs.

Developer Incentives

The New York Power Authority said it supports the roadmap, but that uncertainty around the availability of future incentives has caused customers working with NYPA to hesitate on committing to new projects.

“This observation is particularly pronounced amongst customers in Con Edison’s service territory, where project economics are challenging due to high labor and installation costs, along with the siting constraints inherent to the region’s dense urban environment,” NYPA said.

A group of environmental organizations including Scenic Hudson, Natural Resources Defense Council and the Sierra Club said that NY-Sun should include an incentive for projects that include agrivoltaics — the co-location of solar-powered projects and agriculture — similar to those for landfill, brownfields and parking canopy projects.

“Providing such incentives in the NY-Sun program will have several benefits, including achieving distributed solar targets, supporting the agricultural economy, and promoting community acceptance of projects in rural and farming communities that might otherwise object to projects as a threat to farmland and community character,” the environmentalists said.

The Joint Utilities, representing the investor-owned utilities in New York, said they are developing a pilot to bring more solar energy to underserved communities in support of the state’s expanded target.

“In addition, the mid-point review should explore more funding sources and evaluate incentive levels so that necessary modifications can be made before funding is exhausted,” the utilities said.

New York City said Con Edison deserves a bigger slice of the incentive pie, given its outsize share — 39.6% — of total electricity sales in the state.

The city supports the proposal to segment Con Edison incentives based on system size, which will ensure that smaller projects can continue to be built.

The city recommended, however, that the commission modify the roadmap’s proposals for Con Edison and create three tiers of incentives for non-residential projects versus the proposed two tiers. The city also called for reducing the base incentives for non-residential projects to encourage up to 568 MW of new distributed solar in Con Edison’s territory. It also said the state should re-allocate some of the base incentive dollars to increase the proposed community adder for community solar projects in Con Edison’s territory.

Community organizers WE ACT for Environmental Justice said that “a proposal of this size, without comprehensively planning for equitable outcomes, could do more harm than good,” and that the investment must comply with the statutory requirement that disadvantaged communities receive 40% of overall benefits of state spending on clean energy and energy efficiency programs.

“Right now, the only benefit being accounted for and attributed to disadvantaged communities is bill discounts of 10%. The benefits of distributed solar are plentiful, and bill discounts are one very small piece of that pie,” said WE ACT policy director Sonal Jessel.

Posted on

Stakeholders Divided on MISO Long-range Cost Allocation’s Fairness

MISO’s subregional cost-allocation plan for its long-range transmission projects had both fans and critics at FERC this week.  

The RTO has proposed a 100% postage stamp allocation to load for the long-range projects, limited to two of its subregions, in a filing at FERC. Entities had until Monday to file comments, protest or intervene (ER22-995).

Industrial customers denounced the cost recovery plan, arguing against the sub-regional allocation for yet-to-be-determined projects. Consumers Energy said it was concerned that the grid operator hadn’t yet shared specific calculations of benefits for actual projects.

Others said the RTO’s separate-but-equal allocation application is inherently unequal.

MISO hopes to have the allocation plan, limited to its Midwest and South regions, in place by mid-May. The first long-range projects, all in MISO Midwest, are targeted for board approval in June.

WPPI Energy said if FERC accepts the filing, it should “prevent” MISO from violating the commission’s cost-allocation principles by requiring the RTO to explain when it will use a subregional versus region-wide cost recovery. The grid operator should also defend its strategy to use a different allocation design for the final two cycles of projects in its long-range transmission plan, WPPI said. The utility said it might be unfair to employ a different cost allocation once MISO begins planning long-range projects in its South subregion.

The recovery design relies in-part on a Brattle Group analysis that shows Midwestern projects are unlikely to produce benefits that seep into MISO South unless the subregional transmission transfer capacity limit is increased. Multiple stakeholders have said they’re hopeful that the long-range planning effort’s third and fourth cycles produce a project that broadens transfer capability between Midwest and South.

Staff have repeatedly said the RTO’s postage stamp rate separated by subregion is meant to be temporary and only applies to the first two project cycles. The grid operator has already begun stakeholder talks on a more permanent allocation design. (See MISO Seeking New Tx Cost Allocation for Major Buildout.)

Other stakeholders told FERC the plan represents the best option for now.

Americans for a Clean Energy Grid said the cost allocation design will confront an “existing roadblock to regional transmission development.” The group said FERC should permit flexibility in cost allocation “if it enables regions to gain stakeholder support for new transmission expansion.”

NextEra Energy said it “strongly supports” the proposal because it’s a step toward developing necessary transmission infrastructure.

The Organization of MISO States said it supported both the bifurcated postage-stamp approach and the plan to create a new allocation methodology for the second half of long-range projects.

DTE Electric said the establishment of two separate cost-sharing subregions is appropriate because it follows FERC’s “roughly commensurate” benefits standard for allocation.

DTE also asked that MISO include tariff language that ensures staff and members also consider customer affordability when planning new transmission.

“Customer affordability metrics should be established and used as a tool in the planning process to ensure that transmission investment is financially feasible for customers across the entire MISO footprint,” DTE wrote.

Entergy, which accounts for the lion’s share of MISO South, also supported the filing. The utility said although the plan was “not perfect,” it characterized a compromise among stakeholders. Entergy also noted that MISO Midwest “is clearly at the forefront of the portfolio transition that MISO describes as a driving force behind” its long-range transmission plan.

Chairs of the Senate and House energy committees in the Minnesota legislature wrote to “stress the urgency of MISO’s long-range transmission planning process to affordably allow carbon-free energy to be built at the scale required and demanded in Minnesota.” They said the state’s utilities, including Xcel Energy, Great River Energy and Minnesota Power, “are some of the most forward-looking utilities on clean energy in the country.”

Posted on

ISO-NE Announces Capacity Auction Results After Killingly Delay

Capacity prices in Southeast New England fell to $2.639/kW-month in Forward Capacity Auction 16, a 34% decrease from last year’s auction, ISO-NE reported Wednesday. The total cost of the FCA 16 was $1.04 billion, a $320 million (24%) drop from 2021.

ISO-NE said the auction procured 32,810 MW of capacity for the 2025/26 period.

Prices were mostly flat outside of the Southeast zone, coming in at $2.531/kW-month in Northern New England and Maine, and $2.591/kW-month in Rest of Pool.

“New England’s clean energy transition is well underway, and the region’s wholesale markets are playing a vital role by sustaining a reliable power system, maintaining competitive prices and creating opportunities for the resources that will be the backbone of our clean energy future,” said Robert Ethier, ISO-NE’s vice president for system planning.

Nearly 5,000 MW of renewables, energy storage and demand resources cleared the auction, making up 15% of the total capacity, ISO-NE said. That includes more than 700 MW of energy storage, 500 MW of solar generation and 275 MW of existing wind generation.

Resources worth 256 MW submitted retirement bids, all of which cleared, and 1,540 MW worth of generation was delisted.

No Delist for Merrimack Power

The owner of New England’s last active coal plant, Merrimack Station, submitted a static delist bid, seeking to remove its two units from the capacity auction if prices dropped below a certain point (the dynamic delist bid threshold).

But the bid was rejected by ISO-NE’s Internal Market Monitor, which reviews delist requests, and subsequently withdrawn by the operator of the plant.

Resources successfully submitting retirement bids included Potter II, a 96-MW combined cycle plant owned by Braintree Electric Light Department; two units at Schiller Station in New Hampshire, which shuttered in 2020; and two units burning kerosene and gas at the West Springfield Generating Station.

Information about which individual resources cleared the auction will be published when ISO-NE sends its filing to FERC, expected to occur as early as next week.

A Disjointed Process 

The results were delayed by several weeks because of the uncertainty over the Killingly Energy Center, which won a last-minute stay from the D.C. Circuit Court of Appeals allowing it to temporarily take part in the auction. (See Killingly Uncertainty Could Delay Capacity Auction Results Another Month.)

ISO-NE ended up tallying results both with and without Killingly participating, and when the Connecticut natural gas plant under development by NTE Energy ultimately lost its appeal at FERC and forfeited its financial assurance, the grid operator was able to confirm that it would be using the results without the plant.

Killingly’s exit from the market had an effect on the auction’s outcome, said Dan Dolan, president of the New England Power Generators Association.

FCA 16 vs 15 (ISO-NE) Content.jpgPrices dropped sharply in Southeastern New England in FCA 16 vs. FCA 15, pushing overall costs down by nearly one-quarter. | ISO-NE

 

“We saw with the removal of Killingly less supply than the prior year’s, and when matched with the lower demand this year versus FCA 15, it led to relatively flat pricing overall,” Dolan said. “There are continued historically low capacity prices across the board.”

NEPGA’s members have been frustrated with the uncertainty created by the Killingly delay, Dolan said, but they are relieved that the results have been released and that the grid operator is working quickly to start the process for next year’s FCA 17.

“There is a feeling of ‘we can make this work.’ This is now a manageable timeline and process overall,” he said.

Posted on

New Jersey Tees up Funding, Guidebook to Boost EV Charger Installations

New Jersey plans to boost the number of EV chargers in the state with $4 million in funding from the Volkswagen settlement and a new guidebook to help municipalities efficiently move proposed charging stations through the permitting process.

The money — part of the state’s share of the carmaker’s settlement for false reporting of vehicle emissions — will go to the New Jersey Department of Environmental Protection’s (DEP) It Pay$ to Plug In program for a second round of grants that will add conveniently located charging sites to the 636 public chargers already installed and in operation across the state.

The DEP will start accepting applications on Monday for awards that can be used to install Level 1, Level 2 or DC fast chargers. The deadline for applications is May 14.

The state’s new, 28-page guidebook, “Charge Up Your Town: Best Management Practices to Ensure Your Town is EV Ready,” is intended speed up those installations by helping towns and cities evaluate EV charger projects and expedite their permitting. The book was put together by the DEP, the New Jersey Board of Public Utilities (BPU), the New Jersey Department of Community Affairs and stakeholders, including two independent transportation agencies.

“With this guide, we are equipping towns with a roadmap to help develop cost-effective EV charging infrastructure,” said Lt. Governor Sheila Y. Oliver, in a Tuesday release announcing the guidebook’s publication. “Taking these steps is part of our administration’s larger strategy to help the state meet its climate goals.”

The DEP expects the Plug In program to award between 20 and 53 grants that will cover the cost of installing and maintaining Level 1 and 2 chargers and DC fast charger projects. Eligible locations include public areas, multi-unit dwellings and private sites, such as workplaces, with a maximum grant of $200,000 per location.

Gov. Phil Murphy has committed $10.8 million, or about 15 percent of the state’s share of funds from the Volkswagen settlement to the installation of electric charging stations. The first round of It Pay$ to Plug In awarded $3.2 million in grants to install 535 chargers with 842 ports in four counties and more than 40 municipalities. Funded projects — not all of which may be complete and in operation yet — are located at public sites, multi-family housing and workplaces.

The manual includes sections detailing different types of chargers and what they are used for, how to reduce the time and effort needed to ensure charging stations meet zoning, construction and building permit requirements, and the varied fee structures charging stations can use to generate revenue.

The introduction to the guide states that it is “intended to help municipal staff and their communities understand the context for the statewide EV ordinance, and the considerations relevant to municipalities as they take steps to support the state goals of increasing access to electric vehicle charging infrastructure.”

EV Charger Targets

Charger availability is key to Murphy’s goal of converting the state to 100% clean energy by 2050, and dramatically cutting emissions from the transportation sector, which generates 43% of the state’s greenhouse gas emissions.

The state wants 330,000 passenger and light-duty EVs on the road by 2025. The targets for chargers are at least 400 DC fast chargers at 200 or more locations and at least 1,000 Level 2 chargers — those with a 240-V electricity source — by December 2025.

In addition, a state law passed in 2020, S2252, sets a deadline of December 2025 for having at least 100 charging sites in community locations, such as such as a town centers, commercial areas, retail centers and multi-unit dwellings.

A network of chargers spread evenly across the state would help to assuage the concerns of prospective EV drivers who might be reluctant to buy battery-powered cars due to concerns that the batteries might run out with no charger nearby.

That need for “geographic distribution” across the state means that the location of a proposed site will play a big part in whether a proposed DC fast charger site will get second-round funding, Andrea Friedman, supervisor in the DEP’s electric vehicle program told a recent online seminar held to explain the program to potential applicants.

“We want them to be convenient, and we want them to be visible in communities,” she said. “We want to give people the confidence to go out and buy electric vehicles because they know there will be chargers nearby.”

Time is of the essence, she said.

“We’re looking for projects that are shovel-ready,” she said. “What that means to us is that you will be able to begin the process as soon as the DEP makes the award. If you’re planning a project that can’t be installed for two or three years, that won’t work for this grant program.”

State Charger Incentives

The It Pay$ to Plug In program is the latest of a raft of state and federal initiatives designed to boost the availability of chargers in New Jersey.

The federal Joint Office of Energy and Transportation rolled out the first round of state funding for EV charging from the bipartisan Infrastructure Investment and Jobs Act in February, with New Jersey slated to receive more than $15.4 million in 2022. To qualify for the funds, the state will be required to submit a plan detailing how it will use the money. (See States to Get $615 Million for EV Charging from IIJA Funds.)

In parallel, the BPU is pursuing two straw proposal processes, one to set out the rules to induce private investors to install Level 1 and Level 2 chargers around the state and another to deploy chargers for medium- and heavy-duty electric vehicles.

In September, the board also launched a $4 million incentive program to install chargers on main traffic corridors and at tourist hotspots, especially at the Jersey Shore, to attract more visitors to the state.

And in December, the BPU authorized a program to promote the installation of chargers in multifamily buildings by offering a $1,500 incentive for Level 2 chargers installed in apartment, condominium or mixed-use residential buildings. The program also will pay half of the project’s “make-ready” costs — for installing the wiring required for a charger — up to a total of $5,000.

Murphy in July signed two bills designed to make it easier to set up electric vehicle charging stations. One made the installation of electric vehicle supply equipment or a make-ready parking space a permitted use under municipal zoning laws, removing the sometimes lengthy and expensive task of getting a zoning variance to install a charger. The second bill required that any redevelopment plan approved by a municipality must include EV charging infrastructure as part of the planning for the redevelopment or rehabilitation of the area. (See NJ Cuts Permitting Obstacles for EV Charging Stations.)

Picking ‘User Friendly’ Locations

The Plug In program awards grants in two tracks, one to cover costs to purchase and maintain Level 1 chargers (120 V) with up to five ports, and the second for Level 2 chargers (240 V) with at least two charging ports. The program will offer up to $750 per Level 1 port and up to $4,000 per Level 2 port in a “first come, first served” system, the DEP’s Friedman told the online seminar.

Grant awards for DC Fast chargers, which use a 480 V source, will be made in a separate, competitive solicitation, she said. These chargers must be in a “community location,” with maximum grants of $200,000 per location, according to the program rules.

The program will not fund the expansion of existing sites because the DEP wants to stimulate the deployment of chargers across the state. Fast charger applications must include plans for at least two 50 kW chargers that are “available exclusively to the general public,” Friedman said.

On top of that, she said, “they must be user friendly.”

“That means well-lit, open 24 hours a day, seven days a week all year round,” she said. “They must accept credit cards. They can use other forms of payment, but they must accept credit cards, and they must display pricing information.”

“We’re also very interested in locations with amenities within walking distance, maximum a quarter mile,” Friedman said. “The closer, the better. We’re looking for locations with bathrooms, food, coffee, retail. And the reason is: people will be spending 20 or 30 minutes or more at these sites, and we want them to have a good charging experience and have something to do while they’re at the chargers.”

Posted on

EPA Restores California Tailpipe Standards

California and other states can again enforce tailpipe emissions rules that exceed federal regulations following EPA’s repeal Wednesday of Trump-era actions that revoked state authority to enact higher standards.     

The decision also restored California’s mandate that all new passenger vehicles sold in-state must be emissions-free by 2035.

The Trump-era actions were “decided in error and are now entirely rescinded,” EPA said in a summary of its decision. “With this action, California’s authority under the Clean Air Act to implement its own greenhouse gas emission standards and zero-emission vehicle sales mandate is restored.”

Since the 1970s, California has had waivers from the federal government to adopt its own stricter vehicle emissions rules because of “compelling and extraordinary conditions,” including Southern California smog. In 2013, the state received its latest waiver under the federal Clean Air Act to pursue the state Air Resources Board’s Advanced Clean Cars program, with tough restrictions on greenhouse gas emissions and the zero-emission vehicle mandate.

Sixteen other states and the District of Columbia enacted the California GHG rules with federal permission.

In September 2019, the Trump Administration adopted the Safer Affordable Fuel-Efficient Vehicles Rule Part One: One National Program Rule (SAFE-1). Under SAFE-1, the National Highway Traffic Safety Administration declared that state regulation of carbon dioxide emissions from new cars intruded on federal regulation of fuel-economy standards and was preempted by federal law.

EPA withdrew California’s 2013 waiver based on NHTSA’s actions and its own interpretation that the state did not need its GHG emissions standards and zero-emission vehicle mandate to address the compelling and extraordinary conditions that had prompted the waiver. Interpretations of SAFE-1 also prevented other states from adopting California’s GHG emissions standards.

On his first day in office, President Biden issued an executive order directing federal agencies to review SAFE-1 and other Trump administration rulings. EPA said it was reconsidering the previous administration’s withdrawal of California’s waiver in April 2021, as EPA Administrator Michael Regan called the withdrawal “legally dubious.”

On Wednesday, Regan said, “We proudly reaffirm California’s longstanding authority to lead in addressing pollution from cars and trucks. Our partnership with states to confront the climate crisis has never been more important. With today’s action, we reinstate an approach that for years has helped advance clean technologies and cut air pollution for people not just in California, but for the U.S. as a whole.” 

Environmental groups praised the decision, saying the cutting-edge actions of California and likeminded states had pushed automakers to produce lower-emissions vehicles nationwide.

“States have long been leaders in cleaning up tailpipe pollution, and the EPA is absolutely right to recognize this,” Luke Tonachel, director for clean vehicles and fuels at the Natural Resources Defense Council, said in a statement.

“While the previous administration tried to undermine this authority, the law clearly gives California and other states the ability to adopt standards to curb the pollution affecting the health of their citizens,” Tonachel said. “Reaffirming this legal authority will protect public health and help address the climate crisis.”

Posted on

Texas PUC Pushed on Reliability Charges

The one-year anniversary of ERCOT’s near grid collapse during last February’s disastrous winter storm was marked by a glut of reports, webinars and opinion pieces recapping what went wrong and detailing the changes made to ensure it doesn’t happen again.

Connect the Texas grid to the rest of the country, said an energy institute. Because about 61% of Texan households now use electric heat, a group of academics determined that ERCOT’s grid is more susceptible to cold weather. Another university study posited that 100% clean energy and renewable energy would prevent blackouts.

One politician said Texas fixed its problems quickly because it isn’t connected to the national grid, while another wrote that Texas is on the right track. An energy fellow at the University of Houston blamed the problems on the energy-only ERCOT market, which places all the risk on the consumer.

The truth is out there. Somewhere.

Yes, the grid has survived three cold snaps and an arctic front, but none of them was as severe as last year’s winter storm. The lights and heat stayed on, but not before raising anxiety levels among Texans still suffering from PTSD.

Alison Silverstein (Texas Tribune) Content.jpgAlison Silverstein | Texas Tribune

During one of her many recent webinar appearances, energy consultant Alison Silverstein didn’t wait for questions on the grid’s performance, asking them of herself. She said the grid is in better shape than last year with “lots more to do” but that ERCOT’s performance during these latest cold-weather events are not proof that everything is fixed. (See ERCOT Breezes Through Latest Winter Storm.)

“Absolutely no,” Silverstein said during a panel discussion last month set up by Advanced Power Alliance. Last month’s weather “was not enough of a stress test to really show that the grid is better.”

ERCOT’s regulator, the Public Utility Commission of Texas, has made several major changes, directed by the numerous power-related bills lawmakers passed last year. Power plants have been ordered to winterize, with ERCOT conducting inspections and the PUC penalizing those that have failed to comply.

The commission has also lowered the price cap from $9,000/MWh to $5,000/MWh; the previous commission set prices at the old cap for four days during last year’s storm, resulting in $45 billion in market transactions that week and several bankrupt participants. Ancillary service prices have also been limited after last year, part of several tweaks around the edges in what is called Phase 1 of the market improvements.

At the PUC’s prodding, ERCOT has been practicing a “conservative” approach to operations, calling on more reserves more quickly and increasing the number of reliability unit commitments (RUCs). London Economics said in a recent study that 96% of the RUCs last year were to maintain additional online reserves and not for resolving local issues.

“That is a good thing in terms of having more resources ready to operate, but we’re also paying a bundle to make that happen, and we haven’t had any public accounting of that those costs yet,” Silverstein said.

Partnering with the Texas Consumer Association, Silverstein filed a petition with the PUC asking it to direct ERCOT to calculate the costs spent on grid reliability. The filing says the reliability costs, along with a 36% increase in natural gas prices from April 2020 to February 2022 and new charges for securitizing generator and retail electric providers’ losses during the storm, “are being passed through higher electric bills” to the 27 million individuals the grid operator serves.

“The rough information available in the PUCT proceedings to date suggest that costs could exceed several billion dollars for past [Winter Storm] Uri costs (which will not improve future reliability) and at least another billion for recent reliability improvements,” Silverstein wrote.

During a one-on-one interview with PUC Chair Peter Lake as part of a weeklong virtual symposium, “The Winter Storm, One Year Later,” Texas Tribune CEO Evan Smith said he had been told ERCOT had spent $25 million procuring reserves during one day of the arctic front and as much as $500 million since the middle of last year.

Asked to confirm the numbers, Lake deferred to ERCOT.

“I don’t know the numbers off the top of my head, but yes, more reliability costs more … and we know we need more reliable power in Texas,” Lake said.

Doug Lewin 2022-03-02 (RTO Insider LLC) FI.jpgDoug Lewin, Stoic Energy | © RTO Insider LLC

Stoic Energy President Doug Lewin harkened back to ERCOT CEO Brad Jones’ September testimony to the state Senate Business and Commerce Committee. Asked about the RUC costs, Jones estimated that they were $40 million/month during the summer.

“That’s a lot of money for consumers to shoulder, potentially a 5 to 10% surcharge on top of already higher bills,” Lewin said. “These numbers are rough estimates. I’d love to replace them with more accurate figures, but we need transparency from ERCOT and the PUC on these costs.”

Lewin estimated $1 billion in additional reliability costs, assuming ancillary service costs have gone up two or three times from 2020’s $381.5 million bill and $50 million in monthly costs since the summer.

On Tuesday, Jones told RTO Insider that those numbers are way off. He pointed out that the $40 million was the cost during summer months for all ancillary services and said that ancillary costs were $270 million from last summer through early February.

“To put that into context, that’s less than $1 a customer per month, on average,” Jones said.

He said staff assumed 380 million MWh of energy production in ERCOT, with the average consumer using about 1 MWh/month in deriving the figure, with RUC costs being “shockingly low.”

ERCOT’s annual RUC report shows there were 3,853.1 effective RUC resource-hours in 2021, up from 220.1 in 2020. Total RUC make-whole payments were about $5.3 million last year and were covered through capacity short charges, staff said, with about $3.1 million in excess profits clawed back from generators. In 2020, those numbers were about $404,000 and $484,000, respectively. (See “RUC Usage Skyrockets,” ERCOT Technical Advisory Committee Briefs: Jan. 31, 2022.)

“These actions have also moved us significantly toward a capacity market since these are mostly out-of-market capacity payments,” Lewin said. “Whatever you think about capacity markets, those decisions should be made with transparency, not by opaque regulatory changes.”

Posted on

Landfill Methane Bills Near Passage in Washington Legislature

Washington’s Senate last week voted 30-17 to approve a revised House bill to regulate methane emissions from landfills.

The amended bill (HB 1663) now goes back to the House, which passed the original 57-40 on Feb. 11. Most, but not all, legislative Republicans have opposed the measure.

“We know that methane is one of the deadliest greenhouse gases,” Sen. Liz Lovelett (D), who shepherded the bill through the Senate, said Friday.

“Methane stays in place for 10 years instead of 100 years, but it has 100 times the impact of carbon emissions,” HB 1663 sponsor Rep. Davina Duerr (D) said at a Jan. 10 hearing on the bill, which would require the capture of methane emissions from Washington’s landfills.

On Friday, Sen. Shelly Short (R) said Republicans want more incentives built into the legislation to encourage converting captured methane into energy.

At the Feb. 11 House vote, Rep. Mary Dye (R), the GOP environmental issues leader in the House, argued that it is a mistake to regulate methane in landfills before gas-capture technology is more advanced. “This bill is going into an area that we have not thoroughly vetted on their impacts to the communities. … When you put a regulation in, you stop innovation at that moment,” she contended.

In broad strokes, Duerr’s bill would require the owner or operator of an active covered landfill with 450,000 tons or more of waste in place to calculate the quantity of gas generated by the landfill. The same requirements would apply to closed landfills holding at least 750,000 tons. Washington has 24 landfills that store more than 450,000 tons of waste, according to the state’s Department of Ecology. And it has at least a couple dozen — mostly closed —that store less than 450,000 tons.

If a landfill’s emissions calculations exceed 3 million Btu per hour, the operator would have to install and operate a gas collection and control system. A collection system would also be required if methane emissions hit 500 parts per million (ppm), as determined by instantaneous surface emissions monitoring, or if an average methane concentration reaches 25 ppm based on integrated surface emissions monitoring.

The bill does not apply to landfills that handle solely hazardous wastes or only inert waste or non-decomposable wastes.

California and Oregon already have similar landfill emissions rules in place. (See Oregon Adopts Nation’s Strictest Landfill Emission’s Rules.)

Methane accounted for 10% of the nation’s greenhouse gas emissions in 2019, according to the EPA. EPA figures show that landfills account for 17% of the nation’s emitted methane, behind fuel production at 30% and livestock-related emissions at 27%. A 2021 Penn State study concluded that EPA might be underestimating the nation’s methane emissions.

Cutting Waste

The Senate on Thursday also voted 34-14 to pass another amended House bill that would cut methane emissions from the state’s landfills by reducing the waste placed into them. The tweaked legislation has also gone back to the House for approval.

The bill (HB 1799) by Rep. Joe Fitzgibbon (D), chairman of the House Environment and Energy Committee, calls for the state to reduce the volume of organic material dumped into landfills to 75% below 2015 levels by 2030. Organic material — manure, yard wastes, food wastes, wood and garden wastes — contribute to the production of methane.

The House passed the bill 52-46 mostly along party lines on Feb. 11.

HB 1799 would not apply to cities and counties with fewer than 25,000 people or those that produce less than 5,000 tons of wastes annually. Also exempted would be rural areas with a population density of less than 75 people per square mile.

The bill would require a business generating at least 8 cubic yards of organic wastes annually to have an organic materials management plan by Jan. 1, 2024, while businesses generating 4 cubic yards of such waste must implement plans by Jan. 1, 2025. The Ecology Department would be tasked with reviewing the rules in 2026 to determine if they need changes.

Posted on

Vermont Climate Council Extends Deadline to Find TCI-P Alternative

The Vermont Climate Council is planning to extend its original timeline to find a replacement for the Transportation and Climate Initiative Program in the state’s interim Climate Action Plan.

An alternative to the proposed multistate cap-and-invest program is needed to fill a 26% gap in the emission-reducing actions of the council’s interim plan, released Dec. 1. The council expected to recommend Vermont join TCI-P, but it changed course in November after Connecticut, Massachusetts and Rhode Island said they no longer planned to implement the program.

The abrupt turnaround forced the council to release its plan with a promise to further study transportation emissions-reducing options and recommend a final course of action by June.

A task group in charge of that study told the full council on Monday that it plans to extend the June deadline to November. The council did not oppose the new timeline.

“We need a little bit more time to begin to really lay out the characteristics and potential benefits and ramifications of different approaches,” said Council Member Johanna Miller, energy and climate program director for the Vermont Natural Resources Council.

“Most of our recommendations are likely going to require some legislative support,” she said.

The Vermont legislature adjourns in May, so legislators would not take up any transportation sector recommendations made in June until they reconvene in January 2023. Delaying until November, Miller said, will give the task group more time for analysis and public engagement while ensuring they give policymakers time to draft potential legislation.

Initial study by the group will focus on understanding the framework for joining the Western Climate Initiative and the possibility of creating a Vermont-only Clean Transportation Standard. (See Without TCI-P, Vt. Will Explore Joining Western Climate Initiative.)

Biomass Actions

Members of another task group in charge of finding a resolution to outstanding issues related to biomass in the climate plan said Monday that they may seek a similar deadline extension for their work.

Before adopting its interim plan, the council chose to table proposed actions on biomass for further study, with a plan to release final recommendations in June.

Biomass is a “complicated topic,” said Council Member Richard Cowart, a principal at the Regulatory Assistance Project. “It has multiple arms and legs to it, and I think it’s going to take [the task group] some time to work through the issues.”

The group has met already to identify its study scope, but the topic intersects with other climate plan segments that the council has adopted already, according to Billy Coster, co-chair of the Agriculture and Ecosystems Subcommittee and director of natural resources planning at the Vermont Agency of Natural Resources.

“Trying to understand exactly where those intersects exist and how far the council would like us to go down those paths is important,” Coster said.

Central to the task group’s work will be reconsidering the preliminary biomass actions that the subcommittee presented to the full council and that the council agreed to table. Those actions called for identifying how biomass for thermal heat generation can support the transition away from fossil-fuel heating without having a net effect on Vermont forests. They also included a prohibition on expanding or building large-scale electric generation biomass facilities in the state.

The subcommittee recommended that any policy or regulation for biomass account for all greenhouse gas emissions associated with fuel production, such as extraction and transportation, in-state or out-of-state. Vermont currently relies on an in-state, sector-based GHG inventory for tracking emissions, but a supplemental analysis of lifecycle emissions related to energy use is in the works, according to Council Member Jared Duval, executive director of the Energy Action Network.

When discussing the nuanced issues related to biomass, Duval said, council members must rely on the “latest and highest quality available science and analysis.”