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November 15, 2024

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WestConnect Tx Cost Allocation Plan Rejected by FERC

FERC last week rejected a proposed settlement agreement intended to resolve a longstanding appeals court dispute over how to implement Order 1000 in the WestConnect planning region (ER22-1105).

WestConnect covers parts of Arizona, California, Colorado, Nebraska, Nevada, New Mexico, South Dakota, Texas and Wyoming. It includes FERC-jurisdictional public utilities that are subject to the requirements of Order 1000 as well as several nonpublic utilities not subject to the order.

Order 1000, which FERC issued in 2011, requires jurisdictional utilities to participate in regional transmission planning and to develop a process for allocating costs for projects selected through the planning process.

The settlement agreement rejected by FERC on Thursday was negotiated by nine WestConnect public utilities, including Arizona Public Service; Black Hills Colorado; Black Hills Power; Cheyenne Light, Fuel and Power; El Paso Electric; Public Service Company of Colorado; Public Service Company of New Mexico; Tucson Electric Power; and UNS Electric.

The dispute at issue in the settlement agreement originated in 2012, when WestConnect public utility transmission providers submitted a series of compliance filings in response to Order 1000. FERC rejected several filings related to how the planning group would handle regional cost allocation, but it accepted a proposed participation framework that allowed non-jurisdictional utilities to choose to participate in the WestConnect planning region as either enrolled members subject to binding regional cost allocation or as “coordinating transmission owners” (CTOs) not subject to allocation.

In 2016, the 5th U.S. Circuit Court of Appeals vacated FERC’s decision to accept that framework, concluding that the commission had failed to provide a reasoned explanation for doing so.

The commission provided its explanation in an order on remand, saying that, after considering alternatives, it continued to believe the approved framework could “ensure just and reasonable rates while taking into account the uniquely integrated nature of the transmission systems of public and nonpublic utility transmission providers in WestConnect.” It also explained that nonpublic utilities in the region would be incentivized to participate in cost allocation because projects from which they would receive benefits would be less likely to advance without their participation.

In December 2017, the commission denied a request by the WestConnect utilities to rehear the order on remand. The utilities, contending that the original issues had not been resolved, then petitioned the 5th Circuit, where their appeal is still pending, having been subject to a stay until Tuesday.

New Process

Thursday’s ruling dealt with a proposal by the WestConnect public utilities to resolve the appeals court case by establishing a new framework that seeks to address concerns about free-ridership by nonpublic utilities, which the parties to the agreement believe is at the heart of the 5th Circuit case.

The proposal outlines a process by which nonpublic utilities can opt in and contractually bind themselves to regional cost allocation for projects from which they receive benefits. The plan would allow a nonpublic utility to vote on a project after opting in to cost allocation. It would also include “processes and protections” to ensure that more than one WestConnect public utility would benefit from selected projects and seeks to clarify through “defined criteria” the types of projects that are eligible for regional cost allocation.

Under the proposed plan, if the regional transmission planning process identifies a transmission need for more than one enrolled member, WestConnect will solicit proposals to address the need. The WestConnect Planning Management Committee (PMC) would then develop a comprehensive list of solutions, with each being analyzed to determine whether a CTO is a beneficiary. Any benefiting CTOs could then opt in as a “cost-bound” beneficiary.

Thereafter, any cost-bound beneficiaries for projects on the comprehensive list could vote to decide which of the projects move to a short list of potential solutions.

“The Planning Management Committee then evaluates all the transmission projects on the short list under regional cost allocation criteria to determine if each project is eligible for selection in the regional transmission plan for purposes of cost allocation,” the commission explained. Projects that meet the criteria then move to final consideration by the PMC.

The proposal also stipulates that if one or more CTOs identified as beneficiaries do not opt to become cost-bound entities for a project, but two or more enrolled transmission providers in at least two balancing authority areas are also identified as beneficiaries, then those remaining beneficiaries may unanimously vote to either allow the project to advance through the planning process, choose an alternative or request the PMC convene a new solicitation.

Inconsistent with Order 1000

In rejecting the proposal Thursday, FERC noted that a late-filed protest by LS Power obligated the commission to consider the agreement to be a contested settlement, making it subject to review under the approach outlined in FERC’s Trailblazer decision. Citing that precedent, the commission said it could not find the “overall package” in the agreement to be just and reasonable.

The commission noted that WestConnect’s current process allows a nonpublic utility to participate in the transmission planning process as a CTO without being bound to cost allocation for a selected project. However, if the CTO finds that it would benefit from a project, it can voluntarily agree to accept its share of the costs. If the CTO does not agree to accept cost allocation, the PMC reruns the cost-benefit analysis for the project after removing the benefits the CTO would have received. If the project continues to meet the required cost-benefit analysis, it remains eligible for regional cost allocation.

But in the settlement agreement’s revised process, the commission explained, the decision by a beneficiary CTO not to opt into cost allocation for a transmission project means the project cannot move ahead without unanimous approval by the remaining beneficiaries.

“Instead, the remaining beneficiaries can identify an alternate transmission project (either from an existing list or newly proposed), but if the alternate project provides benefits to any coordinating transmission owner or enrolled transmission owner that was not identified as a beneficiary of the original transmission project, the entire process begins again,” the commission wrote. “This proposed process makes it highly unlikely for a transmission project to move forward if any potential coordinating transmission owner beneficiary does not agree to become cost-bound, regardless of the potential project benefits.”

The commission also found that the proposed criteria for determining whether a project is eligible for regional cost allocation was inconsistent with the intent of Order 1000.

The commission first rejected the requirement that an eligible project must physically interconnect one or more transmission providers in more than one BAA.

“We find that this criterion is inconsistent with the requirements of Order No. 1000 because, given the large size of several BAAs within the WestConnect transmission planning region, this criterion would preclude from consideration transmission projects (including those of significant size and scope) located within a single BAA that could more efficiently or cost-effectively address the needs of multiple transmission providers,” the commission wrote.

The commission also rejected another provision in the agreement that would require that cost-bound beneficiaries must receive 90% or more of the total benefits for a project in order for the project to be eligible for regional cost allocation. FERC pointed out that the provision was similar to an earlier WestConnect proposal the commission had already rejected.

“The commission rejected this requirement because it could eliminate from consideration for selection in the regional transmission plan for purposes of cost allocation transmission projects that, even after accounting for any cost shift to the remaining beneficiaries, are the more efficient or cost-effective transmission solution for remaining beneficiaries compared to other alternatives,” FERC said.

The commission also found fault with the agreement’s requirement that a supermajority of 80% of cost-bound beneficiaries must vote in favor of making a project eligible for regional cost allocation, which proponents said was consistent with NYISO’s policy.

The WestConnect proposal omitted two provisions included in NYISO’s process, the commission noted, including requirements that a beneficiary of a project that votes against it provide a written explanation for its rejection, and that NYISO submit an informational report to FERC detailing the vote.

“Without such requirements, we are concerned that beneficial transmission projects could be eliminated from consideration without explanation or justification,” the commission said, adding that the NYISO supermajority voting requirement applies only to economic transmission facilities.

“Altogether, we find that the proposed process under the settlement agreement would impose significant restrictions on the pool of transmission projects that could be considered as more efficient or cost-effective transmission solutions for potential selection in the regional transmission plan for purposes of cost allocation, even in situations where those projects would provide significant benefits to public utility transmission providers in WestConnect that outweigh their costs,” the commission wrote.

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Hawks Key Concern in Draft EIS for Proposed Wash. Wind Farm

The draft environmental impact study for a proposed southeast Washington wind and solar farm has turned up concerns about nesting areas for the region’s ferruginous hawks.

The Washington Energy Facility Site Evaluation Council released the draft EIS Monday and will accept public comments through Feb. 1, 2023. No date has been set for when the final environmental impact report will be released. EFSEC will eventually make a recommendation to Gov. Jay Inslee on whether to approve the project.

The report looks at a proposal by Scout Clean Energy of Boulder, Colo., to build up to 224 wind turbines — each about 500 feet tall — on 112 square miles of mostly private land in the Horse Heaven Hills region four miles south of Kennewick. About 294 acres of that land would also contain solar panels.

The wind and solar project is expected to have a nameplate capacity of 1,150 MW, roughly the same output as Columbia Generating Station, a commercial nuclear reactor just north of the Tri-Cities area, which includes Kennewick.

Many Kennewick residents oppose the project because the turbines would be seen by residents on the south side of the city.

Residents also cited concern about the turbines’ effects on ferruginous hawks. While ferruginous hawks are not listed as a threatened or endangered species by the federal government, they are listed as endangered by the state of Washington. The birds are among the nation’s largest hawks, with average wingspans of 56 inches. They live in grasslands and shrub steppes, which are found extensively in south-central and southeast Washington. Shrub steppe is a mostly treeless semi-desert filled with sagebrush and a complicated ecosystem at ground level. 

About 60% of the nesting pairs are found in Washington’s adjacent Benton and Franklin counties. The Horse Heaven Hills are in Benton County.

The draft EIS identified potential impacts on ferruginous hawk habitat and populations through loss of habitat and potential mortality from collision with wind turbines.

“As these impacts could result in a high-magnitude impact on ferruginous hawks, EFSEC has proposed additional mitigation measures specific to avoiding and reducing project-related impacts on ferruginous hawks, including exclusion of turbines within core ferruginous hawk habitat and curtailing turbine operation while ferruginous hawks are present,” the draft report said.

Mitigation measures would include avoiding siting turbines and solar panels within two miles of ferruginous hawk nests. Another measure would be to stop the turbines from operating during breeding season.

The draft recommended a two-year survey of the turbines’ impacts on the area’s birds, including American white pelicans, eagles, burrowing owls, great blue herons, Sandhill cranes, tundra swans, loggerhead shrikes, sagebrush sparrows, prairie falcons, sage thrashers, Vaux’s swifts and ring-necked pheasants. The draft also recommended surveys of the area’s striped whipsnakes, sagebrush lizards, Townsend’s big-eared bats and Townsend’s ground squirrels.

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Memphis Turns Down 20-year TVA Supply Contract

The Memphis Light, Gas and Water utility remains on a five-year rolling contract with the Tennessee Valley Authority after its board of commissioners unanimously rejected a 20-year power supply contract with the federal agency earlier this month.

The Dec. 7 recommendation eliminates MLGW’s potential generation independence and MISO membership for the time being. It also avoids a long-term partnership agreement that would have immediately lowered costs but bound the municipal utility to TVA for at least two decades.

MLGW Board Chairman Mitch Graves said the contract TVA offered was “too long of an agreement.”

The contract would have cut base rate charges by 3.1%, kept the savings fixed through 2029, and allowed MLGW to acquire up to 5% of its energy needs from renewable sources. However, the agreement included a stranded-cost obligation that would have held the utility responsible for a percentage of TVA’s future investments and followed the utility if it decided to later leave TVA. The contract also stipulated a 20-year termination notice; MLGW’s current agreement has a five-year exit notice.

In a press release, the utility said it “will remain a TVA customer for the foreseeable future.” It said the decision was made “after months of public and advisory council meetings, work with consultants and internal debate.”

TVA spokesperson Scott Brooks said the verdict is a “reinforcement of the longstanding relationship with TVA in delivering affordable, reliable and clean energy to the people and communities across Memphis and Shelby County.” The agency said it looks forward to continuing a more than 80-year relationship with MLGW and its incoming CEO, Doug McGowen.

Memphis Mayor Jim Strickland in October appointed McGowen, the city’s longtime chief operating officer, as the utility’s CEO. He will replace current CEO J.T. Young.

MLGW has considered weaning itself from TVA’s supply for several years and building its own generation to tap into MISO’s system.

However, consulting firm GDS Associates told the utility that splitting from TVA and participating in MISO’s wholesale markets could cost MLGW up to $25 million annually. The consultants said the escalating cost of materials and labor would soak up any savings when studying an exit from TVA. (See Memphis Says Staying with TVA is Best Option; Inflation Dampens Possible Memphis Exit from TVA.)

“We believe the people of Memphis and Shelby County deserve a partner that cares about serving their needs and addressing real issues like energy burden and revitalization of the city’s core communities,” TVA Executive Vice President and Chief External Relations Officer Jeannette Mills said in a press release. “Our continued partnership with MLGW provides the best option for making this happen.”

TVA West Region Vice President Mark Yates said the agency plans to invest in the Memphis region. He called MLGW’s decision to remain with TVA “a positive step forward.”

The TVA did not address MLGW’s rejection of the 20-year contract option.

“TVA has been respectful and supportive of the process, and we are glad to see it come to a successful resolution. MLGW’s process has been a thorough, disciplined and unbiased consideration of potential energy suppliers,” Brooks said.

Southern Alliance for Clean Energy Executive Director Stephen A. Smith said he applauded the decision to “reject the flawed recommendation to sign TVA’s onerous long-term contract.”

“By not signing the perpetually renewing contract, MLGW maintains maximum flexibility, which we believe is critical in light of the changing utility landscape,” Smith said in a statement. “With the passage of the Inflation Reduction Act and the increasing opportunities available to municipal utilities, we believe that MLGW needs to maintain all its options going forward. We hope they’ll continue to look for further opportunities to be more independent of TVA and provide better service and power supply options for the customers in Memphis and Shelby County.”

Pearl Walker, organizer of the Memphis Has the Power grassroots group, said the MLGW board vote is “historic” and keeps its power supply’s future flexible.

During Wednesday’s utility board meeting, Walker urged MLGW to consider “cleaner, more affordable and renewable energy options” and requested it to explore opportunities for generation funding under the Inflation Reduction Act. She said it was imperative that MLGW continue weighing plans because Memphians have some of the highest energy burdens in the nation.

In a statement, Walker said a “never-ending contact would negatively impact our energy future.”

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DC Circuit Remands Conowingo Dam Licensing to FERC

The D.C. Circuit Court of Appeals on Tuesday vacated FERC’s licensing of the Conowingo Dam on the Susquehanna River in Maryland, ruling in favor of environmental groups who argued that the commission exceeded its authority under the Clean Water Act (CWA) (21-1139).

The court remanded the licensing decision back to FERC, ruling that the commission did not have the power to issue the dam a license based on the conditions of a settlement between the Maryland Department of the Environment (MDE) and Constellation Energy (NASDAQ:CEG), rather than on the department’s original CWA certification of the dam in 2018.

Describing the environmental requirements of the original certification as “unprecedented” and “extraordinary,” Constellation had filed for reconsideration from the MDE, challenged the original certification in state and federal court, and petitioned FERC to find that the state had waived its opportunity to issue a certification. The settlement was reached through mediation between the company and the department, after which the state agreed to waive the right to issue a water quality certification and allow FERC to issue a license for the dam incorporating the terms of the settlement.

The court found that the MDE backtracking on its original certification and waiving its authority to issue a certification does not fit into one of the two instances in which the CWA allows the commission to issue a license. It only allows FERC to grant a license when the state has issued a certification or “fail[ed] or refuse[ed] to act on a request.”

“This leaves no room for FERC’s third alternative, in which it issued a license based on a private settlement arrangement entered into by Maryland after the state had issued a certification with conditions but then changed its mind,” the court said.

The settlement was objected to by environmental groups in the state, including the Waterkeepers Chesapeake, Lower Susquehanna Riverkeeper Association, ShoreRivers and Chesapeake Bay Foundation, which filed a petition for rehearing before the commission and ultimately with the D.C. Circuit for review.

In rejecting the arguments from the environmental groups on rehearing, FERC argued that the CWA does not prevent a state from affirmatively waiving its authority to certify a project. The court struck down that claim when repeated by commission attorneys during oral arguments.

“Pressed at oral argument, FERC counsel went so far as to argue that ‘if we can’t conclude that Congress thought of an unnamed [potential course of action],’ by resort to legislative or congressional reports, then we must treat the course of action as available to the agency,” the court said. “That, however, is not how we interpret statutes. Our court has ‘repeatedly rejected the notion that the absence of an express proscription allows an agency to ignore a proscription implied by the limiting language of a statute.’”

Both Constellation and the MDE expressed disappointment with the ruling, with the department stating that it will “work with the Office of the Attorney General on the implications and next steps.”

“While we are still reviewing the order, we are surprised and disappointed in the D.C. [Circuit] Court’s decision to vacate Conowingo’s license renewal,” Constellation spokesperson Paul Adams said in an email. “No one who cares about clean air and the health of the Chesapeake Bay should be cheering this decision, which potentially jeopardizes the state’s largest source of renewable energy and could disrupt up to $700 million that Constellation pledged for environmental programs, projects and other payments that directly benefit water quality, aquatic life, and citizens living on and near the bay.”

The court said that vacating the license also allows further administrative and judicial review to be completed, which could result in invalidation of the original MDE certification or, in the case of its validation, for FERC to be required to license the dam according to the conditions stipulated in the certification.

The 2018 certification required Constellation to develop a plan including the reduction of nitrogen and phosphorus discharge, improvement of aquatic passage, control of debris, and improved aquatic resources and habitat protection, according to the court ruling.

During oral arguments, FERC said vacatur of the license may disrupt environmental protections included in its conditions, but the court noted that the commission’s counsel recognized that those concerns could be mitigated through interim annual licenses.

“Equally important, [the environmental groups], which brought this action for the very purpose of strengthening the dam’s environmental protections, agree,” the court said.

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SPP Hands Lucas, Kelley New VP Positions

SPP on Wednesday announced it has promoted Antoine Lucas to vice president of markets and David Kelley to vice president of engineering.

Lucas has been SPP’s engineering vice president since February 2020. His new role will have him overseeing the development, design and provision of all SPP market-based services. That will include the wholesale markets currently administered under the grid operator’s tariff and additional value-added services.

Kelley, previously SPP’s director of seams and tariff services, will replace Lucas. He will be tasked with the ongoing development of the transmission expansion plan, administering generator interconnection and transmission service study processes, regional resource adequacy policies, and other engineering studies.

SPP said Bruce Rew, senior vice president of operations, will continue to lead the organization’s real-time operations, operational planning and analysis, and reliability coordination efforts. He will also continue to oversee the RTO’s expansion into the Western Interconnection.

These changes allow SPP to continue to focus on reliable operation of the bulk electric system while managing its growing markets, it said. The grid operator has administered its day-ahead Integrated Marketplace in the Eastern Interconnection since 2014. SPP added the Western Energy Imbalance Services market in the West last year and is working with Western utilities to design its Markets+ suite of market-related services.

“Our industry is ripe for innovation on so many fronts, and SPP is well positioned to deliver a brighter future for our region,” Kelley, a 14-year employee, said in a press release.

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NJ’s EV Charging Plans Face Stakeholder Scrutiny

New Jersey’s plan for spending $104 million in funds from the National Electric Vehicle Infrastructure (NEVI) program faced a barrage of stakeholder questions last week in the first hearings into how the state will meet a federal demand to line its highways with electric vehicle chargers within five years.

State transportation, energy and environmental officials, who presented the plan during virtual hearings on Dec. 13 and 15, are seeking stakeholder input to shape the final plan through a 17-page request for information released on Dec. 2. With more than 40 questions posed in the first session alone, responses suggest the state still has numerous issues to resolve as it seeks to tap into market interest.

One stakeholder wondered if the chargers would be located on government-owned or private land (the answer was “both”), while another questioned whether the locations depicted on a map were specific sites already assigned for charging stations or just identifying the areas of general need, leaving developers to find the specific location (the latter).

A third stakeholder asked whether developers bidding to install chargers must commit to maintaining them. Yes, for five years, said Andy Swords, director of the New Jersey Department of Transportation’s Division of Statewide Planning.

How about security for drivers stopped at charging stations, asked another stakeholder, who wanted to know if the state had set out “requirements” for developers to design sites in a way that would protect users.

“We have not developed specific requirements for security,” Swords answered, adding that those requirements would be in the solicitation when it comes out.

Stimulating EV Charger Development

The RFI is part of New Jersey’s effort to address the challenges facing states across the nation as they seek to put the flow of federal NEVI money to work creating a network of EV chargers that will jumpstart the — so far — relatively slow uptake of EVs.

For the initial round of NEVI funding, states are required to identify alternative fuel corridors (AFCs), major state and interstate highways where EV charging stations would be located every 50 miles. EVs can fully recharge in about an hour using the fast-charger ports now available.

The Biden administration in September approved EV charging plans for all states, starting the flow of the first $1.5 billion of NEVI money to put chargers along 75,000 miles of highway nationwide. The administration will eventually award $5 billion in NEVI funds. (See US Completes Review of State EV Charging Plans.)

The federal government initially allowed state transportation officials to be reimbursed for staffing and activities directly related to the development of charging plans. The funds can now be spent on a variety of related activities, including upgrading and adding EV charging infrastructure; operations and maintenance costs of charging stations; stakeholder engagement; workforce development; data sharing; and mapping analysis.

Implementation phases schedule (State of New Jersey) Content.jpgInitial schedule for proposed implementation phases | State of New Jersey

 

Under the first phase of New Jersey’s NEVI plan, from 2022 to 2024, state officials will designate 12 highways as AFCs, among them two main arteries: the New Jersey Turnpike and Garden State Parkway. The state will use the funds to install four 150-kW chargers at least every 50 miles at locations less than a mile from the highway exit. (See NJ to Invest $10.8M in EV Chargers, School Buses.)

“NEVI requirements are that we have to build a set of fast-charging stations along interstate highways to achieve what’s called a fully built-out designation prior to being able to use that money in other in other locations,” Swords told stakeholders at the hearing. “So, once we have the fully built-out designation, then we can look at filling in the gaps along main roads and also with community charging.”

In the second phase, from 2023 to 2025, the state expects to focus on providing an even denser pattern of chargers with a goal of every 25 miles. In some cases, the state would look to increase funding efficiency by placing a charger at an intersection that serves two corridors, according to the plan.

The final phase, through 2026, would involve the installation of chargers that address other charging needs in the state.

“We plan to have flexible implementation of the funding based on community needs, which could include community-centric charging as well as fast-charging hubs near multiunit dwellings,” said Peg Hanna, assistant director of air monitoring and mobile sources at the Department of Environmental Protection.

One stakeholder asked how they could get a potential charger location site considered if it is in a low-income community and less than a mile from a highway.

“To the extent that the locations are consistent with NEVI requirements, they will be considered,” Swords said. “It’s possible that in New Jersey, given that it’s a densely populated state, there are communities very close to interstate highways. There may be cases where there are locations that meet those built-out requirements that also may be located in overburdened communities. And if that’s the case, they’re certainly eligible to be possible locations.”

Hanna added that the program’s bid evaluation criteria in selecting sites and projects gives additional weight to proposals for chargers located in environmental justice areas.

Revenue Share

New Jersey’s Energy Master Plan calls for the state to deploy 330,000 light-duty EVs by 2025, and state officials — as those in other states — believe a key to reaching that goal will be providing enough EV chargers to ensure drivers don’t fear their vehicle will run out of charge with no station nearby.

New Jersey is aiming to have 400 fast chargers and 1,000 Level 2 chargers in place by 2025. So far, the state has about 950 charger ports available, about a third of which are fast-charging and half are Level 2, according to the DEP’s Drive Green site. The department says about 95% of the state is within a 25-mile radius of a DC fast charger.

To help shape the state’s NEVI implementation, the RFI asks respondents, including potential applicants, to answer 17 questions. Among them are questions about how the state could maximize private investment in chargers, what could be the biggest barrier to installing chargers, and what respondents think of the state’s proposal to levy a “per site or per charger cap on available funds.”

Gov Approach to EV Ecosystem (State of New Jersey) Content.jpgWhole of government approach to NJ’s EV ecosystem | State of New Jersey

 

Other questions focus on respondents who plan to submit a bid to install chargers. The final questions ask about what respondents think is the best approach to workforce training and how they would address “clear risks in the current market environment,” such as “supply chain, labor availability and utility coordination issues.”

Swords noted that by increasing the use of EVs the state would reduce the number of gas-powered cars, reducing state gas tax revenues. That prompted one stakeholder to ask if the state is expecting a “revenue share for charging hosts” to make up for the lost.

“We’re just interested in ideas,” Swords said. “I wouldn’t go so far as to say we’re expecting a revenue share. However, we are very interested in hearing thoughts on this topic.”

Another stakeholder asked how the state anticipates the relationship between the charger host and its providing utility would work.

“First and foremost, the state of New Jersey sees [electric vehicle supply equipment] as a service, not a reselling of electricity,” said Cathleen Lewis, e-mobility program manager for the Board of Public Utilities. “So, the relationship between any of the electric companies and the and the station owner is that the station owner is responsible for paying for the electricity that they are utilizing.”

In addition, some utilities are offering incentives to charging stations, Lewis said.

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Oregon Bans Gas-powered Car Sales by 2035

Oregon’s Environmental Quality Commission voted Monday to adopt California’s rules requiring all new cars and light-duty trucks sold in the state to be zero-emission vehicles or plug-in hybrids by 2035.

Known as Advanced Clean Cars II (ACC II), the rules task automakers with providing an increasing percentage of ZEVs for sale each year, beginning with 35% in 2026, increasing to 68% in 2030 and reaching 100% in 2035.

“Adopting the ACC II rules would significantly reduce tailpipe criteria pollutant and greenhouse gas emissions and is a foundational strategy to decarbonize Oregon’s transportation sector,” Department of Environmental Quality staff wrote in a report on the plan.  

Under an executive order from Gov. Kate Brown, the state is trying to reduce greenhouse gas emissions 45% below 1990 levels by 2035 and at least 80% percent below 1990 levels by 2050. As in California, the transportation sector accounts for about 40% of GHGs in Oregon.

The rule changes are expected to reduce carbon dioxide emissions by 54 million metric tons (MMT) through 2040 and NOX emissions by 3,693 MMT by 2035, DEQ staff wrote.

The California Air Resources Board voted to adopt ACC II in August as a successor to the state’s Advanced Clean Cars regulation, first adopted in 2012 and still in effect. The current regulation requires 22% of passenger vehicles sales to be ZEVs by 2025. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)

In addition to ZEV requirements, the ACC II regulation includes a low-emission vehicle (LEV) component aimed at reducing tailpipe emissions of gasoline-powered cars.

“These changes clarify both existing definitions and testing requirements and will reduce cold-start emissions and lower maximum exhaust and evaporative emission rates,” the staff report said.

The rules also require automakers to meet minimum technology requirements, including a minimum range, battery warranty and durability requirements.

Seventeen states and the District of Columbia have adopted California’s Advanced Clean Car standards as allowed under Section 177 of the Clean Air Act. Three of those states — Oregon, Washington and Vermont — have adopted ACC II, with others expected to follow suit.

The Clean Air Act waiver granted to California decades ago and repeatedly renewed allows the state to enforce its own more-stringent tailpipe emissions standards for cars and light-duty trucks. Other states were allowed to adopt California’s tailpipe emission standards as an alternative to using federal emission standards. The Trump administration withdrew the waiver in 2019, but it was quickly reinstated after President Joe Biden took office.

In Monday’s EQC meeting, commissioners voted 4-1 to adopt ACC II.

Commissioner Greg Addington, who is from Klamath County, east of the Cascade Range, said he generally supported the goals of ACC II but could not vote for it.

Addington said he worried many residents of rural Oregon are not ready for the mandate, including those who wrongly believe it is a ban on gasoline. He also said he had concerns about the technology and infrastructure not being ready for the transition to electric vehicles.

A map of charging stations in Oregon showed them concentrated in Portland and neighboring cities and along Interstate 84, the state’s main east-west transportation route. Blue and green dots on the map marked the areas with EV chargers; the rest of the map was white.

“There’s a whole lot of Oregon in those white gaps,” Addington said. “And I just wonder still about the utility of electric vehicles in some of these places and for some jobs.”

Commissioner Amy Schlusser said she understood Addington’s concerns but said, “I think this rule is really important for Oregon. I think this is an opportunity for us to put ourselves on a more strategic and efficient path for electrifying the transportation sector.

“If we don’t adopt this rule here today, I think that the transportation system will still electrify,” Schlusser said. “We just won’t have the same number of options here. We won’t be providing that regulatory certainty to our utilities.”  

“We won’t be upgrading the grid in a real strategic, cohesive way that’s proactive rather than reactionary,” she said. “If we’re struggling to upgrade the grid as quickly as possible because we already have that demand on the system, that to me is what’s a scary scenario.”

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EPA Announces Tougher Emission Rules for Heavy-duty Vehicles

EPA on Tuesday announced stringent new emission standards for heavy-duty vehicles beginning with model year 2027.

First proposed in March, the rules mark the first upgrade of heavy-duty emission standards in more than two decades. They are aimed primarily at nitrogen oxides, pollutants that cause smog. NOX is also considered a major health hazard, especially for people living in neighborhoods near highways or manufacturing plants.

The new rules, which EPA said are more than 80% stronger than current standards, also will cover truck engines up to two and a half times longer than existing standards, resulting in engine warranties up to 4.5 times longer, according to the agency.

Fifteen-liter diesel truck engines have a lifetime of 1 million miles or longer without requiring a major overhaul, according to industry statistics, meaning a truck built today will last an average of 15 years.

“These provisions guarantee that as target vehicles age, they will continue to meet EPA’s more stringent emissions standards for a longer period. The rule also requires manufacturers to better ensure that vehicle engines and emission control systems work properly on the road,” the agency said.

There are about 3 million heavy trucks operating on U.S. highways, according to industry estimates, and of these about 800,000 are owner operated. The new NOX standards appear to address that as well, noting that “manufacturers must demonstrate that engines are designed to prevent vehicle drivers from tampering with emission controls by limiting tamper-prone access to electronic pollution controls.”

The rules will also aim to improve emissions in stop and go traffic or idling. An EPA analysis found that “current NOX controls are not effective under certain low-load operating conditions, such as when trucks idle, move slowly or operated in stop-and-go traffic.”

EPA intends to propose two additional rulemakings by the end of March 2023. Taken together, the final rules “would put in place stringent long-term standards that would reduce smog, soot and climate pollution from heavy-duty vehicles and would include consideration of greater adoption of zero-emissions vehicle technologies,” EPA noted in a backgrounder.

The announcement follows months of heavy lobbying by truck-makers concerned that stringent emission standards for internal combustion engines come at a time when the industry is slowly moving toward battery-electric and fuel cell-electric power systems.

Environmental groups cheered EPA’s action but also said more work is needed.

“After two decades of inaction, EPA is finally moving to cut harmful truck tailpipe pollution,” Britt Carmon, the Natural Resources Defense Council’s federal clean vehicles advocate, said in a statement. “But these standards fall short, and the agency missed a critical opportunity to slash soot and smog and accelerate the shift to the cleanest vehicles.

“EPA now needs to move quickly to put in place the next round of standards that will accelerate the transition to zero-emitting trucks so that we can all be free from the tailpipe pollution that is harming our health and accelerating climate change.”

Vickie Patton, general counsel for the Environmental Defense Fund, said that the “long awaited” final NOX standards will significantly reduce the pollutant and over time save thousands of lives.

But, she said, “it is also vitally important that EPA move forward swiftly to recognize protective state standards adopted by California and numerous other states and move swiftly to issue a new generation of climate and air pollution standards that recognize 21st century solutions for new model year 2027 and later vehicles — standards that leverage the Inflation Reduction Act’s game-changing investments in zero-emitting trucks.

“American manufacturers, fleets, workers and communities are seizing the historic Inflation Reduction Act and [Infrastructure Investment and Jobs Act] investments in zero-emitting trucks and buses to innovate, altogether eliminate the pollution from rolling smokestacks, and lead our nation to a healthier and brighter future.”

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Postal Service Goes Electric

Ending a bureaucratic battle with a Trump-holdover, the Biden administration on Tuesday announced that the U.S. Postal Service will procure 66,000 battery electric vehicles (BEVs) among the 106,000 vehicles the USPS plans to purchase by 2028.

The BEVs will include 45,000 purpose-built next generation delivery vehicles (NGDVs) from Oshkosh Defense and 21,000 commercial off-the-shelf Ford E-Transit vans.

Officials announced the plans at a press conference outside Postal Service Headquarters in Washington that featured Postmaster General Louis DeJoy, John Podesta, senior advisor to the president for clean energy innovation and implementation, Brenda Mallory, chair of the White House Council on Environmental Quality, and National Climate Advisor Ali Zaidi.

The bonhomie between DeJoy and the White House officials was a sharp contrast to the Biden administration’s outrage in February, when the postmaster general announced that as little as 10% of a planned purchase of 165,000 NGDVs would be battery-powered. (DeJoy, a Trump appointee, had earlier earned the ire of Democrats over cost-cutting practices that contributed to a slowdown of mail deliveries before the 2020 presidential election.)

In March, the Postal Service announced a purchase order of 50,000 NGDVs from Oshkosh, including 20% BEVs.

Under pressure from the administration, the service announced in July it would conduct a supplemental environmental impact statement and anticipated at least 50% of its NGDVs would be BEVs.

When Podesta began speaking to DeJoy in September, he told The Washington Post, he informed the postmaster general that his plans remained “completely inadequate.”

“So we stuck with it, pushed it, he pushed back, and we pushed back,” Podesta said.

Louis DeJoy John Podesta (WUSA9) Alt FI.jpgPostmaster General Louis DeJoy (left) and John Podesta, senior advisor to President Biden for clean energy innovation and implementation | WUSA9

 

At the press conference Tuesday, DeJoy said the Postal Service’s initial EV plans were limited by the need to rescue it from “an imminent financial and operational crisis that threaten[ed] our existence.”

DeJoy said it suffered from “substantial historic and projected losses, eroding market share, increasing and costly obligations to serve a defective pricing model, burdensome … legislation, a failing infrastructure, high employee turnover, ineffective organizational and operational strategies and an aging fleet of over 200,000 delivery vehicles that are best suited for museums rather than for our hard-working carriers.”

DeJoy thanked Congress and the White House climate team for collaborating with the service to overcome its financial and operational obstacles, saying the announced procurement was “an operationally suitable, financially viable and climate-friendly acquisition and deployment strategy.”

DeJoy said the service also is launching an initiative to reduce operating costs “through a massive network reconfiguration” that will reduce air cargo, handling and truck trips.

“The tremendous initiative we are now announcing today is directionally where we anticipated landing all along,” he added. “As our financial trajectory improved, as our delivery strategy evolved, and with the help of the congressional funds to facilitate our ambition, we were very well positioned to move forward with more favorable plans that everyone can rally around.”

Although most of the $9.6 billion price tag will be funded from Postal Service revenues, the accelerated transition was aided by the Inflation Reduction Act, which will provide $1.3 billion for vehicle purchases and $1.7 billion for charging infrastructure.

DeJoy said the service expects the NGDVs it acquires in 2026 through 2028 to be BEVs. “One hundred percent electric, John,” he said, turning to Podesta. “One hundred percent.”

Podesta was also gracious when it was his turn to speak, thanking DeJoy for “his personal leadership in making this day possible.”

Podesta noted that the postal service delivery van is one of the most recognizable vehicles on the road. “So it’s wonderful that the Postal Service will be at the forefront of the switch to clean electric vehicles, with postal workers as their ambassadors. It will get people thinking, ‘If the postal worker delivering our Christmas presents … is driving in an EV, I can drive an EV too.’”

Podesta noted that the Postal Service has the second highest carbon footprint of any federal agency. “So converting to clean electric vehicles is an essential part of making sure that the federal government is walking the walk on climate — and a big demand signal to the rest of the transportation sector to go electric.”

The NGDVs are expected to go into service in late 2023. In addition to not emitting carbon, the new vehicles will be air-conditioned and have air bags, unlike the vans they will replace.

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FPL Credits Grid Hardening for Fast Ian Restoration

When Hurricane Wilma hit the territory of Florida Power & Light (NYSE:NEE) in 2005, it was the culmination of a shattering two years. Beginning with Hurricane Charley the previous year, the utility had seen its disaster response capabilities stretched to the breaking point, and it was clear to all stakeholders that the time had come for reform.

“In ’04 and ’05, we got hit with seven storms in 18 months,” Manny Miranda, FPL’s executive vice president for power delivery, said at last week’s meeting of SERC Reliability’s Board of Directors. “Our customers were upset; our regulators were upset; the media was having a field day; our employees were exhausted; and we knew we had to change.”

Manny Miranda 2022-12-14 (RTO Insider LLC) FI.jpgManny Miranda, Florida Power & Light | © RTO Insider LLC

As a result of that hurricane season, Miranda said, FPL instituted its “Storm Secure” program in 2006. The improvements made under the program paid off when Hurricane Ian made landfall in southwest Florida on Sept. 28, late in an unusually quiet Atlantic hurricane season. With 150-mph winds, the storm tied for the fifth-strongest hurricane ever to hit the contiguous U.S. After moving back out to sea, Ian regained strength and made landfall again in South Carolina before finally dissipating in Virginia on Oct. 2.

In addition to causing a nationwide power outage in Cuba, more than 2 million customers in FPL’s territory lost electricity. At 157 fatalities in both countries, it was the deadliest storm to hit Florida since 1935. Despite the widespread damage, however, the restoration proceeded much more rapidly than that for Wilma; by the first day, the utility restored two-thirds of its affected customers, and full restoration was complete within eight days.

By comparison, full restoration after Hurricane Charley 17 years ago — which affected far fewer people — took 13 days. Restoring power after Wilma took 18 days; while Wilma affected more people than Ian, at Category 4 Ian was a more powerful storm than Wilma, which was Category 3 when it struck Florida.

Miranda credited the Storm Secure improvements with significantly reducing the number of outages and making the restoration process much smoother than in previous years.

One major difference in 2022 was that FPL lost no transmission structures, which Miranda attributed to the utility’s policy of replacing wooden structures with steel or concrete ones. He said that FPL expected to have all wood structures removed from its “legacy” territory — not including the infrastructure of Gulf Power, which FPL acquired in 2021 — by last week; the job should be complete in the remaining territories by 2030.

Restoration times for Storms (Florida Power Light) Content.jpgRestoration times for Hurricane Ian and several other recent storms in FPL’s service territory. Power was fully restored for customers affected by Ian within eight days, quicker than the restorations for Hurricanes Charley (2004), Wilma (2005), and Irma (2017). | Florida Power & Light

 

Additional investments by FPL in its infrastructure include burying distribution lines. The utility has provided incentives to “underground anybody that wants to go forward,” Miranda said. Though he acknowledged the impact of this program has mainly been seen in wealthy communities, he said FPL plans to have “all our main feeder lines … hardened or underground” by 2025.

The utility also upped its vegetation management program, going from trimming plants on 8,000 miles of transmission lines annually in 2005 to 15,000 miles in 2021, and installing 183,000 grid monitoring devices on its facilities, up from just 257 in 2005. In addition, FPL implemented a program to inspect all of its distribution poles, which Miranda admitted has delivered benefits beyond anything he expected.

“I will tell you … I did not agree with a pole inspection program [at that time],” Miranda said. “But what we found is, a pole inspection program is one of those unsung hero programs; they have made a huge difference in our hurricane response. We have replaced over 100,000 poles … over the last 20 years.”

Another target of Storm Secure was the response process itself; Miranda said the restoration for Ian required the mobilization of about 21,000 line workers, with 38 sites to stage, process and park resources and vehicles; 470,000 meals were served during the restoration process, with 2.7 million bottles of water and 2.2 million gallons of fuel consumed.

Asked by SERC Chair Todd Hillman “how you got to pay for all that” — noting that he had “worked with lots of state commissions in the past” — Miranda acknowledged the improvements needed significant investment from the state. He pointed out that with a $1.3 trillion economy in Florida, “every day you lose power is several billion dollars of economic impact.”

“That’s how we walk them through it,” he said.