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December 21, 2022June 14, 2023

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.jpg

Initial 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.jpg

Whole 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.

December 21, 2022

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 NO_X 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.”

December 21, 2022

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. NO_X 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 NO_X 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 NO_X 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 NO_X 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.”

December 21, 2022June 14, 2023

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.

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Postmaster 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.

December 21, 2022June 14, 2023

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.”

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Manny 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.jpg

Restoration 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.

December 20, 2022June 14, 2023

CAISO Board Elects New Chair, Vice Chair

The CAISO Board of Governors on Thursday elected a new chair and vice chair from among its members and praised outgoing Chair Ashutosh Bhagwat, who is leaving the board after 12 years of service.

Mary Leslie | LABC

The board named Mary Leslie to serve as its chair and Jan Schori as vice chair starting Jan. 1, continuing its practice of rotating leaders annually.

Gov. Gavin Newsom appointed Leslie to the CAISO board in 2019. She is the longtime president of the Los Angeles Business Council, a group that works with businesses, government and nonprofits to shape city policy. She was the deputy mayor of Los Angeles under Mayor Richard Riordan from 1994 to 1995 and a commissioner at the Los Angeles Department of Water and Power from 2001 to 2003.

“This is an exciting time to be on the ISO Board of Governors as we transition to a carbon-free power system and enhanced regional coordination throughout the West, and I am honored to have been chosen by my colleagues to serve as the chair,” Leslie said in a statement after the vote.

Jan Schori | © RTO Insider LLC

Newsom appointed Schori to the CAISO board in February 2021 following her tenure as a NERC trustee for 12 years, the maximum allowed. From 1984 to 2008, Schori worked for the Sacramento Municipal Utility District, one of the nation’s largest municipal utilities, including as its CEO and general manager, general counsel and staff attorney.

Governor Angelina Galiteva, CAISO’s first female board chair, called the election of Leslie and Schori “yet another historic moment in the history of the board of the California ISO.”

“For the very first time, due to this rotation that we’ve implemented on an annual basis, we have a female chair and a female vice chair, which has never happened before,” Galiteva said.

Newsom next will have to fill the seat left vacant by current CAISO board Chair Bhagwat, whom former Gov. Jerry Brown first appointed in April 2011. Bhagwat, a University of Davis Law School professor, plans to leave the board by the end of February or as soon as Newsom names a successor.

Ashutosh Bhagwat | UC Davis School of Law

The board plans a formal sendoff for Bhagwat early next year but recognized his service and recent tenure as chair at Thursday’s board meeting.

“Can I be as bold as to take a moment to thank you for your leadership this last year and express our deep sorrow at your family getting to spend more time with you?” Leslie said, prompting laughter. “You will be sorely missed.”

Bhagwat thanked the ISO’s board, management, staff and its stakeholder community.

“It has been a truly fantastic 12-year run, like nothing else I’ve had in my life,” he said. “I’ve enjoyed it thoroughly.”

December 20, 2022

Lacking Low-cost Power Agreement, Wash. Smelter Revival Falters

An effort to reopen Washington’s last standing aluminum plant with a lower carbon footprint faltered last week after the company backing the deal failed to secure a guarantee of low-cost power from the Bonneville Power Administration.

For more than two years, a New York City private equity firm, a labor union, the state government and BPA worked to revive the plant near Ferndale, Wash., and hire back the 700 employees laid off when Alcoa shuttered the smelter in 2020. Gov. Jay Inslee wanted the state to contribute $10 million to the revival; shrinking the resurrected plant’s carbon emissions figured into his push to combat climate change.

The big hurdle was that BPA and the private equity firm that wanted to buy the former Alcoa Intalco Works, Blue Wolf Capital of New York City, could not agree on terms for BPA to provide electricity for the power-hungry plant.

On Thursday, Blue Wolf broke off talks, BPA spokesman Doug Johnson told RTO Insider. The federal power agency is willing to resume discussions if Blue Wolf returns to the table, he said.

Talks broke down over the huge electricity demands of aluminum smelting. When Alcoa owned the plant, it received power at a special industrial rate provided under the 1980 Northwest Power Act. Blue Wolf and a new operating company, Intalco, wanted to buy the facility from Alcoa with the site’s industrial power purchase rate intact, but the 1980 law said the rate could not be transferred.

Consequently, the Blue Wolf-BPA talks focused on market rates, which are subject to fluctuation and could move above or below the industrial rate, Johnson said. Blue Wolf wanted a rate similar to the industrial rate, but a fluctuating market could result in other BPA customers paying more to subsidize Intalco’s power purchases, he said. The bulk of the BPA’s power comes from hydroelectric dams.

Scott Simms, executive director of the Portland, Oregon-based Public Power Council, a coalition of consumer-owned utilities in seven states, including Washington, said Blue Wolf misread BPA’s legal obligations to provide power.

“By Congressional statute, BPA must first and foremost serve the needs of Northwest non-profit public utilities at cost. To the degree BPA has surpluses, it can make excess supplies available to others in the wholesale marketplace,” Simms said in an email. “As our Western power grid becomes tighter on available supplies given heightened demands and new climate mandates, BPA must be certain it can supply public power first, as Congress intended.

“I believe Blue Wolf either misunderstood or failed to realize this long-standing BPA statutory obligation to public power. It legally wasn’t ever possible for Blue Wolf to step in front of public power’s legitimate and rightful obligation to BPA power for a sweetheart deal,” Simms said.

Blue Wolf did not reply to a request for comment.

‘Huge Employer’

Supporters had hoped to get the Ferndale plant fully running by mid-2024.

The governor’s office remains optimistic that the project can be salvaged with new equipment that would trim carbon emissions — mainly sulfur dioxide — below previous levels when Alcoa closed the plant in 2020 due to dropping aluminum prices, a scenario that has played out for smelter across the U.S. The high costs of smelting aluminum, especially due to the volume of electricity required, resulted in the number of the nation’s smelters shrinking from 30 in 1985 to six today.

The anti-carbon measures proposed for the Ferndale plant include better scrubbing and filtering of the fumes going up smokestacks. They also include switching from electricity generated by fossil fuels to that provided by wind, solar and hydropower.

The Ferndale plant would need roughly $250 million in improvements and overhauls to get back online and 400 MW of electricity to operate.

In a statement Friday, Inslee’s office said “the governor remains committed to the vision of upgrading and reopening the plant as a secure, domestic source of the green aluminum that is critical for our clean energy transition. He stands ready to work with labor and community partners as they continue to seek a solution.”

“We are disappointed that negotiations to restart the Intalco aluminum smelter in Washington State, which would provide 700 local high-paying jobs and help secure a domestic supply of low carbon aluminum appear to have failed,” Annie Sartor, aluminum campaign director for Industrious Labs, said in an email. Industrious Labs is a Cincinnati-based think tank focusing on helping industries grow while coping with climate change issues.

Sartor wanted the Biden administration and Congress to invest in reviving aluminum manufacturing with renewable energy. Aluminum is a key component in building electric vehicles, solar panels and transmission lines.

Meanwhile, the likelihood of 700 resurrected jobs in Ferndale has taken a huge hit.

Luke Ackerson, business manager of the International Association of Machinists Local No. 160, remembers when the plant shut down during the pandemic in 2020. “Some worked there for 30, 40, 50 years, and you would see on their faces ‘What am I gonna do next?’” Ackerson said last month. “Ferndale is a small town, and this is a huge employer.” Ackerson could not be reached for additional comment.

Brian Urban, who worked as a bricklayer at the plant, said of the plant’s closing: “It came as a complete surprise. Some people got angry. Some people got completely depressed. There were some suicides. Some marriages suffered.” Urban and his wife coped, and he continued as a bricklayer for Local 160.

The union had negotiated a contract with Intalco that would have kept the Alcoa-level wages and would give the workers partial ownership of the plant.

Meanwhile, Intalco expected to negotiate a “bridge contract” of a few years to obtain electricity from traditional sources before switching entirely to alternative power sources such as solar and wind, Intalco CEO Mike Tanchuk said in an interview last month. He could not be reached for comment after the BPA talks ended Thursday.

U.S. industry has an annual aluminum demand of 5 million metric tons (MMT). American smelters produce 1 MMT a year, while another 2 MMT come from Canada. The remainder comes from overseas, including 300,000 metric tons a year from Russia. The Ferndale plant could produce 235,000 metric tons annually, which would make up most of the aluminum imported from Russia, said Joe Quinn, director of the Center for Strategic Industrial Materials, a D.C.-based think tank.

China produces more than 60% of the world’s aluminum, primarily through coal-fired electricity. The world’s leading producer of aluminum using carbon-free, hydro-powered energy is Russia, Quinn said.

December 20, 2022

NYISO Operating Committee Briefs: Dec. 15, 2022

RENSSELAER, N.Y. — NYISO’s Operating Committee on Thursday approved a winter study, tariff revisions to improve transmission study coordination within the interconnection process, manual updates for “internal controllable” lines (ICLs) and a winter operations study that included new nameplate values for energy storage.

Con Ed Study

The committee approved compliance procedures presented by Consolidated Edison that verified loss-of-gas and minimum oil burn requirements for the winter, which found that there was no change in the results from last year.

Con Ed said it should be able to provide New York City with energy during peak load conditions and meet NYISO reliability requirements using the same expected number of generators as the last winter capability period.

Dan Head, senior engineer at Con Ed, summarized the findings saying, “This year should look like last year.”

Interconnection & Transmission

The OC voted to recommend that the Management Committee and Board of Directors authorize NYISO staff to file proposed tariff revisions that revise base case inclusion rules used in interconnection studies, as well as enhance coordination between transmission project and class year project studies.

The proposals build upon NYISO’s efforts to improve the interconnection process. (See NYISO Investigating Tariff Changes to Improve Interconnection Processes.) The ISO will request an effective date of 60 days from when the proposal is filed with FERC.

‘Internal Controllable’ Lines

Stakeholders voted to approve manual revisions to clarify how ICLs will be evaluated with respect to both existing interface definitions and dispatch assumptions.

The updates, which were approved by both the OC on Thursday and the Business Issues Committee the day before, are part of a raft of revisions to the ICL design that have been proceeding on an accelerated timeline so that they can be adopted for the 2023 Class Year. (See “Deliverability Rules,” NYISO Management Committee Briefs: Nov. 30, 2022.)

Winter Operations Highlights

The committee approved NYISO’s 2022 winter operations report, which reinforced the New York-to-New England interface loop-flow concerns raised by the Market Monitoring Unit. (See related story, NYISO Over-crediting Poorly Performing Units’ Capacity, Monitor Says.)

NYISO also shared an updated total nameplate value of installed intermittent resources in the New York Control Area, which, for the first time, included energy storage resources:

storage: 20 MW
behind-the-meter solar: 4,184 MW (+61 MW)
front-of-the-meter solar: 94 MW (+20 MW)

(See “Intermittent Resources Update,” NY TOs Seek Clarification on ROFR for Upgrades.)

Class Year 2021

Thinh Nguyen, senior manager of interconnection projects, told stakeholders that the second round of Class Year 2021 projects had been posted and that developers must now post their security by Dec. 21.

Assuming all security is posted on time, the next class year will start on Jan. 23, 2023.

Nguyen also said that NYISO will be hosting a Class Year Entry Forum this Wednesday for stakeholders to learn more about the process and procedures related to the class year study. Email InterconnectionSupport@nyiso.com to learn more.

December 20, 2022

Settlement Hearing Ordered for PG&E, SF Distribution Dispute

FERC on Thursday ordered settlement judge procedures for a three-year-old dispute between Pacific Gas & Electric and the city and county of San Francisco over the provision of distribution service.

At issue was a 2019 complaint the city filed with FERC alleging that PG&E had violated its wholesale distribution tariff (WDT) by refusing to provide lower-voltage secondary service to many sites within the city.

Last week’s order comes nearly a year after the D.C. Circuit Court of Appeals remanded the matter back to FERC after overturning the commission’s unanimous 2020 decision rejecting San Francisco’s complaint (EL19-38). (See San Francisco Wins Against PG&E, FERC in DC Circuit.)

In its original filing, the city alleged that PG&E had consistently refused to make new interconnections at secondary voltage unless the total electricity demand was less than 75 kW and instead offered to connect higher-voltage primary service, which requires the installation of transformers and carries higher fixed costs for ratepayers, inhibiting the installation of rooftop solar.

The city argued that the practice violated PG&E’s tariff, which it said requires the utility to offer secondary service when requested and to expand its infrastructure where necessary.

The utility countered that it did not categorically deny secondary service in cases where demand exceeded 75 kW and said its denials in some cases were based on technical, safety and reliability concerns.

FERC denied the complaint in April 2020, ruling that PG&E should decide what level of service is appropriate for customers, and upheld the decision on rehearing later that year in another unanimous vote.

But in a January 2022 opinion, a three-judge panel of the D.C. Circuit found that FERC failed to scrutinize the safety and reliability risks cited by PG&E. The court also rejected PG&E’s contention that it decides appropriate voltages case by case.

“Evidence before the commission showed that since 2015, many of San Francisco’s new interconnection requests exceeding 75 kW have been denied secondary service by PG&E, and that the proportion of new interconnections above 75 kW receiving primary service has increased since 2015,” the court said. It cited a July 2019 letter written by PG&E to San Francisco saying it was no longer “willing to make additional accommodations” for secondary service.

Faulty Guidepost

In re-examining the record on remand, FERC found that “PG&E’s application of an unofficial and unwritten 75-kW threshold for providing secondary service for San Francisco customers violates the filed rate doctrine, and that the criteria by which PG&E determines service level must be included in its WDT.”

The commission also concluded that FERC’s record contains “insufficient support” to find that the 75-kW threshold is “just and reasonable,” and that the record requires further development to determine when primary service is required under the WDT.

The commission noted that the filed rate doctrine forbids utilities from charging any other rate than the one filed with FERC, adding that the principal “extends to utility practices that affect rates and service.”

“Relatedly, the rule of reason requires public utilities to file for commission approval ‘practices that affect rates and service significantly, that are realistically susceptible of specification, and that are not so generally understood in any contractual arrangement as to render recitation superfluous,’” the commission wrote, citing a 1985 D.C. Circuit opinion.

The commission said it had previously determined that the 75-kW threshold did not need to be included in the WDT because it viewed the threshold as an “initial guidepost for which primary service can be expected,” noting the multiple occasions PG&E had granted secondary service for installations exceeding 75 kW. But the D.C. Circuit ruled that, even as a “guidepost,” the 75-kW threshold was the kind of “numerical threshold” that the “rule of reason” required to be included in the WDT.

“Given the court’s direction on remand, we find that under the rule of reason PG&E must include in the WDT the thresholds and other criteria used to determine whether a customer receives primary, primary plus or secondary service,” the commission said.

The commission also found that the record does not demonstrate that the 75-kW guidepost would itself be just and reasonable for determining which points of interconnection should receive either primary or secondary service.

“For example, while we recognize that the WDT serves a different purpose and applies to different customers than PG&E’s retail tariff, and while that retail tariff is not subject to the commission’s jurisdiction, PG&E has not sufficiently explained why the 3,000-kW threshold it applies in the retail context is not appropriate for determining the type of wholesale distribution service available to a point of delivery under the WDT,” FERC said.

The commission further found that it is unclear that a kilowatt threshold is either necessary or sufficient for determining whether an interconnection should be served with primary or secondary service, rather than “specified reliability, safety or operational criteria,” which could possibly be considered in conjunction with a kilowatt threshold.

“For these reasons, we find that San Francisco has demonstrated that the WDT must include the specific criteria that PG&E uses to determine whether a wholesale distribution service customer is eligible to receive primary, primary plus, or secondary service at a requested point of delivery,” the commission wrote.

FERC said the settlement hearing should examine those issues and explore what San Francisco points of interconnection, if any, that were provided primary service should have been provide secondary service since the time of the original complaint until a revised WDT becomes effective and the appropriate amount of refunds owed to San Francisco as a result.

Hudson Sangree contributed to the reporting in this article.

December 20, 2022June 14, 2023

Texas RE Board of Directors Briefs: Dec. 14, 2022

NERC’s Robb Addresses Long-Term Reliability Assessment

Attending his first in-person meeting of the Texas Reliability Entity’s Board of Directors, NERC CEO Jim Robb was able to give directors, staff and stakeholders an early look at his organization’s annual Long-Term Reliability Assessment a day before it dropped.

“What’s really fascinating right now … is that the CEO of NERC is not supposed to be on the ‘Today’ show,” Robb said. “The fact that mainstream media has had such interest in the reliability assessments that we’ve been publishing … they used to be kind of very goal-oriented engineering studies, but starting around 2018, we started to see chinks in the armor of the industry from a reliability and resource adequacy perspective.

“Every year when we do the long-term assessment, we see the colored areas of the map that are the wrong color growing. [The latest assessment] continues the trends that we’ve seen. More and more areas of the country are at a greater risk of not being able to serve customers.”

NERC’s annual report assesses North American resource adequacy and identifies trends, emerging issues and potential risks for the next 10 years. This year’s report found most of the continent in either high-risk situations, where energy shortfalls could occur at normal peak conditions in one or more years, or elevated situations, where severe heat or cold could lead to shortfalls. (See NERC Warns of Ongoing Extreme Weather Risks.)

Robb said his resource adequacy concerns are driven by the industry’s transition to renewable resources. He said interconnection queues are overflowing with wind and solar projects and account for more than 1 TW of energy than is already on the ground.

“A lot of this stuff will never get built, so it just goes to show that there is a lot of capital and capital interest in investing in this new form of generation,” he said. “I think the transition is going to continue, and we need to get in front of it and really understand what that means.”

Given that the new technologies are different from what the industry is used to, Robb said it needs to change its mindset from capacity to focusing on energy and the ability to deliver it around the clock. He said changing weather patterns are becoming more extreme and frequent, creating more stresses on the system.

“What’s really sobering about the situation we’re in right now is that for the first time in a long time, our Long-Term Reliability Assessment is showing aggregate load that’s being driven after a number of years of reductions due to energy efficiency and attention to reducing peak capacity needs,” Robb said, warning that electrification could result in a five-fold increase in electricity demand.

“One of the things that we’re seeing in our reliability assessments is large areas of the country are moving in the wrong direction,” he said.

Robb suggested that pricing and retaining capacity not needed for everyday usage, building multistate transmission to “harvest” renewable resources and rebuilding the supply chain would address the situation.

“We’ve got to crack the code on transmission development, and it’s not a financing issue. The issue is getting sited,” he said. “So, there’s a lot of work to be done, to figure this all out.”

Texas RE’s 2023 Goals Set

Texas RE COO Joseph Younger said the organization is supporting the ERO Enterprise’s long-term strategy across five focus areas:

expanding risk-based focus in standards, compliance monitoring and enforcement programs;
assessing and accelerating steps to mitigate known and emerging risks to reliability and security;
building a strong Electricity Information Sharing and Analysis Center (E-ISAC)-based security capability;
strengthening engagement across North America’s reliability and security ecosystem; and
capturing effectiveness, efficiency and continuous improvement opportunities.

“Our staff has really looked at ways to improve all facets of the organization,” Younger said. “We’re continuing to support the ERO and our industry stakeholders as we look to leverage those tools and enhance our processes and our security.”

Younger promised more information on NERC’s biannual GridEx exercise as its Nov. 14-15 dates approach. The event, GridEx VII, is the largest grid security exercise in North America. It provides a forum for E-ISAC member and partner organizations to practice their response and recovery from coordinated cyber and physical security threats and incidents.

NERC, Texas RE to Discuss Odessa Disturbance

Appearing earlier before the Member Representatives Committee, Younger said that NERC and the regional entity will both hold webinars on what has become known as the “Odessa Disturbance,” an inverter-based resource disruption in West Texas this summer.

Joseph Younger 2022-09-21 (RTO Insider LLC) FI.jpg

Joseph Younger, Texas RE

The two organizations worked together on an event analysis that they released Dec. 8. The report documents the June 4 event near Odessa and differentiates it from a similar event in the same location the previous year. ERCOT lost 2,555 MW of solar PV and synchronous generation during the event.

NERC and Texas RE called for “immediate industry action” to ensure that IBRs do not pose a threat to grid reliability. (See NERC Repeats IBR Warnings After Second Odessa Event.)

NERC will hold an industry webinar Jan. 4 to review the report’s findings and recommended actions, and answer questions. Texas RE will discuss the event during a Talk with Texas RE session on Jan. 24.

In its only voting item, the MRC approved a 15-day ballot period for staff’s proposed regional standards development process (RSDP). A standard drafted team has completed a red-lined version of revisions that lay out how Texas RE can obtain regional variances to NERC Reliability Standards.

If the ballot passes, the MRC will send it on to the Texas RE’s board. Assuming its approval, the entity will send the standards authorization request to NERC for a 45-day public posting and its eventual adoption.

Members Re-elect 2 Directors

During the Texas RE’s annual meeting, sandwiched between the board and MRC meetings, members re-elected Directors Crystal Ashby and Jeffrey Corbett to three-year terms.

Ashby was also selected by the board’s Nominating Committee to serve as vice chair next year. Board Chair Milton Lee was re-elected.