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January 12, 2022

Hearing May Settle Ameren, DOJ Clash over Coal Plant

A federal judge has scheduled a hearing next month to settle a dispute between Ameren and the Department of Justice over the closure of a St. Louis-area coal plant.

In a Monday ruling out of the U.S. District Court for the Eastern District of Missouri, Chief Judge Rodney Sippel ordered a Feb. 4 hearing over when Ameren should shutter its 1.2-GW Rush Island Energy Center. The DOJ has accused Ameren of dragging its feet on pollution mitigation (4:11 CV 77 RWS).

The hearing date gives MISO time to determine whether the plant is needed for system reliability beyond its planned 2024 retirement. The grid operator said it will decide no later than Jan. 28 whether to designate Rush Island as a system support resource that would possibly prevent it from shutting down.

The DOJ has accused Ameren of “engineering” a “drawn-out process” rather than simply closing the plant prior to 2024 or installing required sulfur dioxide controls, as directed by the Eastern District Court in 2019.

That decision appeared to conclude a decade-long battle over Rush Island, which was energized in 1976. The Sierra Club sued Ameren over the redesign and reconstruction of the plant’s Unit 1 and Unit 2 boilers in 2007 and 2010, respectively. The utility carried out the rebuilds without applying for a Clean Air Act permit, which would have required the inclusion of wet flue gas desulfurization pollution controls.

The court has singled out Rush Island as the 10th-highest source of sulfur dioxide pollution in the U.S. It currently operates without any pollution controls. It gave Ameren until 2024 to install up to $1 billion in emissions controls.

The utility said in December it would meet the court’s deadline rather than bring Rush Island into compliance. According to its 2020 integrated resource plan filed with the Missouri Public Service Commission, the plant would run through 2039.

The DOJ argued that Ameren should have been contemplating Rush Island’s closure as early as 2017, when a judge found the company liable for excessive pollution.

“It has been more than a decade since Ameren should have installed life-saving pollution controls when it reconstructed the Rush Island plant,” the DOJ opined in a Dec. 28 filing. “It has been five years since Ameren was found liable under the Clean Air Act for failing to install those controls. And it has been two years since this Court put Ameren on a court-ordered schedule to finally come into compliance. Now, Ameren has decided it would rather just retire the Rush Island plant after all.”

Ameren could have alerted MISO to Rush Island’s retirement and study process in 2018 when the company itself “raised the specter” of retirement, the DOJ said. The utility’s expert economist said it would make better financial sense to close the plant rather than mount pollution controls.

The DOJ said Ameren has already “reaped significant financial benefits” from its illegal modifications to Rush Island and should speed up the closure rather than keep the plant pumping out dollars and toxic gas. The agency said it’s up to the courts, not Ameren, to establish a shutdown date.

“Any delay in the plant’s shutdown will come at the expense of human health and welfare,” the DOJ said.

But Ameren said the closure process is not that simple. It also insisted that its retirement decision wasn’t “definitive” until last month and pushed back against the DOJ’s insinuation of a “bad motive.”

“Rush Island cannot be hastily disconnected from the grid without careful evaluation of potential impacts on the stability and reliability of the transmission system, and resolution of any problems identified,” Ameren countered in a filing Friday.

The utility has fought for years to keep Rush Island generating electricity. Now, Ameren says the plant’s early retirement will lead to a healthier public — if MISO doesn’t conclude the plant is needed for the grid’s health.

The Sierra Club has asked that Ameren replace Rush Island’s capacity with a blend of renewable energy, energy efficiency and demand response.

“Given the immense public health harms that Ameren Missouri chose to inflict on the region by operating Rush Island out of compliance with the Clean Air Act, [Ameren] CEO Marty Lyons and utility executives should work with the grid operator to retire the coal plant as soon as possible,” interim Sierra Club Beyond Coal Campaign director Andy Knott said in a statement last month.

January 12, 2022

Study: EV Adoption to Cut $5.3M in Vt. Gas Taxes in 2025

The Vermont Agency of Transportation (VTrans) is estimating that the state will lose $560,000 in gas tax revenue this year from the adoption of plug-in hybrid and all-electric vehicles.

Given the state’s plans to ramp up EV adoption, gas tax revenue losses from light-duty cars could reach $5.3 million in 2025 and $80 million in 2050, Joe Segale, VTrans’ policy, planning and research bureau director, told legislators Wednesday.

“We need to make up for this lost revenue, and we need to do it in a way that doesn’t do any harm to the adoption of EVs,” Segale said during testimony before the House Transportation Committee.

Segale presented findings to the committee from a new study on the effect of EV adoption on the gas tax and possible solutions to offset revenue losses. The agency is recommending that Vermont establish an EV mileage-based user fee by 2024 that gathers odometer data during annual vehicle safety inspections.

The tax loss from Vermont’s 5,730 registered plug-in hybrid and all-electric vehicles will only account for 0.67% of the state’s total gas tax revenue this year, which Segale said is “manageable.” About one-third of those vehicles are all-electric.

Estimates from the recently released Vermont Climate Action Plan put total registered EVs at 47,500 by 2025 and 593,000 by 2050.

Vermont uses its gas tax revenue to match federal funding, so Segale said it’s critical to put sustainable alternative mechanisms in place as soon as possible. About 25% of the money raised through the gas tax comes from out-of-state drivers, he said.

The study examined the possibility of establishing a per-kilowatt-hour fee for out-of-state EV drivers at public charging stations. Data from three Vermont utilities’ charging stations showed that out-of-state drivers purchase 15 to 20% of the electricity.

Based on purchase data and an estimated 3.4-cents/kWh equivalent to the gas tax, Segale said the state would only raise $5,000 from out-of-state drivers for the year.

“That’s just not worth it at this point, but we need to figure this out,” he said, adding that the best option now is to watch the national mileage-based user fee pilot established by the federal Infrastructure Investment and Jobs Act.

The options for capturing revenue from EVs include collecting an annual flat fee or charging a fee based on miles driven, according to the study. For plug-in hybrid and all-electric vehicles, the study recommended annual flat fees of $55 and $139, respectively, based on historical average miles driven.

There are winners and losers under a flat-fee system, as nobody drives the average, Segale said. The agency, therefore, is leaning toward a mileage-based fee.

Until onboard telematics can automatically report miles driven, the state will need to establish a system for reading individual odometers.

That could happen through wireless devices installed by drivers, but Segale said the most viable option is to collect the data during annual safety inspections. Implementing that data collection process would cost the state between $1 million and $2 million and 3.5% of the annual revenue collected for ongoing operations, according to the study.

Thirteen states have active mileage-based user fee pilots, while another 13 are studying the option. Utah and Oregon have instituted mileage-based user fee programs for EVs that Segale said allow owners to pay a flat fee or pay by miles driven, with a cap at the flat rate. Both states, he added, may expand the program to all vehicles.

Virginia has also passed a law to allow mileage-based fees, but the state is still designing the system.

“There’s some uncertainty now about how much that will be pushed because there has been a change in leadership in Virginia,” Segale said.

VTrans will perform a system assessment and design study for a mileage-based program this year and seek legislative approval for the program next year. Program implementation would not begin until at least 2024, Segale said.

“The Climate Action Plan recommended waiting to establish registration fees for EVs until they reach 15% market share, and the Department of Environmental Conservation [estimated] that might happen by 2026,” Segale said.

January 12, 2022

NEPOOL Markets Committee Briefs: Jan. 12, 2022

Retirement Bid Flexibility Proposal

The NEPOOL Markets Committee on Wednesday approved a proposal from Calpine that would make changes to the resource retirement process to allow retirement bids to be updated later in order to give generators more flexibility.

Currently, retirement bids are due in March, 11 months before the Forward Capacity Auction, a time period that Sigma Consultants’ Bill Fowler said adds “significant, unnecessary risk.” (See NE Stakeholders Propose Retirement, Financial Assurance Changes.)

The rule change would allow bids to be updated in October, by at most 25% below their initial submission. The committee approved the proposal by voice vote.

Calpine is planning to bring a second part of its proposed retirement changes — removing the “repowering rule” that requires a minimum investment to re-enter the market after retirement — to a vote in the committee next month. That change is intended to provide generators a way to mothball units and return them to service if there are significant changes in the region, Fowler said.

Financial Assurance Proposal

The committee also discussed a plan from Competitive Power Ventures to hike financial penalties for resources that fail to reach milestones prior to their delivery year and commercial operation — a timely topic as Killingly Energy Center contests a recent FERC ruling affirming ISO-NE’s decision to terminate its capacity supply obligation (ER22-355). (See FERC Accepts ISO-NE Request to Terminate Killingly CSO.)

Killingly and projects like it have “little financial incentive to withdraw a failed project,” CPV’s Joel Gordon said in a presentation, with penalties currently only assessed after resources have failed to reach their initial commercial operation date. And the only tool that the grid operator currently has to respond to such failures is termination, which Gordon called a “sledgehammer.”

When failed projects participate in capacity auctions, it harms other CSO holders through lower clearing prices and higher performance risk, and it can displace “shovel-ready” projects, Gordon argued.

CPV’s proposal would create new financial assurance requirements for projects that fail to meet certain milestones. It’s similar to a previous proposal by the New England Power Generators Association, which has raised the issue as well in recent weeks in response to Killingly. NEPGA’s Dan Dolan told RTO Insider that the group would support escalating penalties for delays.

The MC was supposed to vote on the plan Wednesday, but CPV deferred to the committee’s next meeting to try to hash out differences with ISO-NE, which said in a recent memo that the plan is not complete and needs further development to define the root cause of the conditions it describes.

GIS Revisions

The committee also voted to approve changes to NEPOOL’s Generation Information System, including:

metering for certain residential solar generators in the Connecticut Residential Solar Investment Program;
the treatment of energy storage facilities in the GIS; and
enhancements to the GIS to address incorrect inputs on fuel splits for dual-fuel units.

January 12, 2022November 11, 2023

Long Permitting, Drought Put US Hydropower at Risk

Sen. Joe Manchin (D-W.Va.) | Senate ENR

The Senate Energy and Natural Resources Committee kicked off its 2022 schedule with a hearing on hydropower characterized by uncommon agreement among its often adversarial Democrats and Republicans.

Lawmakers on both sides of the aisle agreed that the nation’s hydropower projects provide renewable, flexible baseload power that is undervalued in power markets and under-incentivized in federal policymaking. They also agreed that hydro is at risk because of long, expensive permitting and relicensing processes, as well as the ongoing drought in the West, which has threatened water levels and power supplies at major federal projects.

About a third of all nonfederal hydropower projects, representing 14 GW of capacity, will be up for relicensing between now and 2030, said Sen. Joe Manchin (D-W.Va.), committee chair, in his opening statement at Tuesday’s hearing. “Between low hydroelectricity prices and the high capital cost of maintenance and retrofits required for relicensing, there is a real possibility these plants could face closure,” Manchin said.

Sen. John Barrasso (R-Wyo.), the committee’s ranking member, stressed the importance of hydro’s use as a black start resource and the need for changes to permitting, both for the relicensing of existing facilities and for adding hydro to nonpowered dams.

Noting that only 3% of the nation’s 90,000 dams produce electricity, Barrasso said, “The glacial pace of permitting is a significant barrier to private sector investment in hydropower. It reduces the likelihood of investment in upgrading existing hydropower facilities such as installing turbines in nonpowered dams.”

Citing a Department of Energy study, Barrasso said that installing turbines on nonpowered dams could add 12 GW of power to the nation’s grid.

‘Just a Down Payment’

Federal support for hydropower was one of the selling points of the bipartisan Infrastructure Investment and Jobs Act (IIJA), signed by President Biden in November. The law included $125 million to add hydropower to nonpowered dams and another $75 million for efficiency improvements at existing hydro facilities, such as installing new low-head turbines that can produce power at lower water levels.

Jennifer Garson, acting director of the Department of Energy’s Office of Water Power Technologies, which is administering the IIJA funds, said they “will have an immediate impact on the U.S. hydropower sector and help address some of the critical capital gaps the industry faces.”

Garson was one of four federal and industry officials at the hearing. Malcolm Woolf, president and CEO of the National Hydropower Association, said the federal dollars, while vitally needed, are “just a down payment.”

“That money will stretch to cover investments in perhaps 150 to 200 facilities across the nation, but there are about 2,200 [hydro projects] in the U.S.,” Woolf said.

He also called for a streamlined permitting process that would allow “facilities that do not have significant environmental issues” to be approved in about two years, such as closed-loop or off-river pumped storage projects or nonpowered dams that have already gone through environmental reviews.

“We need some process discipline in order to be able to make sure that the deadlines established are honored, and the second thing we need is to rein in the agency over-run,” Woolf said, pointing to permitting requirements that may not be directly related to a project, such as building community facilities or providing grazing for livestock.

Woolf and others called for FERC to take a stronger role in the permitting process. It is currently the lead agency on hydropower permitting but is often “reluctant to make decisions when there are conflicts between agencies or between the developer and the agency,” Sen. Angus King (I-Maine) said. “It basically says, ‘Go work it out, and then we’ll bless what you agree to.’ … FERC has to be ready to make those decisions on a timely basis.”

Hydropower ITC

On the incentive side, Sens. Maria Cantwell (D-Wash.) and Lisa Murkowski (R-Alaska) both promoted SB 2306, which would provide a 30% federal income tax credit for hydropower upgrades that improve grid resilience by, for example, providing ancillary services or helping to integrate other renewable resources. The bill also includes a direct-pay option that would allow public power utilities and cooperatives to use the credit.

The credit would also be available for smaller, run-of-river projects that, Murkowski said, would have a major impact for remote communities in her state.

“When you take a village off diesel, you are making an extraordinary difference in the quality of life and sustainability of that community,” Murkowski said. “We can do more to demonstrate to the public that projects like this are safe; that they can be constructed without detriment to the environment [and] without impact to our fisheries.”

Sen. Maria Cantwell (D-Wash.) | Senate ENR

But Scott Corwin, executive director of the Northwest Public Power Association, cautioned that incentives needed to be backed up by changes to electricity markets. “One challenge for hydropower is that traditional energy markets were not designed to provide proper price signals for its value, like ramping capacity and ancillary services,” Corwin said. “We need more market mechanisms that create price formation to compensate hydropower, so it’s available for dispatch when needed most.”

The 500+ Plan

But the greatest threat to hydropower right now is the drought in the Western states, which Sen. Martin Heinrich (D-N.M.) said has passed the point where it can be labeled as a temporary condition.

Martin Heinrich (Senate ENR) Content.jpg

Sen. Martin Heinrich (D-N.M.) | Senate ENR

“There’s substantial evidence that what we’re experiencing now in New Mexico and other parts of the West … may be more accurately termed aridification. In other words, it’s a permanent impact of the changing climate,” Heinrich said. “We’re simply not seeing the snowpacks and the precipitation that we used to see, and it doesn’t look like it’s coming back.”

Camille Touton, commissioner of the Bureau of Reclamation, provided an overview of the “unprecedented” impacts of the ongoing drought on hydropower dams in the Colorado River Basin. Both Lake Mead at the Hoover Dam and Lake Powell at the Glen Canyon Dam are at the lowest levels since they came online, Touton said. Lake Mead is currently at 1,066 feet above sea level, uncomfortably close to the 950-foot level at which power could not be produced at the dam.

“When you look at hydropower, there are two components to it,” Touton said. “The elevation of the reservoir, or the head, [and] the flow rate or the amount of water that goes to the turbine. What we’re seeing in the Colorado River is record low capacity.”

Camille Touton, Bureau of Reclamation | Senate ENR

To mitigate the impact of low water levels at Lake Mead, the bureau replaced five of the dam’s 17 turbines with wide-head turbines that produce power at lower water levels, Touton said.

At Lake Powell, recent forecasts show the possibility of the lake dropping below 3,525 feet by next month, she said. “This elevation is critical because it is just 35 feet above the minimum power pool elevation of 3,490,” resulting in “new and unpredictable operational conditions,” Touton said.

In response to the drought, Reclamation and the lower basin states of California, Nevada and Arizona launched the 500+ Plan in December to conserve 500,000 acre-feet of water a year, both in 2022 and 2023, to prop up water levels at Lake Mead, Touton said.

Reclamation will provide $100 million in federal funds — partly from the IIJA — and Touton said the states are also stepping up with financial support.

In yet another unprecedented move, the bureau recently announced it would for the first time “adjust” the water releases from Lake Powell, she said. “The volume stays the same in how much goes out, but we varied how much between months to be able to protect critical times in the power pool.”

Sen. John Hickenlooper (D-Colo.) noted that his state is currently seeing an above-average snowpack, providing some relief for both downstream dams, but it’s not a permanent solution.

Touton agreed that while the snow was welcome, “it’s one data point. It’s like not getting money into your bank account for a year and then all of a sudden getting a paycheck. We’re still at extreme deficits.”

January 12, 2022

NEPOOL MC Approves ISO-NE Plan to Eliminate MOPR

NEPOOL’s Markets Committee on Tuesday approved ISO-NE’s proposal to eliminate the minimum offer price rule (MOPR), rejecting an amendment that would have created a two-year transition period for the changes to the region’s capacity market.

The plan to eliminate the MOPR, which ISO-NE is pursuing after calls from FERC, will head to NEPOOL’s Participants Committee in February for final approval before the RTO files a tariff amendment with the commission later this quarter.

The proposal approved by the MC included some changes from the previous version, which were outlined by ISO-NE’s Ryan McCarthy at the meeting.

Most significantly, the new proposal removes part of the buyer-side market power review process. Specifically, it would get rid of a requirement that the Internal Market Monitor adjudicate whether a new resource’s offer would “materially reduce the clearing price in the auction.” The RTO said that provision was redundant with the “incentive rebuttal” process under which new resources receiving out-of-market support can avoid mitigation by proving that they do not have an incentive to exercise buyer-side market power.

Before approving the proposal, the committee voted down an amendment from Calpine and Dynegy that would have created a two-year transition period. The companies have argued that the proposal creates market and reliability risks and say their proposed delay would give the grid operator time to develop new mechanisms — such as capacity accreditation and enhanced reserves — to help mitigate those worries.

Ahead of Tuesday’s MC vote, the New England Power Generators Association complained that the proposal still suffers from unresolved flaws. The plan “allows uncompetitive offers to set uncompetitive clearing prices, violating the competitive, wholesale market construct and principles adopted by ISO-NE, agreed to by market participants and the New England states, and accepted by [FERC] decades ago,” NEPGA’s Bruce Anderson said. (See Monitor, Merchants Challenge ISO-NE Plan to Eliminate MOPR.)

Another amendment proposing the creation of a Scarcity Event Reduction Framework was withdrawn by its sponsor LS Power because it lacked support from ISO-NE. The plan would have added a new incentive to compensate resources that are able to perform in “very tight” conditions and forestall scarcity.

January 11, 2022November 8, 2023

Idaho Commissioner to Join WECC Executive Ranks

Idaho Public Utilities Commissioner Kristine Raper will join WECC as vice president of external affairs beginning Jan. 24, the regional entity said Monday.

Raper has served one full six-year term as commissioner and was reappointed to a second term last year by Gov. Brad Little. Prior to her appointment to the commission, Raper worked for seven years as its deputy attorney general, “representing a myriad of regulatory and energy law matters, with a strong emphasis on the federal Public Utility Regulatory Policies Act,” according to her bio on the PUC’s website. She holds a juris doctorate from the University of Idaho College of Law.

Raper currently serves on the Electricity Committee of the National Association of Regulatory Utility Commissioners and is a member of the Western Energy Imbalance Market’s Body of State Regulators. She also previously served on the EIM’s Governance Review Committee (GRC), which is responsible for oversight of the market as CAISO moves to expand the market from real-time to day-ahead trading. (See CAISO Takes on Transmission, EDAM in 2022.) As a GRC member, Raper advocated for CAISO to provide the EIM’s Governing Body to have greater joint authority with the ISO’s Board of Governors over decisions that affect the interstate trading market. (See Joint CAISO-EIM Authority Debated in West.)

She is also current chair of the Western Interconnection Regional Advisory Body (WIRAB), a group organized under the Federal Power Act to advise FERC, NERC and WECC on matters related to grid reliability in the West. WECC regularly provides organizational and issue status updates to WIRAB members at the latter’s monthly meetings.

“Kris’ wide-ranging regulatory and utility industry knowledge, along with her ability to engage with key stakeholders, will be a tremendous asset in this position at WECC,” the RE’s CEO, Melanie Frye, said in a statement Monday. “Furthermore, her in-depth knowledge of the issues affecting the Western Interconnection will enable her to hit the ground running in this critical outreach role.”

At WECC, Raper will be taking on the position similar to that previously held by former Utah Public Service Commissioner Jordan White, who joined WECC in May 2020 as vice president for strategic engagement and departed in August to become executive director of development at NextEra Energy subsidiary GridLiance. White was a key figure in WECC’s stakeholder outreach efforts as the RE sought to reshape its mission to center on resource adequacy in the Western Interconnection. (See WECC Seeks to ‘Invent’ Future with RA Forum.)

Under Raper’s leadership, WIRAB last year recommended that WECC’s Board of Directors approve a controversial, staff-driven proposal to reorganize the RE’s stakeholder technical committees to ensure a focus on the new core mission of resource adequacy. (See WECC Board Approves Stakeholder Committee Shakeup.)

In her role on WECC’s executive team, Raper will report to Steve Goodwill, who is senior vice president of strategic engagement and general counsel.

January 11, 2022November 9, 2023

New California Laws Help Electrify Cars, Houses

California laws that took effect at the start of 2022 included measures to increase electric vehicle charging, promote building decarbonization and eliminate greenhouse gasses from coal-fired cement plants.

Gov. Gavin Newsom signed most of the two dozen new energy laws last fall, but former Gov. Jerry Brown signed one of the new year’s most significant measures — Senate Bill 1383 — in 2016, with its implementation partially delayed five years.

SB 1383 sought to reduce methane emissions by requiring cities to divert 75% of organic waste from landfills by 2025. Regulations adopted under the bill took effect Jan. 1, requiring residents to put their food scraps into yard waste containers for recycling.

Much of that waste could be turned into biomethane to generate electricity, heat homes and fuel natural gas-powered vehicles, provided the infrastructure is built to turn the waste into gas through anaerobic digestion.

California expects to have enough anaerobic digestion facilities to handle 1 million tons of organic waste by 2025 but needs to be able to process 2.7 million tons to meet SB 1383’s goals, the California Department of Resources Recycling and Recovery (CalRecycle) said in an August 2020 report.

“Organics recycling and recovery infrastructure is growing but still needs significant expansion to provide the recycling capacity necessary to meet the SB 1383 disposal and methane reduction goals,” CalRecycle said.

Additional federal and state incentives are essential for meeting the goal, the department said.

Demand for the biomethane, which costs more than solar power and other renewable resources, must also increase.

Working under another measure, Senate Bill 1440 from 2018, the California Public Utilities Commission is currently developing targets for gas companies to procure enough renewable natural gas to generate 75.5 million MMBtu by 2030. (See Calif. Wants to Turn More Waste into Gas.)

EV Development

Several other measures that took effect seek to promote electric vehicles by accelerating the development of charging infrastructure, growing medium- and heavy-duty truck fleets and supporting workforce and supply chain development.

Assembly Bill 970 tries to address the slow progress of installing EV chargers that the state needs to meet its transportation decarbonization goals. (See California Needs Huge Number of EV Chargers.)

The bill seeks to create an expedited permitting process for applications to install EV charging stations by establishing timelines for cities and counties to follow. Under the bill, for example, an application to install 25 chargers or more will be “deemed completed” 10 days after it is submitted and “deemed approved” 40 days after it is completed.

Slow approval from local planning authorities has made it more difficult to meet the state’s need for hundreds of thousands of EV chargers to support the goal of putting 5 million EVs on the road by 2030, developers have said. (See Installing EV Chargers in Calif. is Slow, Costly.)

“In California, a new-service utility interconnection takes an average of 39 weeks or nine months to complete, in our experience, having built more than 200 stations today,” Matthew Nelson, director of government affairs for Electrify America, the largest network of fast-charging stations in the U.S., told a California Energy Commission workshop in October.

“The utility process for constructing the interconnection, the line extension and dropping the transformer … takes an average of 27 weeks, or more than six months, to complete,” Nelson said. “As a result, building stations in California costs 34% more for the exact same station than it costs us to build the same station in any other state.”

Another measure, Senate Bill 372, tries to make it more affordable for fleet operators to purchase medium- and heavy-duty zero-emission vehicles by establishing a fleet purchasing assistance program under the California Pollution Control Financing Authority, with priority given to fleets that impact low-income and disadvantaged communities.

Senate Bill 589’s aim is to expand the types of projects eligible for state clean transportation funding to include projects that develop in-state workforce and supply chains for zero-emission vehicle manufacturing and raw materials needed for batteries, such as lithium from the geothermal wells near the Salton Sea in far Southern California.

Building Decarbonization

Senate Bill 68 requires the California Energy Commission (CEC) to develop and publish on its website “guidance and best practices to help building owners, the construction industry, and local governments overcome barriers to electrification of buildings and installation of electric vehicle charging equipment.”

Topics include the “development of whole building electrification plans to help building owners prepare for future additions of electrical equipment.”

The bill authorizes the CEC to award funds from its Electric Program Investment Charge program to foster technological advancements that reduce the costs of electrifying buildings and benefit ratepayers.

Cement Plants

Senate Bill 596 requires the state Air Resources Board (CARB) to develop a strategy by the end of 2023 for eliminating greenhouse gas (GHG) emissions from cement plants by 2045.

Cement makers are the last major coal burners in California, with eight coal-fired cement kilns in the Mojave Desert and Central Valley producing inordinate amounts of pollution. Cement production accounted for 1.8% of GHG emissions in 2017, CARB said.

The cement industry has agreed it is important to decarbonize production by 2045 but contended it may be difficult to replace coal as a fuel source. (See Challenges Loom for Decarbonizing Concrete.)

January 11, 2022December 13, 2023

Cal Fire Finds PG&E Started Massive Dixie Fire

The California Department of Forestry and Fire Protection said last week it found that a tree falling onto a PG&E distribution line last July ignited the nearly 963,000-acre Dixie Fire, the second largest in state history, which destroyed more than 1,300 structures and killed one person.

“The Dixie Fire investigative report has been forwarded to the Butte County District Attorney’s Office” for possible criminal prosecution, Cal Fire said in a Jan. 4 news release.

Butte County prosecutors won 85 felony convictions against PG&E for starting the devastating Camp Fire in November 2018, killing 84 residents, and now are leading a coalition of five counties investigating PG&E’s role in the Dixie Fire.

The finding that PG&E started the wildfire was not a surprise; PG&E said soon after the blaze began that its line may have ignited the blaze. (See PG&E Expects $1B in Costs from Dixie Fire.)

“As we shared in our public statement in Chico in July after the start of the Dixie Fire, a large tree struck one of our normally operating lines,” PG&E said in a statement following Cal Fire’s announcement on Jan. 4. “This tree was one of more than 8 million trees within strike distance to PG&E lines.”

“Taking a bold step forward, PG&E has committed to burying 10,000 miles of lines in addition to the mitigations included in PG&E’s 2021 Wildfire Mitigation Plan,” the utility said. “Regardless of today’s finding, we will continue to be tenacious in our efforts to stop fire ignitions from our equipment and to ensure that everyone and everything is always safe.”

Last year, prosecutors in Sonoma and Shasta counties charged PG&E in the 2019 Kincade Fire and the 2020 Zogg fire. Cal Fire determined a tree that fell on a PG&E line started the Zogg Fire. The cause of the Kincade Fire remains under investigation.

PG&E acknowledged its lines likely started both fires but denied it was criminally liable for either blaze.

Federal prosecutors on Thursday said they would not ask for an extension of PG&E’s probation time based on California criminal charges. (See Judge Refrains from Adding Time to PG&E Probation.)

Monitor Findings

In November, the independent monitor appointed by the court to oversee PG&E during its probation said the utility needs to make substantial improvements in its efforts to prevent wildfires through vegetation management and grid hardening.

“Multiple years of horrific wildfires” started by PG&E equipment showed “its progress regarding wildfire mitigation obviously has been inadequate, and we doubt anyone would seriously dispute that, given the ongoing and profound safety issues in that area of operations,” the law firm Kirkland & Ellis, which the court appointed monitor, wrote in its report to Alsup.

“Including the Camp Fire fatalities, over 110 people have died as a result of wildfires where Cal Fire has determined PG&E equipment was involved since the San Bruno incident,” which killed 8 people, the monitor wrote.

Its reviews of PG&E safety practices showed the utility probably has missed tens of thousands of dangerous trees near its lines and failed to detect worn or broken equipment in many situations. PG&E still has a vast backlog of problems to fix from a 2019 inspection of 685,000 distribution poles, 50,000 transmission structures and 200 substations in high-fire threat districts, the monitor noted.

“There are over 500,000 tags from 2019 to present that remain unresolved to date,” it said.

The monitor also expressed skepticism about PG&E’s plans to bury 10,000 miles of power lines in fire-prone areas. CEO Patti Poppe announced the effort in July during the same media event in which she discussed the utility’s possible role in starting the Dixie Fire. (See PG&E Proposes Undergrounding 10K Miles of Distribution.)

“The monitor team applauds PG&E’s commitment to undergrounding to mitigate wildfire risk but notes that some serious questions and issues remain regarding PG&E’s implementation of the undergrounding initiative,” it said.

The utility did not give a time frame for the work but has plans to underground just 66 miles of lines in this year and a total of 327 miles over the next three years, the monitor said.

Even if it greatly increases its efforts over a 20-year period, “there is substantial skepticism among PG&E field personnel that PG&E can feasibly underground more than 500 miles per year using current technology and hardening methodologies,” the monitor said.

January 11, 2022December 14, 2023

Legislators Step into NH’s Battle over EE Program

Recent uncertainty over New Hampshire’s energy efficiency program continued last week, as the House of Representatives passed a bill to govern its pricing, while regulators dug in on their decision to roll back utilities’ recent budget proposal for the program.

State representatives Thursday unanimously passed House Bill 549, which would set the system benefits charge (SBC) at 52.8 cents/kWh, as approved for 2020, to fund New Hampshire’s 2021-23 Triennial Energy Efficiency Plan. The bill also would authorize the Public Utilities Commission to adjust the SBC annually based on inflation.

The measure is one of a series of steps stakeholders and legislators are taking following a PUC order Nov. 12 that basically reversed course on utilities’ three-year program proposal. (See NH EE Plan Approaches 2nd Year without Funding Certainty.) In its order (DE 20-092), the PUC said the proposed program budget of nearly $400 million was too high and directed the utilities to submit a new budget in line with the 2018-2020 plan.

While the House last week unanimously passed the bill to set program funding, it was only after Republicans and Democrats were split on a vote for the amendment that set the new SBC language. All but one Republican voted for the amendment, and all but two Democrats voted against it.

In both voting against the amendment and passing the final bill, Democrats were signaling that they support the basis of the bill but believe that it needs more work, Sam Evans-Brown, executive director of Clean Energy NH (CENH), told NetZero Insider.

The bill is “awful for New Hampshire citizens who are utility ratepayers,” Democratic Rep. Rebecca McWilliams said in a statement. “It moves SBC rate setting to the legislature, which means the rate will rarely (never) go up with inflation.”

Democrats are concerned that legislative control of the SBC will lead to an annual fight among policymakers over what the rate should be, Evans-Brown said. That means that any certainty the bill seeks to achieve might not be realized in the long term.

Republican Rep. Michael Vose, chair of the House Science, Technology and Energy Committee, believes the bill will put “guardrails” on the program’s funding. Under the utilities’ 2021-2023 plan, the SBC would have doubled, he said in a statement, adding that “the bill prevents that by striking a balance between investing in energy efficiency and protecting ratepayers from unsustainable increases to their electric bills.”

The bill now goes to the Senate, where McWilliams hopes it will be “further refined.”

For Evans-Brown, the bill will need to go beyond mere budget setting and “set the clock back” to before the PUC’s Nov. 12 order.

“The problem with the order is that it [shrunk the program budget] in such a way that it blew up all of our energy efficiency policies,” he said, adding that the order left the utilities wondering what they can do with the new budget.

Despite still needing to make its way through the legislative process and go to the governor for approval, passage of the bill could provide an expedient pathway to relief that stakeholders have yet to find elsewhere.

PUC Order on Rehearing

On Friday, the PUC denied requests for a rehearing of its order restructuring the three-year program.

New Hampshire’s utilities, the Consumer Advocate, advocacy groups and the New Hampshire Department of Energy filed rehearing requests in early December, primarily claiming that changes to the program administration in the order were “retroactive in nature” and departed from precedent.

The PUC disagreed with their arguments.

Conservation Law Foundation attorney Nick Krakoff said the organization “will continue the fight to overturn” the PUC’s “irresponsible” November order.

In a separate order on Friday, Commissioner Pradip Chattopadhyay denied a Dec. 17 motion by the Office of the Consumer Advocate (OCA) for his disqualification from the docket. The OCA claimed that Chattopadhyay’s prior work in the OCA was a conflict of interest. Chattopadhyay, however, said the OCA did not sufficiently demonstrate that he had any involvement in the docket before joining the commission.

CENH Lawsuit

A New Hampshire judge on Dec. 29 denied a request filed in Superior Court by a group of the state’s energy efficiency industry stakeholders, led by CENH, seeking a temporary injunction staying the PUC’s order.

The judge said the court lacked “subject matter jurisdiction to entertain appeals from PUC rulings, orders and rules,” and that the state’s Supreme Court has “exclusive jurisdiction” over the case.

Plaintiffs filed a motion to reconsider on Jan. 3, arguing the opposite and that there is no adequate remedy of law for immediate relief.

“One of the most disappointing pieces from the judge’s order … was the insistence that the New Hampshire Supreme Court … ‘can act with great alacrity when it needs to,’” Evans-Brown said.

Expediency, according to the petitioners, is imperative in this case to prevent layoffs that would stem from the PUC’s order, which they say effectively defunded ongoing activities of the state’s energy efficiency industry.

At this point, Evans-Brown said, CENH and other advocates are shifting their approach to find relief.

It’s not clear how a legal case would move ahead at this point, he said, but it is “100% certain” that stakeholders will appeal the PUC’s order to the Supreme Court.

“I think we are headed on a different path strategically, which is to say, instead of hoping that the Supreme Court will ride in on a white horse and get the contractors back to work, we are going to focus on a legislative solution in the near term,” he said. “In the long term, we hope that the New Hampshire Supreme Court understands the real problems with this order from a due process perspective and vacate it so that it does not become a precedent.”

January 11, 2022December 14, 2023

Can Youngkin Stop Clean Energy Growth in Virginia?

Governor-elect Glenn Youngkin (R) shook Virginia’s environmental and clean energy advocates Jan. 5 with his controversial nomination of Andrew Wheeler, who led EPA under President Donald Trump, to be Virginia’s next secretary of natural resources.

But when Youngkin takes office Saturday, he will be leading a state widely recognized as a Southern leader in the U.S. energy transition, with strong targets for grid decarbonization under the Virginia Clean Economy Act (VCEA).

Further, with a slim Democratic majority holding the line in the state Senate, Youngkin and the Republican majority in the House of Delegates will not be able to repeal the VCEA or take Virginia out of the Regional Greenhouse Gas Initiative (RGGI), as the governor-elect has vowed to do. Democratic lawmakers have also declared they will fight Wheeler’s nomination “tooth and nail.” (See Youngkin Taps Trump’s Former EPA Chief to Head Virginia DNR.)

Even putting the partisan state of play aside, the momentum of cleantech in Virginia may be hard to slow down, as demonstrated by a series of plans and reports announced in the runup to Youngkin’s inauguration.

On Dec. 30, Appalachian Power filed its 2022 renewable energy plan, as required by the VCEA, with modest commitments to add 294 MW of solar and 204 MW of wind to the utility’s generation mix over the next three years.

And on Jan. 1, the outgoing administration filed its VCEA-mandated report on the least-cost strategies for grid decarbonization, including a finding that the low cost of clean energy will outweigh any need for the state legislature to prohibit new fossil fuel plants. Dominion Energy also started the new year with a Jan. 7 ruling from the State Corporation Commission (SCC) giving it the go-ahead for the second phase of its grid modernization program, which includes preparing the utility’s distribution system for high levels of distributed energy resources.

Solar Grows, but Coal Stays

Appalachian’s new solar and wind power procurements were the top-line items in the company’s Jan. 4 announcement of its 2022 VCEA plan. The utility will acquire a 204-MW wind farm in Illinois and a 150-MW solar plant in Virginia; it will also sign power purchase agreements for three additional solar projects, totaling 89 MW, according to the plan, which will need approval from the SCC.

The utility “intends to meet its VCEA targets primarily through investments in solar, wind, energy storage and purchase of market renewable energy certificates,” it said. “By 2040, the company expects to add approximately 3,300 MW of solar, 2,600 MW of energy storage and nearly 3,000 MW onshore wind to its current portfolio of wind and hydro resources.”

Building out its renewable portfolio will provide near-term savings, according to Ismael Martinez Jr., resource planning manager for the utility’s parent company, American Electric Power (NASDAQ:AEP). In the 2022 plan submitted to the SCC, Martinez said the new solar would “help Appalachian avoid costs it would otherwise incur as a PJM participant, especially by helping the company to avoid purchasing energy from the PJM energy markets, which can be volatile.”

Solar can also be used as a distribution resource, Martinez said, to “reduce the company’s load during the PJM … coincident peak hours, thus providing a capacity obligation benefit by allowing the company to avoid an incremental purchase of capacity in the future.”

But reaching these and other VCEA goals could be challenging. The most recent figures on Appalachian’s generation mix, from September 2021, show that close to 65% of its power comes from coal and another 19% from natural gas, according to a company spokesperson. Most of that coal-fired power comes from two plants in West Virginia, which the utility intends to keep online through 2040, eventually replacing their combined 4,235 MW with carbon-free power.

If fossil fuel generation were to be used to replace the coal plants, it would be located out of state, the plan says.

Appalachian looked at the possibility of closing the coal plants by 2028, according to the plan. But in August the West Virginia Public Service Commission ordered the utility to make improvements at the two plants to bring them into compliance with federal wastewater regulations, which will allow them to stay online past 2028. Who will pay for these improvements has become a flash point since the SCC rejected Appalachian’s request to recover part of the costs from its Virginia customers, while the PSC has said West Virginia consumers may have to foot the bill for the upgrades on their own.

Andy Farmer, interim director of the SCC’s Division of Information Resources, said the commission has yet to schedule any hearings on Appalachian’s plan.

“Commission staff is reviewing the application to ensure that it is complete, and in a few weeks the SCC will issue a procedural order that provides opportunities for public comment and a schedule for hearings,” Farmer said.

Least-cost Path to 100% Clean Power

The VCEA report — compiled by the Natural and Historic Resources Department and Commerce and Trade Department, and submitted to the legislature on Jan. 1 — looks at the least-cost strategies for Virginia to reach a decarbonized grid by 2045. That goal can be achieved with existing technologies based on the VCEA’s renewable energy and energy efficiency standards and the emission reductions possible through RGGI, the report says.

The law calls for the state to add 16,100 MW of solar and onshore wind, along with 3,100 MW of energy storage. The solar industry alone could add tens of thousands of jobs to the state’s workforce as the sector grows from $1.3 billion to $8.1 billion in economic activity over the coming decades, numbers that underline the “economic strength of the clean energy sector,” the report says.

Getting to 100% clean energy: By 2045, Virginia could still have some natural gas generation, but it will account for only a small amount of the terrawatt-hours of power solar, wind and other clean technologies will provide. | Resources for the Future and Virginia Energy

“The emerging/advanced/clean energy sector is already a significant share of the energy economy in the commonwealth and is only poised to grow — largely because of the VCEA and the policy certainty it provides,” the report says.

Perhaps with Youngkin in mind, the report also warns that “markets working to drive clean energy growth will be limited without policy to help drive that growth. Low-carbon energy technology is widely acknowledged as the cheapest source of new electricity capacity, but strong policy signals ensure that the market responds at a rate reflecting the pressing need to eliminate greenhouse gas emissions.”

Rolling back the VCEA “could send a negative signal to industries already investing in Virginia,” the report says, pointing to the state’s expanding offshore wind industry as a key example. The rapid development of the sector is being driven by the VCEA’s target of 5,200 MW of offshore projects by 2034.

At the same time, the report does not recommend that the legislature pass any laws prohibiting the permitting of new fossil fuel generation. Such resources will be needed in the near term for reliability and flexibility, and the clean energy and efficiency targets in the VCEA will provide a competitive advantage for solar, wind and storage, the report says.

It also anticipates that nuclear power, which currently generates just under a third of the state’s electricity, will continue to provide a significant portion of its power. Natural gas, while still in the mix in 2045, will have shifted from baseline to seasonal backup power. By 2040, the state will have retired all but 20% of its legacy fossil fuel plants, and almost all new generation will be solar, wind and storage, the report says.

DERs

With the SCC’s approval of the second phase of Dominion Energy’s (NYSE:D) grid modernization plan, the utility announced it will be investing $650 million this year and next for a range of distribution system improvements and upgrades, from the installation of 1.1 million smart meters to a management system for integrating DERs.

But the commission’s ruling also came with conditions that Dominion show the value of those investments. For example, the utility’s plans to spend $198.3 million on smart meters must also ensure the technology will be optimized to provide customer savings and demand-side flexibility. A time-of-use rate the utility has been piloting will be developed into a systemwide offering, along with the creation of an opt-in demand response program providing peak-time rebates.

Dominion’s request to spend $5.2 million on a DER management system drew opposition from commission staff, who argued that the utility’s distribution system can handle the relatively low levels of DERs now installed.

The company had also pitched for the investment as necessary to better leverage aggregated DERs for the PJM system in compliance with FERC Order 2222. Again, staff raised concerns, this time about the uncertainty surrounding the RTO’s compliance filing, and Dominion agreed to put a hold on system implementation until the filing is submitted and approved.