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November 19, 2024

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Nevada PUC Rejects Mobile-only Payment Systems for EV Chargers

With more EV drivers using their smartphones to pay for vehicle charging, ChargePoint has asked Nevada regulators for flexibility to leave magnetic-stripe or chip credit-card readers off its public stations.

The request was made in connection with NV Energy’s $100 million EV infrastructure plan that the Public Utilities Commission of Nevada (PUCN) approved in November. (See NV Energy Gets Green Light for $100M EV Charger Plan.)

But PUCN voted 3-0 Tuesday to reject ChargePoint’s proposed changes to the charging station technical standards included in NV Energy’s plan. The plan says that stations “must accept a credit or debit card (magnetic stripe and chip card) without incurring any additional fees … in compliance with ISO 15118.”

The commission instead voted to reaffirm its Nov. 30 order approving NV Energy’s plan, but it made a grammatical change in the payment requirement. The requirement now says that charging stations “must accept a credit or debit card (magnetic stripe and chip card) without incurring any additional fees … and be in compliance with ISO 15118.”

The commission said that the technical requirements are minimum standards, and “other forms of payment may be offered and accepted in addition.”

“The commission reaffirms that more options for payment, rather than fewer options, will make it easier for customers to pay,” the order said.

In reaffirming its Nov. 30 order the commission also rejected a request from EVgo, another EV charging station provider. EVgo asked the commission to give third parties participating in NV Energy’s plan more flexibility to decide the number, type and capacity of chargers at a particular site.

EVgo also asked that the minimum power requirement for DC fast-charging stations installed as part of the plan be 100 kW, rather than 150 kW.

NV Energy’s plan, known as the Economic Recovery Transportation Electrification Plan (ERTEP), is a requirement of Senate Bill 448, a product of the legislature’s 2021 session.

The three-year plan, which starts this year, includes a network of electric vehicle charging sites throughout the state.

Paying With Smartphones

In a petition filed with PUCN last month, ChargePoint said that “real world evidence” indicates most EV drivers prefer to use a smartphone app or other mobile payment method to pay for charging.

The petition argued that requiring magnetic-stripe and chip card readers nearly doubles the lifetime cost of a Level 2 charging station, “with the predictable result that fewer charging stations will be deployed through the plan.”

Magnetic-stripe and chip readers are susceptible to fraud and are unreliable when used outdoors, the petition said.

“ChargePoint is concerned that the payment standards NV Energy has proposed drastically will limit the equipment and vendors that will be able to participate in the plan,” the petition said.

ChargePoint asked that the order be changed to require the stations to accept credit cards, but not specify the card-reader technology. Alternatively, the company suggested that charging-station hosts be allowed to ask for and receive a waiver of the magnetic-stripe and chip card reader requirement.

In a response to the petition, NV Energy said the technical requirements were a topic of “substantial debate” during proceedings leading up to the commission’s Nov. 30 order, and ChargePoint is simply rehashing those arguments.

During testimony, NV Energy officials shared concerns that EV drivers without a smartphone wouldn’t be able to use charging stations that lacked magnetic-stripe and chip readers.

Although ChargePoint said the requirements would limit the number of vendors that could participate in NV Energy’s plan, the utility responded that “the plan can be fully and effectively implemented with a limited number of … vendors willing and able to comply with the technical requirements.”

California Consistency

The Sierra Club and Nevadans for Clean Affordable Reliable Energy (NCARE) weighed in on ChargePoint’s petition, saying EV charging stations deployed as part of NV Energy’s plan should accept credit cards, debit cards and cash cards.

But NCARE questioned the need for magnetic-stripe readers, saying the technology is being phased out.

Many EV charging stations don’t directly accept credit, debit or cash cards and instead require use of a proprietary app or a call to an 800 number, NCARE representative Max Baumhefner testified in November. Prepaid debit cards are especially important to those who are “unbanked” or “underbanked,” he said.

In California, regulations require public charging stations to include a chip reader for credit, debit and cash cards, Baumhefner said, adding that Washington may soon follow suit.

“While contactless credit cards have gained market share in recent years, the debit and cash card market has not seen the adoption of contactless technology at the same rate,” Baumhefner said.

NCARE recommended that NV Energy’s plan mirror the California standards for payment at EV charging stations. Because California accounts for about half of the EV market in the U.S., makers of EV charging equipment will likely be basing designs on California standards, the group said.

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RI Asks Public: How Should We Define Net Zero by 2050?

Rhode Island’s climate council has begun the process of sorting out how it will define “net zero by 2050” for the upcoming update to the state’s 2016 Greenhouse Gas Emissions Reduction plan.

In a public session on Tuesday, the Rhode Island Executive Climate Change Coordinating Council (EC4) sought comments on which emissions to count in the plan, how to net those emissions and over what time frame to net them.

Under Rhode Island’s Act on Climate passed last year, the EC4 must submit a GHG emissions reduction plan update by January . The act sets an economy-wide, net-zero emission target for 2050.

In the current GHG inventory, the state tracks carbon dioxide, methane, nitrous oxide and fluorinated gases, summarized as CO2 equivalent and reported in million metric tons (MMT). While attendees were supportive of the four-GHG approach, there was some concern about the time frames used to calculate equivalencies.

“To combine the impacts of these very different kinds of gases, you need to come up with a way to figure out what one unit of methane means in terms of warming for the planet compared to carbon dioxide,” Timmons Roberts, Ittleson professor of environmental studies and sociology at Brown University, said during the session. That calculation, he added, depends on the time frame used.

Carbon dioxide, for example, stays in the atmosphere for hundreds of years, while methane has a short-term impact before breaking down. Their potential for warming the plant is calculated differently, depending on the time frame.

The New York Climate Action Council, in its draft scoping plan released in December, switched from a 100-year impact time frame to 20 years. For methane, Roberts said, that switch adjusts the impact from being “20 times worse than carbon dioxide per molecule to about 84 times worse.”

He suggested that Rhode Island consider the 20-year time frame for its accounting. “It looks like that’s the way the science is going,” he said.

The EC4 is considering different methods for the way it balances GHG emission from sources with sinks to find net emissions. Under the current inventory, Rhode Island takes all GHG sources and all GHG sinks, both summarized as MMTCO2e, and nets them, according to Carrie Gill, chief economic and policy analyst at the Rhode Island Office of Energy Resources.

As an alternative, she said, the accounting could net each GHG source and sink individually, then convert each GHG to MMTCO2e and add them together to find the final net measurement. A benefit of netting the GHGs separately, according to Gill, would be to target specific policies.

“If one of our policy objectives happens to be eliminating all [methane] leakage from the natural gas distribution system, then that would point us towards trying to get to a place where we can net each GHG first, because then it would meet additional policy objectives,” she said.

While attendees did not favor one accounting method over another, some suggested that netting through offsets or sinks should be a last resort, and Rhode Island should count emission sources outside of the state.

Rhode Island “should get to zero-carbon equivalent emissions” as quickly as possible, attendee Peter Trafton said. “Let’s start by 2030 and not be so focused on the arithmetic of how we add up to 2050 that we forget to get down as low as we can now.”

And while the state’s GHG inventory is consumption-based only for electricity, Roberts suggested it should be used for “everything.” That approach, however, has drawbacks.

“If we have natural gas-fired power plants, we should be including the emissions from the extraction and the transportation of that natural gas … because we know that Pennsylvania, New York and Connecticut, the states through which it’s traveling, are not counting those emissions,” Roberts said.

There’s no good way, however, to be certain of what other states are including in their own GHG inventory, he said.

The EC4 also is considering options for electricity sector accounting that changes the time frame for when emissions are released into the atmosphere.

“Our current practice aggregates these emissions based on averages over the entire year,” Gill said. Electric sector emissions change based on the fuel mix at the time that the electricity is pulled from the grid. Rhode Island, Gill said, counts them equally, whether it’s a renewables-heavy mix on a warm day or a fossil fuel-heavy mix on a cold day.

Future accounting options may allow the state to consider netting emissions over smaller time frames, but Gill said that would require some technological advances in accounting systems.

The EC4 will accept comments on how to define net zero by 2050 in the updated emissions-reduction plan through Jan. 28. In February, the council will discuss a draft of that definition during its regular meeting and release an update based on public input in March.

Another public comment session for the emissions-reduction plan in March will address the 1990 baseline against which emissions are measured.

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Washington Bill Takes Aim at Landfill Methane Emissions

A bill to regulate methane emissions from landfills drew praise and concerns during a hearing of the Washington House Environment and Energy Committee on Tuesday.

Questions surfaced about the costs and extent of House Bill 1663, introduced by Rep. Davina Duerr (D).

In its present form, the bill requires the owner or operator of a covered landfill with 450,000 tons or more of waste in place to calculate the quantity of gas generated by the landfill.

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

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

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

Landfills contribute to climate change with their methane emissions. “Methane stays in place for 10 years instead of 100 years, but it has 100 times the impact of carbon emissions,” Duerr said at the hearing.

Methane emissions from the state’s landfills are estimated to equal those of roughly 320,000 cars, said Martha Hankins, a manager with the Washington Department of Ecology.

“Methane is one of the most impactful greenhouse gases,” said Deepa Sivarajan, Washington policy manager with Climate Solutions. Heather Trim, executive director of Zero Waste Washington, said, “This bill is way overdue.”

Methane accounted for 10% of the nation’s emissions in 2019, according to EPA estimates. EPA figures show that landfills account for 17% of the nation’s emitted methane, behind fuel production at 30% and livestock-related emissions at 27%.

Utilities and waste management officials voiced concerns about the unknown costs of implementing the bill and asked for more study on the subject. They also wanted a better grasp on which specific locations would have to comply with the bill’s requirements

“It is a significant unfunded mandate for municipal solid waste programs,” said Paul Jewell, policy director with the Washington State Association of Counties.

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NY Targets Bronx Neighborhood as Part of Clean Transit Program

New York Gov. Kathy Hochul on Monday announced the winners of $3.4 million in funding from the state’s Clean Transportation Prizes program for 17 projects to decarbonize trucking and busing, including five in New York City.

“As New York continues to pursue its nation-leading clean energy and climate goals, we must ensure that we are not leaving behind our traditionally underserved communities,” Hochul said in a statement. “The transportation sector is one of New York’s largest sources of pollution, and, too often, low-income New Yorkers and communities of color are forced to bear the brunt of the consequences.”

Among the projects is one by Volvo to deploy an electric garbage truck and an electric refrigerated truck in the Bronx’s Hunts Point neighborhood, as well as build a new charging hub for the area’s two dominant sectors, food and waste.

The neighborhood, across the East River from Riker’s Island, hosts the largest wholesale food hub in the U.S., nine waste transfer facilities and several large recycling yards, as well as 13,000 residents, all in the southern part of the poorest urban congressional district in the U.S.

The prize program, administered by the New York State Energy Research and Development Authority, is intended to help the state achieve its target of an 85% reduction in greenhouse gas emissions by 2050. Each of the 17 winning projects will receive an award of up to $200,000, including $100,000 for further proposal development, up to $50,000 in funding for community partners, and up to $50,000 in in-kind support from technical consultants.

They will also be eligible to compete for larger prizes in Phase Two of the program, under which the Clean Neighborhoods Challenge, for example, includes up to three $10 million awards to innovative projects that address air pollution reduction at scale in underserved communities.

The state award for the Bronx project builds on an earlier city initiative to electrify trucking at Hunts Point, which in August directed a portion of its Volkswagen diesel settlement funds to purchase five new electric Volvo trucks.

“Targeting emissions from the transportation sector, particularly in communities that have been disproportionately impacted by pollution from cars and trucks, will advance efforts to reach New York’s ambitious greenhouse gas reduction goals while protecting public health and ultimately saving lives,” Department of Environmental Conservation Commissioner Basil Seggos said.

New York is trying to reduce transportation-related pollution not only through decarbonization, but also by increasing the availability of public buses and light rail and developing greenways to make bicycling safer and easier. (See NY Using Multitude of Strategies to Clean up Transit.)

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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.

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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.

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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.
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Long Permitting, Drought Put US Hydropower at Risk

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Joe Manchin (Senate ENR) Content.jpgSen. 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.”

Maria Cantwell (Senate ENR) Content.jpgSen. 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.jpgSen. 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 (Senate ENR) Content.jpgCamille 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.”

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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. 

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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.