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Chelan PUD Commissioners hear details on plan to expand conservation efforts

November 17, 2020

by Paul Ciampoli
APPA News Director
November 17, 2020

Commissioners for Washington State’s Chelan PUD on Nov. 16 heard a plan to expand energy conservation programs to focus on households that spend more than 6 percent of their income on power bills.

In Chelan County, about 2,100 households qualify as “high energy-burdened” because they spend more than 6 percent of their paychecks on electricity. About 98 percent of these households earn less than $20,000 a year.

PUD staff outlined a plan to launch a focused low-income energy assistance program in 2021. The PUD already offers rebates for energy-saving measures, including insulation, heat pumps and windows. Staff recommended greater engagement with nonprofits and landlords, as well as greater assistance to help low-income homeowners cover the up-front cost of home improvements.

PUD commissioners “expressed support to expand energy conservation, which would provide significant benefit to about two-thirds of the 2,100 high energy-burdened households,” Chelan noted in a news release.

“I believe we also have to remind ourselves that we work consistently to keep our rates lower than most of the country,” Commissioner Steve McKenna said. “That’s part of our ongoing commitment to provide rate relief.”

PUD staff will continue developing the program and report on progress in 2021.

Energy Northwest, partners bring solar-battery project online

November 17, 2020

by Ethan Howland
APPA News
November 17, 2020

Energy Northwest and its partners started operating Washington State’s first utility scale solar-plus-battery project.

The Horn Rapids Solar, Storage and Training Project, which includes 4 megawatts of solar and a 1-MW/4-megawatt-hours vanadium flow battery, came online this month.

The City of Richland, Wash., where the project is located, will buy electricity from the project.

Excess electricity from the solar panels will be stored by the battery system for later use, according to Energy Northwest, a joint action agency serving public power utilities with 1.5 million customers.

The battery storage component will help smooth the project’s solar output, support energy time shifting with peak demand reduction, offer demand side management options, and provide voltage and var support, according to the project’s developers.

Tucci Energy Services, a Seattle-based company, owns and operates the solar portion of the poject. Energy Northwest owns and operates the battery storage system.

“This project will provide clean and reliable power to families in this community while showcasing the role utility-scale solar and battery projects can play in our statewide energy strategy moving forward,” said Mary Tucci, Tucci Energy Services chief operating officer.

Pacific Northwest National Laboratory, part of the U.S. Department of Energy, and the University of Washington’s Clean Energy Institute will monitor and analyze data from the project to evaluate the financial benefits of incorporating battery energy storage, Energy Northwest said.

The information will be used to improve battery designs and develop tools for incorporating intermittent renewables onto the grid more reliably and economically, according to Energy Northwest.

The facility also houses a training program for solar and battery storage technicians. The program will be run and managed by Potelco Inc., an electric utility contracting firm based in Sumner, Wash.

Energy Northwest expects hundreds of workers from across the United States will use the training facility a year.

The roughly $6.5 million project received a $3 million grant from Washington’s Clean Energy Fund. The International Brotherhood of Electrical Workers, Local 77, which owns and leases the land where the project is located, worked with Energy Northwest and Potelco since 2015 to develop the project.

Groups urge FERC to reject objections to small utility opt-in mechanism under DER order

November 16, 2020

by Paul Ciampoli
APPA News Director
November 16, 2020

The American Public Power Association and the National Rural Electric Cooperative Association are urging the Federal Energy Regulatory Commission to reject objections to a small utility “opt in” mechanism that the Commission adopted in Order No. 2222, a final rule that allows for distributed energy resource (DER) aggregators to compete in regional organized wholesale electric markets.

In addition, APPA and NRECA said that FERC should not carve out an exception to the small utility opt-in for energy efficiency resources (EERs) in a Nov. 3 filing.

Order No. 2222, which FERC approved in September, enables DERs to participate alongside traditional resources in the regional organized wholesale markets through aggregations, opening U.S. organized wholesale markets to new sources of energy and grid services (Docket No. RM18-9-000).

In October, the Sierra Club, Sustainable FERC Project, and Natural Resources Defense Council filed a request for rehearing and clarification in response to Order No. 2222.

These groups argued challenged the final rule’s small utility opt-in on the grounds that “state authorities simply do not possess the power to directly determine whether resources are permitted to participate in RTO/ISO markets,” asserting that “such state actions directly ‘aim at’ wholesale transactions and are therefore field preempted.”

This argument “mischaracterizes the nature of the small utility opt-in, which is not a unilateral assertion of state and local authority over wholesale transactions, but rather a framework adopted by the Commission pursuant to its jurisdiction to establish the criteria for participation in wholesale markets,” APPA and NRECA said in a joint answer to the filing made by the Sierra Club, Sustainable FERC Project, and Natural Resources Defense Council.

NRECA and APPA pointed out that under the small-utility opt-in, state and local actions do not directly “aim at” FERC-regulated wholesale transactions.

“Rather, the Commission accounts for state and local preferences and concerns in determining eligibility to participate in wholesale markets.” In adopting the small-utility opt-in, the Commission “appropriately exercised its discretion to determine that, given the burdens that the final rule could impose on small utilities, retail customers of those utilities are not eligible to participate in DER aggregations under Order No. 2222” unless the relevant electric retail regulatory authority affirmatively allows such retail customer participation.

“This is an exercise of the Commission’s jurisdiction, not an intrusion upon it,” APPA and NRECA said.

APPA, NRECA also argue that FERC should not carve out an exception for EERs

Meanwhile, APPA and NRECA told FERC that it should not carve out an exception to the small utility opt-in for EERs.

That proposal was made in an Oct. 19 request for clarification, or, in the alternative, rehearing filed by Advanced Energy Economy (AEE) and Advanced Energy Management Alliance (AEMA).

“As a threshold matter, AEE and AEMA do not establish that participation of EERs in DER aggregations could have no impacts on small distribution utilities or their regulators that justify providing the opt-in,” APPA and NRECA argued.

AEE and AEMA pointed to the Commission’s assertion in a case involving AEE that, compared to demand response, EERs are not likely to present the same operational and day-to-day planning complexity that might otherwise interfere with a load-serving entity’s day-to-day operations.

But FERC “never said that EER wholesale market participation could impose no obligations on distribution utilities, nor would such an assertion be accurate,” APPA and NRECA noted.

“For example, a small distribution utility with EERs on its system participating in an aggregation might need to monitor how any capacity provided by the EERs was accounted-for in determining the utility’s resource adequacy obligations.”

Similarly, under Order No. 2222, small distribution utilities and/or their regulators might need to coordinate with RTOs and ISOs concerning whether a resource participating in a state or local energy efficiency program should be restricted from participating in a wholesale aggregation under the provisions of Order No. 2222 that are designed to avoid double compensation, APPA and NRECA said

“Indeed, just the obligation for distribution utilities and their regulators to monitor and track the complex RTO and ISO rules that will govern DER aggregation could impose a significant burden on small distribution utilities.”

Further, the fact that EERs are not subject to the Commission’s opt-in/opt-out regulations under Order Nos. 719 and 719-A is not a reason to exclude EERs from the small utility opt-in, as AEE and AEMA contend, the public power and cooperative trade groups argued. Order Nos. 719 and 719-A addressed improvements to RTO governance.

Final rule builds off recent court ruling on Order No. 841

FERC in September said that Order No. 2222 builds off a ruling earlier this year from the U.S. Court of Appeals for the District of Columbia Circuit on Order No. 841 in which the court affirmed the Commission’s exclusive jurisdiction over the regional wholesale power markets and the criteria for participation in those markets.

In July, the appeals court issued an opinion that denied an appeal filed by the American Public Power Association and several other parties that challenged certain aspects of Order Nos. 841 and 841-A, which established rules for the participation of electric storage resources in RTO and ISO markets. 

Public power utilities respond to power outages caused by ice storms

November 16, 2020

by Paul Ciampoli
APPA News Director
November 16, 2020

Oklahoma public power utilities embarked on a large-scale restoration effort after a historic ice storm caused widespread outages the week of October 26-31, the Oklahoma Municipal Power Agency (OMPA) reported on Nov. 12.

OMPA said that statewide, more than 300,000 customers lost power in the first 24 hours of the storm, due mainly to fallen trees.

Utilities in Oklahoma typically employ tree-trimming programs to avoid such disasters, but this storm came earlier in the year than normal and dumped several inches of ice onto trees that still hadn’t lost their leaves, thus impacting trees that had sustained decades worth of winters.

The state’s public power utilities deployed their mutual aid program to get customers back online, as crews from around the state answered the call for assistance, as well as crews from utilities in Arkansas, Kansas and Missouri.

Fourteen of the OMPA’s 42 members suffered outages in the first day of the storm, while another 15 experienced outages in the following days, impacting thousands of customers. One public power utility with just less than 16,000 customers had 260 different individual outages on the second day of the storm.

Several of the outages OMPA members saw lasted days, some the entire week, due to the extensive damage sustained from the fallen trees. However, all OMPA members had power restored by Monday, November 2, with a few remaining service drop issues.

OMPA offered thanks to the following crews for assisting members with outage restoration:  GRDA; Tahlequah, OK; Claremore, OK; Skiatook, OK; Pryor, OK; Collinsville, OK; Stilwell, OK; Bentonville, AR; Wellington, KS; Coffeyville, KS; Siloam Springs, AR; Monet, MO and OMPA Field Services.

NPPD helps Burt County Public Power District restore power

Meanwhile, in partnership with other public power utilities, Nebraska Public Power District assisted Nebraska’s Burt County Public Power District in making repairs after a hard-hitting ice storm earlier this month.

Along with NPPD, crews from the following utilities assisted Burt County Public Power District assisted with power restoration efforts: Elkhorn Rural Public Power District, North Central Public Power District, as well as Niobrara Valley Electric Membership Corporation.

Snohomish PUD signs deal to move forward with vehicle-to-grid charging

November 13, 2020

by Peter Maloney
APPA News
November 13, 2020

Snohomish County Public Utility District in Washington State has contracted with Mitsubishi Electric, Hitachi ABB and Doosan GridTech to install two electric vehicle-to-grid (V2G) chargers.

The V2G chargers are being sited at Snohomish PUD’s Arlington microgrid site and will be able to charge an electric vehicle and also send the stored energy back to the grid during a power outage.

Snohomish PUD began planning its Arlington microgrid project four years ago. It is now nearing completion, which is expected in January 2021. The $9 million project, which includes a $3.5 million grant from the Washington Department of Commerce, includes a 500-kilowatt (kW) solar array and a 1-megawatt (MW), 1.4-megawatt hour (MWh) battery system, as well as the two Mitsubishi two-way capable electric vehicle chargers.

Doosan’s DERO distributed energy resource management system (DERMS) will control the Arlington microgrid’s energy storage system, as well as the electric vehicle charging stations when grid connected. Doosan is also partnering with Awesense, a Canadian software company that is integrating its digital energy platform with Doosan’s DERMS to gather more granular data on the distributed energy resources, V2G devices and other assets involved in the project to provide accurate, real-time data and analytics.

The microgrid is designed to support a new local office that Snohomish PUD is building in Arlington, north of the utility’s Everett headquarters, to accommodate growth in the northern part of the county.

The microgrid will allow Snohomish PUD’s Arlington operations center to continue to operate in the case of an outage. But the microgrid will also be able to provide revenues when the system is connected to the grid in the form of ancillary services such as peak shaving, energy arbitrage, and capacity firming.

For instance, the solar-plus-storage microgrid will be able to offset charges Snohomish PUD would have to pay its wholesale power provider, Bonneville Power Administration, to provide capacity firming, also known as solar smoothing, during times when solar output drops because of conditions such as cloud cover.

In that way, the microgrid is “earning its keep,” Scott Gibson, project manager for the Arlington microgrid, said. “It is benefitting the grid daily. It is a solar powered emergency generator with a day job.”

Snohomish PUD plans to use the two-way capable electric vehicle chargers to power up utility electric vehicles. Snohomish PUD is just starting to build up its electric vehicle fleet, Gibson said.

Currently, the utility has four electric vehicles, two Nissan LEAFs and two Kia Niros. The LEAFs will be used for the V2G system.

While V2G technology has often been touted as a promising form of mobile storage for the grid, achieving that promise is more difficult. “There is a big controversy with V2G, about whether to use public vehicles or fleet vehicles,” Gibson said. “In our opinion, it is tough to find the right incentive to allow owners to let us use their vehicle.” An electric vehicle that is also feeding the grid would be charging and discharging more frequently than a vehicle that is only being used for transportation and that degrades the battery more rapidly. “Everybody is struggling with that,” Gibson said.

A utility, on the other hand, can monetize the discharge functions of an electric vehicle for the benefit of the grid. Gibson noted that if a utility were to have 16, 60-kWh Nissan LEAF electric vehicles, it would essentially have 1 MWh of storage.

“We see this as an important step in our ‘utility of the future’ vision and for SnoPUD to be one of the premier utilities in the country,” John Haarlow, the utility’s CEO and general manager, said in a statement.

While the Arlington microgrid is a pilot project, it is “an actual functioning system,” Gibson noted. There are a lot of similar demonstration projects but “this will be one of the first to truly put a functioning grid connected V2G system together,” he said.

Among the challenges that come with building a pioneering project is integrating the various pieces of the system. “Electrically the system is pretty simple,” Gibson said, but getting the different controllers to talk to each other is a challenge.

The Mitsubishi V2G chargers have their own control system, which must talk to the microgrid control system, a task made more difficult because control of the microgrid depends on how it is being used.

When the microgrid is connected to the grid, it will be controlled by Doosan’s DERMS system. When the microgrid separates from the grid during an outage and is in islanded mode, it will be controlled by the Hitachi-ABB microgrid control system. “It is really a unique system,” Gibson said.

In the initial stages, Snohomish PUD’s recovery of its investment in the microgrid project will be learning, Gibson said. “When the energy market changes, though, there will be more value and we will be able to step right in and take advantage of that.”

“We have an incredibly supportive commission and general manager, who all see this as part of our future” Gibson said. With that vision, “the more we invest, the more we can take advantage of it.”

WAPA, Municipal Energy Agency of Nebraska and others to evaluate SPP membership

November 13, 2020

by Paul Ciampoli
APPA News Director
November 13, 2020

Southwest Power Pool (SPP) on Nov. 12 reported that it has received letters from several western power entities committing to evaluate membership in the organization.

If they pursue membership, Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska (MEAN), Tri-State Generation and Transmission Association, and Western Area Power Administration (WAPA) would become the first members of SPP’s regional transmission organization to place facilities in the Western Interconnection under the terms and conditions of SPP’s open access transmission tariff.

SPP said that WAPA’s evaluation of RTO membership will consider the participation of its Upper Great Plains-West region and Loveland Area Projects. “This would extend the reach and value of SPP’s services — including day-ahead wholesale electricity market administration, transmission planning, reliability coordination, resource adequacy and more — and the synergies they provide when bundled under the RTO structure,” SPP said in a news release.

Basin Electric, MEAN, Tri-State and WAPA’s Upper Great Plains-East Region are already members of SPP, having joined the RTO in 2015 when they placed their respective facilities in the Eastern Interconnection under SPP’s tariff.

Along with Deseret, each is also a customer of at least one of SPP’s contract-based Western Energy Services, which includes reliability coordination and a real-time market scheduled to launch in February 2021.

The companies’ letters indicate they will now work with SPP to evaluate the terms, costs and benefits of putting western facilities under the RTO’s tariff.

A recent SPP Brattle study found that WEIS participants’ membership in the SPP RTO would produce approximately $49 million in savings annually for SPP’s current and new members.

The RTO said that the western utilities joining SPP would receive $25 million a year in adjusted production cost savings and revenue from off-system sales, and SPP’s members in the east would benefit from $24 million in savings resulting from the expansion of SPP’s market, transmission network and generation fleet.

SPP said its prior calculations of the value of RTO membership suggest that these benefits are only a portion of those current and new members will derive. There is additional value not considered by the Brattle study in five-minute real-time economic dispatch, achievement of public policy goals, lowered reserve-margin requirements, consolidation and regionalization of planning and other processes and more, the grid operator said.

SPP launched its first real-time balancing market in 2007 then transitioned to a day-ahead market and became a single, consolidated balancing authority in 2014.

It first began serving customers in the west in December 2019 when it launched its Western Reliability Coordination service on a contract basis.

SPP is awaiting FERC approval to implement a western energy imbalance service market that it plans to launch in February 2021.

FERC in July rejected the SPP proposal for a western energy imbalance service market. At the same time, FERC offered guidance for a modified proposal should SPP choose to submit one. SPP then submitted a modified western energy imbalance service market proposal in October.

CAISO Western EIM

Earlier this year, the California Independent System Operator signed an implementation agreement with Xcel Energy-Colorado, which paves the way for its participation in the CAISO Western EIM in 2022.

The agreement also provides for participation of three other utilities: Black Hills Energy Colorado Electric Colorado Springs Utilities, and Platte River Power Authority.

The four utilities currently share resources and balance demand for electricity during peak periods through a Joint Dispatch Agreement.

These utilities launched a study in 2019 to determine which market, the WEIS proposed by SPP or CAISO’s Western EIM, would provide greater benefits to customers.

The Colorado utilities also report that the Western EIM has lower administrative costs and is exploring adding day-ahead market services, which could help participants to make wider use of renewable energy resources.

New England public power utilities sign PPAs for hydroelectric power

November 13, 2020

by Peter Maloney
APPA News
November 13, 2020

A total of 21 public power utilities in New England have signed agreements to purchase 200 million kilowatt-hours (kWh) per year of hydroelectric power produced by FirstLight Power in Western Massachusetts.

The purchase agreement, which was structured and executed by Energy New England, will take energy from the Turners Falls and Cabot generating facilities on the Connecticut River in Montague and will save the participating utilities’ ratepayers millions of dollars over the life of the contract, according to Energy New England, a wholesale risk management and energy trading organization serving public power utilities in the northeast.

“Never before have so many municipal light plants, municipal electric departments, and other public power utilities come together to buy emissions-free renewable power on this scale,’’ John Tzimorangas, president and CEO of Energy New England, said in a statement.

Power purchases by Massachusetts public power utilities served by Energy New England on average now account for 29% fewer carbon dioxide (CO2) emissions than electricity generated in the state as a whole, Energy New England said, adding that the new contracts will raise the public utilities’ average to 34% below the state average.

FirstLight and Energy New England offered an excellent opportunity for Reading Municipal Light Department “to increase its portfolio of local renewable energy at competitive rates for our customers in the four towns we serve,” Coleen O’Brien, general manager of the Reading utility, said in a statement.

The participating utilities are mostly in Massachusetts and include:

Also participating are the Block Island Utility District and Pascoag Utility District in Rhode Island and Stowe Electric Department in Vermont.

FirstLight Power is a clean power producer and energy storage company in New England with a portfolio that includes nearly 1.4 gigawatts of pumped hydro storage, battery storage, hydroelectric generation, and solar generation.

NREL report says EV charging stations continued strong growth in early 2020

November 12, 2020

by Paul Ciampoli
APPA News Director
November 12, 2020

During the first three months of 2020, public electric vehicle supply equipment grew 7.6%, according to a new report from the National Renewable Energy Laboratory (NREL).

Of that, direct-current fast chargers made up the largest piece of the pie, expanding by 10.6%, NREL said in the report.

The metrics build on a consistent upward trend across the country for charging stations, according to Abby Brown, a project manager in NREL’s Sustainable Transportation Integration group and co-author of the report.

“Since about 2011, we’ve seen strong year-over-year growth in charging infrastructure,” she said in a statement. “Between December of 2015 and 2019 alone, for example, the number of charging stations doubled. It was much the same in early 2020: more growth in all parts of the country.”

NREL reported that while all regions saw substantial growth during the quarter, a few stood out.

The Northeast (Maine, New Hampshire, Vermont, New York, Massachusetts, Rhode Island, and Connecticut) saw an increase of over 10%, the fastest growth in the country.

California’s charging infrastructure grew by 9%, “even as it continued to boast the largest share of the country’s public charging infrastructure,” NREL said.

The states with the highest rate of charging stations per 100,000 people were Vermont (105.3), California (64.0), Washington D.C. (63.3), Hawaii (47.7), and Colorado (40.9).

Private electric vehicle supply equipment, such as charging for transit fleets or employees only, grew by 3.2%, bringing the total of private electric vehicle supply equipment to nearly 14,000.

Direct-current fast and Level 2 electric vehicle supply equipment are 49.6% and 12%, respectively, of the way toward meeting projected 2030 charging demand for 15 million EVs, though 56.2% of public direct-current fast chargers are only available to Tesla drivers, NREL said.

ChargePoint made up nearly 44% of public electric vehicle supply equipment in the station locator, the largest of any charging network.

The report’s statistics tap data from the Alternative Fueling Station Locator, which NREL said is the most widely used tool on the Department of Energy’s Alternative Fuels Data Center.

The report is available here.

Vanderbilt University, Nashville partner with TVA, NES on new solar farm

November 12, 2020

by Paul Ciampoli
APPA News Director
November 12, 2020

Vanderbilt University and the city of Nashville, Tenn., recently announced a Green Invest partnership with the Tennessee Valley Authority and Nashville Electric Service that calls for the construction of a solar farm to be built in Tullahoma, Tenn., by Nashville-based Silicon Ranch Corp.

Vanderbilt will be a 25-megawatt co-subscriber to the array for campus operations. The new solar farm project is scheduled for completion in 2023.

This marks the university’s second solar project with TVA, NES and Silicon Ranch through TVA’s Green Invest program.

In January, TVA reported that a partnership between Nashville Electric Service, Vanderbilt University and TVA to bring new, large-scale renewable energy to the Tennessee Valley marked the first of its kind under the Green Invest program.

TVA’s Green Invest program leverages long-term agreements to build new, large-scale renewable energy installations through a competitive bid process.

In other recent Green Invest news, TVA on Nov. 9 said that a new 100-megawatt solar facility in Obion County, Tenn., will supply energy to Google’s data centers in Clarksville, Tenn., and Hollywood, Ala.

Tacoma Power proposes rate to support renewable electrofuel producers

November 10, 2020

by Peter Maloney
APPA News
November 10, 2020

Tacoma Power has filed a pilot rate to support the production of carbon neutral fuels known as electrofuels that could be substitutes for traditional fossil fuels.

Electrofuels are typically made from electricity, water and air. The resulting synthetic fuel can have a variety of forms and uses including the transportation sector. Renewable energy produced by wind, solar and hydropower resources that might otherwise be wasted can be stored as a renewable or “green” fuel.

In a filing with Tacoma’s Public Utility Board (U-11206), the public power utility noted that electrofuel producers could operate differently than most industrial customers because the production process can be interrupted on very short notice and be shut down for extended periods. The production of renewable electrofuels is flexible because the resulting fuel can be stored. That flexibility would allow Tacoma Power to request curtailment of the production process at times when electricity demand and prices are high.

Tacoma Power had conversations with several hydrogen producers, Clay Norris, the utility’s Power Management manager, said. “We realized their business model is driven by electricity costs. We also realized the flexibility of their production. We were looking to take advantage of that flexibility to get to a win-win outcome,” he said.

The proposed renewable electrofuel rate could call upon the customer to curtail their electric service for a minimum of 15% of the hours during a year. Participants in the pilot program would also have to be willing to curtail production within 10 minutes of notification for a minimum of one hour and up to three days. The pilot program is currently capped at 65 megawatts (MW).

In return, the utility would offer renewable electrofuel producers rates lower than standard industrial rates. The utility added that renewable electrofuel producers would not likely site facilities in its territory without this pilot rate.

The Renewable Electrofuel Service Pilot was approved by Tacoma’s Public Utility Board on Oct. 28 and is now awaiting approval before the city council. The city council has scheduled hearings on the proposal for November and December. If approved, the rates would take effect April 15, 2021, and the pilot program would end in 2030.

The electrofuel rates are designed to provide a benefit to the utility through increased retail sales, Tacoma Power said in the filing, adding that it does not anticipate a cost associated with the new rate.

Tacoma Power also noted that the new rates could benefit existing utility customers by providing several million dollars a year in revenues from electricity sales to electrofuel producers that the utility would otherwise sell into the wholesale market. In addition, an electrofuel customer represents a long-term energy sale that could generate positive margins, lowering rates for existing customers. And, finally, the community as a whole would benefit from the creation of jobs and additional tax revenue for the city, the utility said.

Tacoma Power would not have to procure firm capacity to serve electrofuel production load. If a regional resource adequacy program were established, the new rate could be characterized as a demand response program – the utility’s first – and would qualify as capacity and, therefore, would not burden existing customers with incremental costs.

Other utilities may adopt similar programs, which would lead to wide-spread beneficial use of surplus renewable power, Tacoma Power said in the filing.

The new interruptible load from hydrogen producers on Tacoma Power’s system would be a useful tool. “For the West Coast in particular, it is a power manager’s dream,” Norris said.

“Meeting climate change policy targets will be impossible without substantial electrification of infrastructure traditionally dependent on fossil fuels,” the utility said in the filing.

Other public power utilities in the Pacific Northwest have been exploring alternatives to fossil-based transportation fuels. The Eugene Water and Electric Board in Oregon last month signed a memorandum of understanding to explore the development of a production facility for renewable hydrogen that could be used in the region’s heating and transportation sectors.

And the Douglas County Public Utility District in Washington and its partners have received a $1.9 million grant from the Centralia Coal Transition Board to fund a demonstration project for the first hydrogen fueling station for fuel cell electric vehicles in Washington state.