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Omaha Public Power District to Build Solar Project On Landfill Site

January 13, 2023

by Peter Maloney
APPA News
January 13, 2023

Omaha Public Power District is using a $3.46 million grant from the Nebraska Environmental Trust to build a solar power plant at a former landfill site

The proposed OPPD-Douglas County SOLUS – for Solar on Landfills Utility Scale – project is a joint effort between OPPD and Douglas County and is sited on the Douglas County State Street landfill, a 160-acre parcel of land in Omaha. The landfill is capped and covered to isolate the waste, which limits the uses for the property.

“There are limited development opportunities directly on landfills, and utilizing the property for renewable energy is a win-win,” Kent Holm, director of Douglas County environmental services, said in a statement. “We already are using a third-party contractor to clean the landfill gas and pump it into [Metropolitan Utilities District’s] pipeline. Adding solar can be another positive step in utilizing the former landfill property and providing renewable energy.”

The first step in the development process is a feasibility study, which is slated to begin late this summer. The feasibility study will help determine the ideal size of the solar array and allow engineers to address any possible challenges, such as how to build around existing landfill features and the best way to fit it onto the contours of the land.

The NET grant will help support the cost difference between a typical ground-mounted utility-scale solar project and landfill solar project, which requires differences in design and construction.

OPPD said it plans to share what it learns from the project with other utilities that are interested in similar initiatives that provide benefits that extend well beyond the district’s 13-county footprint.

Extreme Weather, Fuel Constraints Drove High, Volatile 2022 Electric Prices

January 12, 2023

by Peter Maloney
APPA News
January 12, 2023

Extreme weather, compounded by natural gas and coal constraints, resulted in higher and volatile wholesale electric prices in 2022, according to the Energy Information Administration.

Prices at all electricity trading hubs were higher in 2022 compared with 2021, except in the Electric Reliability Council of Texas region where Winter Storm Uri pushed prices to $1.800 per megawatt hour in February 2021 and making ERCOT’s 2021 annual average electricity price higher than in 2022, the EIA said.

The EIA, a part of the Department of Energy, cited four severe weather-related events in 2022 that contributed to volatility and pushed wholesale prices higher last year.

Last January, cold temperatures and a winter storm, combined with natural gas pipeline constraints in New England, caused New England wholesale electricity prices to rise, averaging $160/MWh in ISO New England that month.

In July, a heatwave in Texas created record-breaking electricity demand in ERCOT while wind generation provided less electricity than usual for several days during the heatwave as wind speeds dropped precipitously. Natural gas-fired generation increased to make up for the drop in wind generation, pushing up prices at the ERCOT North trading hub, which averaged $182/MWh that month.

An early September heatwave in the western United States resulted in record-breaking electricity demand and rising prices. The price increases started in the Northwest, where the Northwest Mid-Columbia market hub’s wholesale electricity price averaged $224/MWh that month. In California, natural gas-fired generation increased in the generation mix, resulting in higher electricity prices. In the California ISO (CAISO) region, the wholesale electricity price averaged $134/MWh that month.

In December, cold weather and winter storms in the Western Pacific regions led to record-high electricity prices of $283/MWh at the Northwest Mid-Columbia market hub while CAISO’s N-15 hub hit $257/MWh.

Once again, cold weather increased demand, which increased natural gas-fired generation. And the cold weather, along with supply constraints, caused natural gas spot prices in the western hubs to rise to about 10 times those at Henry Hub, the national benchmark price.

Early last year, natural gas prices were pushed higher by economic growth in Asia and constraints on pipeline and liquefied natural gas (LNG) exports to Europe from Russia. Meanwhile high international demand for natural gas increased U.S. LNG exports, causing natural gas prices to rise for domestic customers. Natural gas prices rose from $3.70 per million British thermal units (MMBtu) in early January 2022 to almost $10/MMBtu in late August 2022.

Milder temperatures and increased natural gas production lowered natural gas and electricity prices after the September heatwave and through early November. Natural gas prices then started to rise again as colder weather set in.

The limited availability of coal to substitute for higher-priced natural gas also contributed to higher electricity prices.

In 2022, railroad and coal mine labor shortages constrained coal supply and delivery to power plants throughout the summer, limiting utility operators’ ability to switch from relatively expensive natural gas to cheaper coal-fired generation.

ISO New England Files Proposal to Use Storage as Transmission Resource

January 12, 2023

by Peter Maloney
APPA News
January 12, 2023

ISO New England in late December filed with the Federal Energy Regulatory Commission for approval to treat energy storage as a transmission asset.

The proposed change would create a new, separate class of storage resources that would not participate in the ISO’s wholesale electric power markets and would be purpose-built as transmission equipment and known as storage as a transmission-only asset (SATOA).

In the filing, made in conjunction with New England Participating Transmission Owners and the New England Power Pool, ISO New England said SATOA resources would have “minimal effect on wholesale electricity prices” because they would not be participating in those markets.

Under the proposal, SATOA resources would be owned and maintained by transmission companies, but ISO New England system operators would control their use. The resources would be used under rare system conditions to prevent localized overloading after at least two unplanned equipment outages on the transmission system, ISO New England said.

Construction of SATOA resources by transmission companies would depend on selection in the open regional system planning process administered by ISO New England, similar to the way the ISO now handles reliability-based system upgrades.

Energy storage resources, such as batteries and pumped hydroelectric facilities, already participate in ISO New England’s wholesale electricity markets by buying and selling capacity, energy, or ancillary services. In ISO New England’s most recent forward capacity auction, held in February 2022, more than 700 MW of battery storage secured capacity supply obligations.

To illustrate how SATOA resources could be used, ISO New England offered an example of a town served by three transmission lines. The town uses 100 megawatts of electricity and each transmission line is designed to supply 75 MW. If one transmission line were to be knocked out by a storm, the other two lines would continue to supply all the electricity the town needs with no problem. If the storm took down two lines, the remaining third line would be overloaded and a power outage would be imminent. But if there were a SATOA in the area, ISO system operators could activate it to provide power and relieve the strain on the transmission line.

Energy storage is growing rapidly in New England. Battery storage projects made up about 20 percent of the proposed generating capacity in the ISO’s generator interconnection queue as of May 2022, compared with 10 percent in July 2020 and less than 1 percent in May 2017.

The ISO has asked FERC to approve its rule change request by March 29 to allow implementation by a target date of July 1, 2024.

Connecticut Municipal Electric Energy Cooperative Brings Fuel Cell Microgrid Online

January 11, 2023

by Peter Maloney
APPA News
January 11, 2023

The Connecticut Municipal Electric Energy Cooperative has brought online a natural gas-fired fuel cell power station that will provide power to its municipal electric utility members.

The 7.4-megawatt (MW) fuel cell, sited on property leased from the U.S. Naval Submarine Base New London in Groton, Conn., (SUBASE) will also enhance the reliability of electric service provided to the SUBASE by CMEEC member Groton Utilities, whose public power electric distribution system is interconnected to the project.

The fuel cells will support SUBASE’s ability to isolate, or island, its power supply for critical loads to provide increased resiliency and energy security in the event of a broader grid outage.

“Ensuring the SUBASE has a resilient source of electric power is a strong priority for the Navy, Groton Utilities, CMEEC and also CMEEC’s partner in this project, Groton Station Fuel Cell, LLC, a subsidiary of Connecticut-based FuelCell Energy Inc., who owns and operates the project,” Dave Meisinger, CMEEC’s CEO, said in a statement.

In addition, Meisinger added, the clean energy output of the fuel cells will help to further Connecticut’s decarbonization goals as established by Governor Lamont and later codified by the state legislature.

In September 2018, Connecticut Gov. Dannel Malloy released of $5 million of state grant money to establish a microgrid at SUBASE. CMEEC had previously entered into an enhanced use lease agreement with the Navy for property on the SUBASE to host a fuel cell park.

CMEEC is a non-profit municipal joint-action electric supply agency that is a political subdivision of the State of Connecticut created in 1976. It provides the wholesale power supply requirements of six municipal electric utilities in Connecticut, as well as for other customers who purchase power at wholesale.

Its municipal electric utility members are Bozrah Light & Power, Jewett City Department of Public Utilities, Groton Utilities, Norwich Public Utilities, South Norwalk Electric and Water, and The Third Taxing District of Norwalk Electric Division. CMEEC also supplies the wholesale power requirements of the Mohegan Tribal Utility Authority.

California’s SMUD Receives Help from Public Power Community in Restoration Efforts

January 10, 2023

by Paul Ciampoli
APPA News Director
January 10, 2023

California public power utility SMUD this week worked to assess damage, make repairs, and restore power in the wake of recent storm-related damage and is receiving a helping hand from a large number of public power utilities from California and other states.

On Jan. 8, SMUD reported that the Sacramento region was hit by heavy rains and 70 mph-winds by the latest storm that ripped through Northern California overnight. Storm damage knocked out power to more than 345,000 SMUD customers at its height around 2 AM. As of 3:45 PM on Jan. 8, approximately 60,000 customers remained without power. 

The most recent storm was the worst storm in more than 30 years, eclipsing a New Year’s Eve storm. So far, SMUD has identified more than 80 downed power poles and dozens of downed trees impacting utility equipment, SMUD said on Jan. 8. “These numbers will grow significantly as assessments are completed,” it said.

SMUD line crews, troubleshooters and other field personnel will work 24/7 to restore power to customers if it’s safe to work, it said.

Crews made steady progress throughout the day last Sunday to assess damage, make repairs and restore power.

SMUD on Jan. 9 said that 100 teams were working to restore power after Sunday night’s storm brought hurricane force winds to parts of our region.

It said that many other utilities have come to support SMUD and its customers, including:

SMUD also said that it has received assistance from the California Utilities Emergency Association, Western Energy Institute and the Western Region Mutual Assistance Group.

The American Public Power Association has also been providing mutual aid assistance.

“I want to give a shout-out to SMUD’s field crews and staff across the company who are supporting this effort,” said SMUD CEO and general manager in a Linkedin post on Jan. 9. “Team SMUD, I couldn’t be prouder of you. Thank you for being safe and for working so hard for our customers. It has been a challenging time for all of us, but together we’re stronger and I’m proud to stand with you,” he wrote.

Environmental Protection Agency Proposes to Strengthen National Ambient Air Quality Standard

January 10, 2023

by Paul Ciampoli
APPA News Director
January 10, 2023

The U.S. Environmental Protection Agency on Jan. 6 announced a proposal that would strengthen a key national ambient air quality standard for fine particle emissions, also known as PM2.5.

EPA will specifically take comment on strengthening the primary annual PM2.5 standard from a level of 12 micrograms per cubic meter to a level between 9 and 10 micrograms per cubic meter. The agency is also taking comment on the full range (between 8 and 11 micrograms per cubic meter) included in the Clean Air Scientific Advisory Committee’s latest report.

Background

On December 18, 2020, EPA reviewed and retained the primary and secondary PM NAAQS without revision, by final rule. 

After President Biden took office in 2021, EPA decided to reconsider the 2020 final rule based on available scientific evidence and the Policy Assessment. The EPA also reconstituted the membership of the Clean Air Scientific Advisory Committee, which provides independent advice to EPA on the technical bases for National Ambient Air Quality Standards. That committee ultimately recommended tightening the annual and daily PM 2.5 NAAQS. 

All members of the committee agreed that the current annual PM 2.5 value of 12 micrograms per cubic meter should be lowered.  

An EPA policy statement concluded that the daily PM 2.5 standard should not be reduced.  EPA reasoned that “we reach the conclusion that, in conjunction with a lower annual standard level intended to increase protection against average short- and long-term PM2.5 exposures across the U.S., the evidence does not support the need for additional protection against short-term exposures to peak PM 2.5 concentrations.” 

EPA sent the Proposed Rule to the Office of Management and Budget on August 16, 2022.  OMB conducted a series of meetings before completing its review on December 27, 2022. 

The proposed rule supports lowering the PM2.5 primary annual standard, while taking comment on reducing other PM standards. 

Primary NAAQS standards focus on public health protections against the health effects caused by exposures to PM 10 and PM 2.5, while secondary NAAQS standards concentrate on visibility, climate, and materials effects. 

The implications of the proposed rule can be evaluated by reviewing the areas of the country that cannot attain a lower standard of 9.0-10.0 ug/m3.  EPA developed a map and table of vulnerable areas. 

Using 2019-2021 Air monitoring data, EPA identified 50 counties that would not meet the standard of 10.0 micrograms/cubic meter and 62 counties that would not meet 9.0 micrograms/cubic meter. 

The table identifies the counties that have monitors and provides the design values for each. A future nonattainment area might include a county not on this list (i.e., without an ambient monitor) that is part of a metropolitan statistical area that has a monitor out of attainment.  Overall, western states (California, Oregon and Washington) would have a large number of nonattainment areas, while select, populated urban areas in the east would be in nonattainment.

After the final rule, EPA will move toward the implementation process of designating areas as attaining/not attaining the new standard. States must then develop state implementation plans to address areas in nonattainment by incorporating air pollution control strategies to reduce PM. 

Under the Clean Air Act, EPA is required to set the NAAQS for the six criteria air pollutants, carbon monoxide, lead, nitrogen dioxide, ozone, particle pollution and sulfur dioxide.

There are two types of NAAQS, the primary standards that provide public health protection and the secondary standards that provide public welfare protection.

NAAQS are periodically reviewed and updated if EPA determines that there is a need for more stringent standard to protect the public health or welfare. The PM NAAQS were last reviewed and updated in 2012.

In June 30, 2020, APPA and the National Rural Electric Cooperative Association submitted joint comments in response to EPA’s 2020 proposal to retain the primary 24-hour PM2.5 standard, the primary PM10 standard, and the secondary standards.

Albertville, Ala., City Schools Receive Federal Funding for 19 Electric Buses

January 9, 2023

by Paul Ciampoli
APPA News Director
January 9, 2023

Albertville City Schools in Alabama will receive $7.5 million toward the purchase of 19 new electric buses through the Environmental Protection Agency’s Clean School Bus Program. 

Albertville’s Board of Education recently voted to move forward with the rebate program. The Clean School Bus program is a rebate competition for school districts. The rebate will fully cover 19 brand new electric buses and 10 charging stations. 

The 19 electric buses will replace older diesel-modeled buses in the fleet. Electric school buses have fewer moving parts than traditional diesel buses, resulting in lower maintenance costs.

Maintenance savings will be close to $10,000 each year, with another $40,000 estimated in yearly fuel savings. The new buses will generate an estimated $150,000 each year in fleet renewal funds for the next 10 years for Albertville City Schools.

As part of the rebate program, the system will scrap buses manufactured in 2010 or before. Buses manufactured after 2011 will be sold, which will generate additional income for the system. 

The Bipartisan Infrastructure Law of 2021 authorizes EPA to offer rebates to replace existing school buses with clean and zero-emission models to reduce emissions from older buses.

 In September, the EPA announced it would nearly double the funding awarded for clean school buses in 2022 following high demand from school districts across the United States that applied for the 2022 Clean School Bus Rebates. These awards represent the first $1 billion of a five-year, $5 billion program under the Bipartisan Infrastructure Law. 

The EPA received around 2,000 applications. High-needs school districts, including school districts with more than 20-percent of students in poverty, rural school districts, Tribal school districts and districts in underserved and overburdened communities were prioritized.

As a rural school district with more than 80% of its students living in poverty, Albertville City Schools was awarded a total of $7,505,000 to purchase the buses.

The rebate per bus totals $375,000, plus $20,000 per bus in infrastructure funding, which includes the purchase of the charging stations. Thanks to the rebate, the system will not incur any expenses in relation to purchasing the buses.

The Municipal Utilities Board in Albertville has offered to cover the expenses of a new meter and transformer, and the system will be able to utilize more parking at the transportation department thanks to the City of Albertville. 

Albertville will see the new additions to the fleet hit the road by the beginning of the 2023-2024 school year. Preparation for the on-site charging stations will begin as soon as March 2023.

The electric buses will make up around 30% of the fleet at Albertville and will be used for inter-district routes. Diesel buses will continue to be used for extracurricular trips. On a full charge, electric buses can go for 135 miles. Training will be available for drivers and maintenance technicians. 

Albertville City Schools will run the buses for at least five years and commit to an audit of the district’s expenditures to ensure they comply with federal program standards.

Orlando Utilities Commission Explores Deployment of Long-Duration Energy Storage Facility

January 9, 2023

by Paul Ciampoli
APPA News Director
January 9, 2023

Florida public power utility Orlando Utilities Commission will explore deployment of a long-duration energy storage facility as a way in which to help achieve the utility’s net-zero carbon emission goals, OUC said on Jan. 5.

The facility will be provided by Malta Inc. Malta’s storage technology converts excess electricity into thermal energy that is stored in salt and coolant. When needed, the plant regenerates gigawatt hours of electricity for residential and commercial use.

The Malta facility would be situated at OUC’s Indian River Plant in Brevard County on Florida’s East Coast.

Malta’s more than 100-megawatt utility-scale system provides more hours of energy storage than lithium-ion batteries and could provide energy storage diversity for OUC. The increased duration facility has the potential to help OUC ensure grid reliability despite the variable nature of clean and renewable energy resources like solar.

OUC’s Electric Integrated Resource Plan calls for ending the use of coal no later than 2027 and sets the utility on a course to reach net zero CO2 emissions by 2050, with interim carbon reductions of 50% by 2030 and 75% by 2040.

Pairing Malta’s energy storage system with OUC’s growing investment in solar would help achieve the utility’s carbon-reduction goals while also leveraging experienced staff to operate large energy storage projects like Malta, the utility said.

Reliability, Resiliency, Safety and Affordability Flow from Small Modular Reactor Technology

January 9, 2023

by Peter Maloney
APPA News
January 9, 2023

New nuclear technologies, such as small modular reactors (SMR), have reached a point where they are able to help utilities address growing concerns about fulfilling their core mission: delivering safe, affordable, and reliable electric power.

Several industry trends are challenging utility executives’ abilities to balance those three key objectives.

A July report from the North American Electric Reliability Corp. (NERC) highlighted the growing threats to reliability, including extreme weather events, the growing proliferation of “inverter based resources” such as photovoltaic solar power and energy storage, and increasing reliance on natural gas-fired generation.

The growth of renewable resources aimed at meeting state and federal goals aimed at addressing greenhouse gas emissions has been impressive. In the first half of the year, 24 percent of utility-scale generation in the United States came from renewable sources, according to the Energy Information Administration. However, as NERC pointed out this summer, as renewable resources have proliferated, gas-fired generators are becoming “necessary balancing resources” for reliability, leading to an interdependence that poses “a major new reliability risk.”

In this environment, if utilities are going to stay on track to meet their clean energy targets while providing secure, safe and reliable electric power to meet growing demand, they are going to need a new solution.

“NuScale Power’s SMR technology offers a carbon-free energy solution with features, capability, and performance not found in current nuclear power facilities,” Karin Feldman, Vice President of NuScale’s Program Management Office, said in an interview.

Several utilities have already begun exploring the potential of a new generation of nuclear technology to help them meet both their clean energy and reliability needs as they work toward meeting growing demand.

NuScale’s project portfolio includes a six module, 462-MW VOYGR™ SMR power plant. Utah Associated Municipal Power Systems (UAMPS) plans to develop at the Department of Energy’s (DOE) Idaho National Laboratory in Idaho Falls for their Carbon Free Power Project (CFPP).

NuScale also has memorandums of understanding to evaluate the deployment of its SMR technology with Associated Electric Cooperative in Missouri and Dairyland Power Cooperative in Wisconsin.

“What we bring to the table is a technology that is smaller and simpler; that lowers total costs while providing high reliability and resilience, and greater safety,” said Feldman, who develops and manages NuScale’s portfolio of projects and establishes and maintains project controls, cost estimating, and risk management standards. She is also NuScale’s primary interface with the DOE.

Cost Comparisons

The smaller scale of NuScale’s reactors – 77 MW versus 700 MW or even 1,600 MW or more for conventional reactors – brings several cost advantages, Feldman said. Smaller reactors can be fabricated in a factory, which is cheaper than field fabrication, because it involves repetitive procedures that foster iterative improvement and economies of scale, she said. Smaller reactors also take less time to build, which lowers construction costs.

Because they are modular, an SMR does not force a utility to commit to participation in a nuclear project in the 1,000-MW to 2,000-MW size range. An SMR project can be scaled to meet demand, and modules can be added as demand requires, Feldman said. That helps reduce financial risk for a utility, she said.

Another, related consideration, highlighted by the supply chain disruptions in the wake of the COVID-19 pandemic, is that much of NuScale’s technology can be locally sourced. “We are taking advantage of the U.S. supply chain to the greatest extent possible,” Feldman said. “We have some overseas manufacturers, but we are also engaged to develop additional U.S. capabilities in areas such as large-scale forgings.”

Reliability and Resiliency

Nuclear power plants generally have high reliability, over 92 percent, nearly twice the reliability of coal and natural gas plants, but the smaller, compact design of SMR technology can offer additional reliability advantages, Feldman said. Because NuScale plants are designed to scaled up in incremental steps, if any one of the individual reactors has an issue, the other reactors can continue to generate power, she explained.

NuScale’s SMR technology also enhances resiliency, Feldman said. The design calls for the reactors to be housed in a building below grade, hardening their vulnerability to airplane strikes and very large seismic events, she said.

An SMR plant also is designed with black start capability so that it can restart after a disruption without using the surrounding electric grid. “So, in the event of an emergency, it could be a first responder to the grid, one of the first generators to start up,” Feldman said.

And because the design calls for multiple reactors, a problem with one reactor does not require the entire plant to shut down. An SMR plant can also operate in island mode, serving as a self-sufficient energy source during an emergency, Feldman said.

In some ways, a NuScale SMR power plant resembles a microgrid. In fact, NuScale’s technology team has done a lot of analysis on microgrid capacity, Feldman said, noting that the analysis found that a 154-MW SMR plant could run for 12 years without refueling. “The technology is very good for mission critical functions and activities,” she said.

Safety First

Cost and resiliency are important considerations, but if a power plant, especially a nuclear power plant, is not safe, other considerations pale in comparison.

Safety is built into NuScale’s SMR design, Feldman said. “The SMR has a dual walled vessel design that gives it an unlimited coping period,” she said. “If an incident does occur, the plant can shut down without operator intervention or action and be safe and secure,” she said.

NuScale’s integrated design encompasses the reactor, steam generators and pressurizer and uses the natural action of circulation, eliminating the need for large primary piping and reactor coolant pumps.

If needed, the reactor shuts down and self cools indefinitely without the need for either alternating current or direct current power or additional water. The containment vessel is submerged in a heat sink for core cooling in a below grade reactor pool housed in a Seismic Category 1 reactor building as defined by the U.S. Nuclear Regulatory Commission (NRC). In essence, the unit continues to cool until the decay heat dissipates at which point the reactor is air cooled, Feldman said.

In 2018, the NRC found that NuScale’s SMR safety design eliminates the need for class 1E power, that is, power needed to maintain reactor coolant integrity and remain in a safe shutdown condition.

In August 2020, the NRC approved the overall design of NuScale’s SMR. In a next step, the NRC in July directed staff to issue a final rule certifying NuScale’s SMR design.

If approved, the certification would be published in the Federal Register and have the effect of law, providing even greater comfort to any entities exploring SMR technology to provide clean, emission free, reliable and affordable power, Feldman said.

The rulemaking is on NRC’s docket for a decision in November.

Finally, after a rigorous years long review by the NRC, the Final Safety Evaluation Report (FSER) regarding NuScale’s Emergency Planning Zone (EPZ) methodology was issued. This is another tremendous “first” for NuScale’s technology. With the report’s approval of our methodology, an EPZ that is limited to the site boundary of the power plant is now achievable for a wide range of potential plant sites where a NuScale VOYGR™ SMR power plant could be located.

Northern California Power Agency Signs Geothermal Power Agreements

January 9, 2023

by Peter Maloney
APPA News
January 9, 2023

The Northern California Power Agency recently signed a set of long-term power purchase agreements to supply renewable geothermal energy and capacity to Silicon Valley Power, the public power utility serving the City of Santa Clara, and potentially other NCPA members.

Under the agreements, signed with the Geysers Power Company LLC, an indirect subsidiary of Calpine, NCPA will purchase and receive renewable energy produced from multiple Calpine geothermal plants in California’s Sonoma and Lake Counties from 2025 to 2036.

The agreements provide for the initial delivery of up to 50 megawatts of renewable energy and capacity, increasing to up to 100 MW from 2027 through to 2036.

NCPA and Geysers Power both individually own and operate geothermal plants in The Geysers area, one of the largest geothermal steam fields in the world.

“This long-term agreement to secure renewable baseload generation only furthers that objective and will help to assure a continued supply of affordable and reliable power for SVP customers for many years to come,” Randy Howard. NCPA’s general manager, said in a statement.

NCPA, based in Roseville, is a California joint powers agency serving nearly 700,000 electric customers was established in 1968 to build and operate electric generation facilities and assist in meeting the wholesale energy supply needs of its 16 members: the cities of Alameda, Biggs, Gridley, Healdsburg, Lodi, Lompoc, Palo Alto, Redding, Roseville, Santa Clara, Shasta Lake, and Ukiah, as well as Plumas-Sierra Rural Electric Cooperative, the Port of Oakland, San Francisco Bay Area Rapid Transit, and the Truckee Donner Public Utility District.