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NAESB report addresses need for digital technologies standards

December 18, 2020

by Peter Maloney
APPA News
December 18, 2020

The North American Energy Standards Board (NAESB) has adopted a report by its digital committee concerning the development of standards for the digital transformation taking place in the energy industry.

The report summarizes a series of conference calls and surveys conducted by NAESB’s board of directors and digital committee and is intended to aid NAESB as it considers new standards to support digital technologies.

Included among the digital committee members is Valerie Crockett, senior program manager for environment and energy policy at the Tennessee Valley Authority.

The report said that industry sectors ranging from energy, finance, manufacturing to healthcare are taking advantage of digital technologies that have lowered the cost of data collection, storage and processing and are enabling advanced analytics to drive better performance, increase productivity and support better strategic decision making.

The report paid particular attention to technologies, such as the use of distributed ledgers or the implementation of 5G networks, that have the potential “to alter the manner in which the transactions governed by NAESB standards take place.”

The NAESB report reviewed nearly a dozen technologies: distributed ledger technology (also known as blockchain technology), data governance requirements, cybersecurity, distributed energy resources, cloud computing, renewable energy certificate/credit tracking, deployable shareware, Internet of Things (IoT), 5G technologies and implementation, data analytics, and energy usage data.

Many of those technologies are already being deployed and are increasing efficiencies, and the development of supportive standards could accelerate their adoption and reduce the likelihood of “developing solutions that must be retrofitted to support interoperability with other technologies,” the report said.

In a 2018 meeting, NAESB’s board recommended that the organization begin looking at the impact digital technology could have on the energy sector.

Research and a series of discussions found that global investment in digital technologies by energy companies has risen over 20% annually since 2014 and that in 2016 an estimated $47 billion was invested in digital electricity infrastructure alone, a level 40% higher than worldwide investment in gas-fired power generation.

NAESB’s research also found that other standards organizations, such as the International Organization for Standardization, SAE International and ANSI, are pursuing digital transformation standards and have created groups within their organizations or held meetings to focus on exploring how new digital technology is transforming their industry sectors.

The report recommended that NAESB’s board continue “standards development efforts” for two technologies in particular – distributed ledger technology and cybersecurity – and monitor the other technologies identified in the report as “strongly relevant to the processes/transactions that NAESB standards currently address or may address in the future.”

The report noted that NAESB is currently developing standards to support distributed ledger technology in the wholesale and retail electric and gas markets.

NAESB’s Wholesale Gas Quadrant is working to conclude development of a standard to support conversion of the NAESB Base Contract for Sale and Purchase of Natural Gas into a digital “smart” contract that can be used with distributed ledger technology. And NAESB’s Wholesale Electric Quadrant and Retail Market Quadrants are jointly developing a standard contract to improve and automate the current voluntary renewable energy certificate processes.

NAESB’s Wholesale Electric Quadrant is also considering developing standards related to distributed ledger technology to support the accounting-close cycle for power trading.

The report also recommended that NAESB should continue to develop standards that support cybersecurity for the transactions the standards address and develop standards to support specific digital technologies, as well as review the finding of reports from Sandia National Laboratories and recommend any modifications that “may be necessary to support a new model for the implementation of NAESB cybersecurity standards.”

With respect to other technologies, the report identified the Internet of Things technology as an “emerging high interest and high value area for standards development.” The adoption of IoT technologies “will drive the need for new standards that support both privacy and cybersecurity, especially when used within operational or control environments,” the report said.

The report also identified data analytics as a technology that is relevant to the processes and transactions that the NAESB standards will address in the future, but noted that one-third of respondents to a NAESB survey said data analytics is not an area relevant to NAESB and that NAESB standards are not needed.

As with other emerging technologies, such as renewable energy credit contracts, the report recommended that NAESB should continue to monitor the development and adoption of the technology to determine if standards development is necessary.

The report also identified 5G technology as an area that received strong support as being relevant, but 50% of survey respondents said standards are not needed or that adequate standards are already in place.

The report is available here.

Public power utilities and blockchain

Several public power utilities are exploring blockchain technology.

A Sacramento Municipal Utility District project that is being funded in part through an award from the American Public Power Association’s Demonstration of Energy & Efficiency Development program will utilize blockchain-enabled tokens as part of an effort to encourage EV owners to charge their vehicles at workplaces when local renewables peak during the day.

In 2018, the Burlington Electric Department in Vermont won a grant from the DEED program to use blockchain technology to facilitate the integration and distribution of energy from multiple sources in real time.

Meanwhile, another California public power utility, Silicon Valley Power, and Power Ledger successfully completed the first stage of a program to test the use of blockchain technology for tracking and monetizing carbon dioxide reduction credits for electric vehicle charging and now plan to proceed to the second phase of the project.

In 2018, Silicon Valley Power used Power Ledger’s blockchain-backed platform to track and manage Low Carbon Fuel Standard (LCFS) credits at the Tasman Drive parking garage in Santa Clara, Calif., which has a 370 kW solar system and 49 electric vehicle charging stations.

Danville Utilities in Virginia has plans for a 10.6-MW battery storage system

December 18, 2020

by Peter Maloney
APPA News
December 18, 2020

Public power utility Danville Utilities in Virginia is moving forward with a battery energy storage project designed to shave its peak charges and save the utility and its customers money.

The Danville Utility Commission at its Nov. 30 meeting voted unanimously in favor of the 10.6-megawatt (MW), 23.3 megawatt hour (MWh) project.

The proposal is scheduled to be discussed at a work session of the Danville city council on Jan. 5. If it moves forward, the proposed project will be on the agenda for a vote on final approval at the council’s Jan. 19 meeting.

If approved, Danville Utilities is targeting Dec. 1, 2021 for operation of the battery system. It would be the public power utility’s first energy storage system.

“We are looking to take advantage of the battery storage system to reduce our exposure during generation and transmission peaks,” Jason Grey, director of Danville Utilities, said.

Not being an all-requirements utility, Danville gets is electrical power and transmission services from a variety of sources, including the PJM Interconnection. Danville, which is on the Virginia-North Carolina border, is just a couple of miles within the limits of PJM’s territory.

Danville Utilities has been looking at a battery system for well over a year but didn’t pursue one. “We kept an eye on battery prices and revisited the idea when prices came down,” Grey said.

If the project is approved, Danville Utilities would enter into a 20-year capacity agreement with Delorean Power, the Arlington, Va., company that would build, own and operate the storage system. The project is sited on an unused plot of land, about 100 feet by 70 feet, outside a utility warehouse in Danville.

Under the agreement, Danville Utilities would pay $4.25 per kilowatt per month, or about $541,000 in the first year with the costs declining slightly thereafter to reflect the 1.5% annual decline in battery capacity.

The utility would charge the batteries during off-peak hours when energy prices are lower and discharge the batteries during on-peak hours to offset or avoid transmission and energy capacity costs.

By the utility’s estimates, Danville would save $1.2 million in transmission and capacity costs in the first year of the agreement. And, over the 20-year life of the agreement, the utility would spend about $9.6 million in capacity payments to Delorean but save about $48.3 million in generation and transmission capacity charges.

Because so many transmission owners are implementing upgrades, transmission charges have been rising about 15% every year, Grey said.

By using the batteries to shave the peaks off its capacity charges, Danville Utilities expects to also be able to reduce its power cost adjustment, the sum that the utility charges customers to cover the over- or under- payment customers make through their monthly base rate. “When we can lower our power cost adjustment, it helps ratepayers,” Grey said.

The proposed battery storage project is kind of a trial, Grey said. “We hope to learn about the technology” and decide if it is a viable solution. “If it performs as anticipated, we could do another project in two or three years.”

Starbucks enters into first-ever ‘virtual’ storage PPA

December 17, 2020

by Ethan Howland
APPA News
December 17, 2020

Starbucks Corp. is entering into solar and solar-plus-storage virtual power purchase agreements to support its corporate sustainability goals.

One of the contracts is tied to a 1,200-megawatt solar project that is combined with energy storage that can deliver 2,165 megawatt-hours before needing to be recharged, according to LevelTen Energy, which runs a marketplace for renewable energy.

Under the deal with Terra-Gen, Starbucks is contracting for 24 MW of solar and 5.5 MW of battery storage from the Edwards and Sanborn project in Kern County, California. The project is expected to be fully online before 2023, according to Terra-Gen, a renewable energy developer owned by Equity Capital Partners, a private equity firm.

Other offtakers from the Edwards and Sanborn project include San Jose Clean Energy, which is buying 162 MW from Terra-Gen.

Starbucks is the first corporation to execute a virtual PPA for utility-scale storage, according to LevelTen, which helped arrange the transaction.

A virtual PPA is a financial deal under which the buyer pays a set price but doesn’t directly buy electricity from the project. Power from the project is sold into the wholesale market. If the wholesale price is higher than the price in the virtual PPA, the offtaker receives the difference. If the price is lower, the offtaker pays the facility owner to make up the difference.

“This new contract not only provides corporate buyers the economic benefits of storage, but also delivers developers a guaranteed revenue stream, enabling a more practical method for storage project financing,” LevelTen said Dec. 9 when Starbucks announced its deals.

Until now, contracting with utility-scale storage project developers was impractical for most corporations, according to LevelTen.

Stored renewable energy can be sold during the highest-priced hours of the day, often displacing coal- or natural gas-fired generation, the Seattle-based company said.

Also when organizations add storage to their wind and solar power purchase agreements, it can add value and smooth pricing variability by extending the hours of the day the energy is sold, LevelTen said.

“By providing a more practical way to contract with storage developers, this type of financial agreement opens the door to billions of dollars of investment in large-scale energy storage projects, in much the same way virtual power purchase agreements … ushered in a wave of wind and solar project development in the U.S. and beyond,” LevelTen said.

Starbucks also entered into a virtual PPA with an undisclosed solar farm in Virginia. The contract will offset half of its company run roasting and beverage production sites’ electricity use in the United States by 2022.

The coffee company said it is investing about $97 million in up to 23 new community solar projects in New York, which will supply solar energy to more than 24,000 homes, small businesses, nonprofits, churches, universities and Starbucks stores.

Starbucks aims to cut in half by 2030 the greenhouse gas emissions from its direct operations and supply chains.

NERC: Long-term resources are sufficient, except in Ontario and MISO

December 17, 2020

by Peter Maloney
APPA News
December 17, 2020

There should be sufficient resources to meet electric power demand over the next 10 years, except in two areas, according to a new report from the North American Electric Reliability Corp. (NERC).

NERC’s 2020 Long-Term Reliability Assessment estimated there would be adequate resources except in Ontario and the Midcontinent Independent System Operator (MISO) regions where projected reserve margins could fall below reference margin levels.

And while bulk power system capacity is sufficient in the other areas of North America, some areas demonstrate the potential for insufficient resources. Specifically, NERC identified “nearly all parts of the Western Interconnection,” the Electric Reliability Council of Texas (ERCOT) area and MISO as areas that “show levels of increased risk over the next five years.”

Overall, NERC’s long-term assessment noted that “the addition of variable energy resources, primarily wind and solar, the continued growth of distributed energy resources (DER) and the retirement of conventional generation are fundamentally changing how the grid is planned and operated.”

“As the system becomes more reliant on wind and solar generation, resource and energy adequacy must be assured,” Mark Olson, manager of reliability assessments at NERC, said in a statement. “The changing resource mix introduces greater variability, making long-term planning more complex. To meet this challenge, we need to create the necessary models, technology, and strategies to properly support future grid operators.”

The report also noted that throughout the 2021-2030 assessment period and particularly in the years between 2021 and 2025 there is “heightened uncertainty in demand projections” stemming from the ongoing COVID-19 pandemic.

The pandemic does not present a specific threat to the reliability, but it does lead to uncertainty in electricity demand projections and presents cyber security and operating risks that could exacerbate planning reserve shortfalls in areas that are below or near NERC’s reference margin levels, the report found.

With respect to the two areas of highlighted concern, reserve margins in Ontario could dip below recommended levels as soon as 2022, driven largely by refurbishments of nuclear power plants, demand forecast uncertainty, and the expiration of several generation contracts, NERC said in the assessment, which was released Tuesday. Ontario’s Independent Electric System Operator expects to acquire the required electricity resources through capacity auctions or other tools.

In MISO, NERC said there are adequate reserves in the short term, but there could be shortfalls in 2025. MISO and stakeholders will need to take action to ensure future resource adequacy by “achieving certainty of prospective resources beginning in 2025,” NERC said.

One of the challenges posed by the increasing level of intermittent resources on the grid is that it introduces a risk of inaccuracy into demand forecasts, NERC said. The output from those units can be inaccurate, but in areas with “embedded solar PV” demand forecasts can also be inaccurate. The result, according to NERC, is “operators must increasingly balance uncertain loads with uncertain generation.”

Additionally, as more flexible resources, mostly natural gas-fired generation, are added to the system to make up for the intermittent nature of wind and solar power, NERC noted the potential for an increase in “vulnerabilities associated with natural gas delivery to generators” that could potentially result in generator outages due to both insufficient natural gas infrastructure or alternate fuel delivery and/or disruption to natural gas or alternate fuel deliveries.” Those risks are most notable in New England, the desert Southwest, and California, where there is increased reliance on natural gas generation and limited back-up fuel, the report said.

To address the emerging risks and prevent the possibility of threats similar to those posed in Ontario and MISO occurring elsewhere, NERC recommended that regulators and policymakers “coordinate with electric industry planning and operating entities to develop policies that prioritize reliability, such as promoting the development and use of additional flexible resources, energy-assured generation, and resource diversity.”

NERC also recommended that regulators and policy makers consider revising their resource adequacy requirements to consider new risks that emerge during non-peak hours, limitations from neighboring systems during system-wide events, and the reduced resource diversity and/or increased reliance on a single fuel source or delivery mode.

Industry should also “identify and commit flexible resources to meet increasing ramping and load-following requirements” that result from increased variable energy resources and not solely to meet peak load capacity requirements, the report said.

PNNL transactive energy projects aim to improve DER integration

December 17, 2020

by Ethan Howland
APPA News
December 17, 2020

The Pacific Northwest National Laboratory (PNNL) is working on two projects designed to show how “transactive energy” can help efficiently manage distributed energy resources (DERs) such as rooftop solar.

Using market-based constructs, transactive energy provides a framework for the grid, buildings, electric vehicles, appliances and DERs to communicate with each other to balance real-time electricity supply and demand, according to the PNNL, a Department of Energy laboratory.

A more transactive energy system can improve efficiency, cost, and delivery while providing environmental benefits through the expanded use of intermittent renewable resources, according to PNNL. The approach could “substantially” reduce the amount of money spent updating and maintaining the nation’s energy infrastructure, the DOE lab said Nov. 23 in announcing the projects.

“Getting to the future transactive system will require advanced and automated control and coordination methods to enable the participation of flexible electrical loads,” Hayden Reeve, PNNL program manager, said.

The separate PNNL projects focus on technology deployment in Spokane, Washington, and on simulations of Texas’ primary power grid, operated by the Electric Reliability Council of Texas (ERCOT). The efforts are supported by the DOE Building Technologies Office and Office of Electricity, respectively.

PNNL tests transactive systems in Spokane

One project centers on Avista Utilities’ Eco-District, two buildings designed to test a shared-energy model where a centralized heating, cooling and electrical system can serve the energy needs of a group of buildings.

The buildings include solar panels, battery storage, thermal storage and sensors that track ambient conditions, air quality, occupancy and other attributes in real-time, according to Avista, an investor-owned utility.

In a multi-year, $7 million project, Avista plans to see how incentives can be used to manage the buildings’ energy loads and balance on-site energy demand, generation and storage in real-time, in a way that benefits the grid and provides flexibility for the building operators and the utility.

PNNL will bring to Avista’s project transactive energy management techniques developed at the laboratory-led Clean Energy and Transactive Campus.

The techniques include: intelligent load control, transactive coordination and control, a market-clearing mechanism, and automated fault detection and diagnostics, according to PNNL.

By being part of Avista’s project, PNNL said it will be able to refine the transactive energy management techniques and help develop a “shared-energy” model that other building owners and communities can use.

“Early on, our goal in CETC was to eventually conduct a broad field test to apply and evaluate some of the transactive and other energy-efficiency technologies we developed and demonstrated,” Srinivas Katipamula, a PNNL scientist, said. “Avista’s Eco-District aligned with DOE and PNNL objectives.”

Besides Avista’s two buildings, the project will include nearby retail and institutional buildings, according to Katipamula.

PNNL studies DER integration based on ERCOT model

Meanwhile, to see how transactive energy can help integrate DERs, PNNL researchers are conducting large-scale modeling, simulation and analysis based on ERCOT’s footprint, with the results extrapolated to reflect the U.S. grid.

“We are looking at participation of DERs from two perspectives: What we would see with an amount of renewable generation similar to that currently found in the Western U.S., as well as much higher levels, which would provide an idea of what’s possible if trends toward higher levels continue,” Rob Pratt, a PNNL engineer, said.

In addition to DERs, the project models a distribution system operator, the entity that conducts planning and operational functions associated with an electricity distribution system, including DER coordination, and a transactive network to realize the coordination, PNNL said.

Using the sophisticated modeling, PNNL researchers are studying the engineering and economic performance and identifying ways to provide economic benefits to grid operators and customers, according to the laboratory.

The researchers expect the study will affect two key products: a distribution system operations business framework and a compatible, field-ready transactive network design for coordinating DERs. The products will enable expanded testing of the concepts by industry and research institutions in simulations and the field, PNNL said.

Utility in deal for development of 100-MW battery storage project on NYPA-owned land

December 16, 2020

by Paul Ciampoli
APPA News Director
December 16, 2020

Solar and energy storage company 174 Power Global and investor-owned New York utility Con Edison on Dec. 16 announced the signing of a seven-year dispatch rights agreement for the development of a 100-megawatt battery storage project, the East River Energy Storage System, in Astoria, Queens.

The facility will be located on land owned by the New York Power Authority (NYPA) and leased under a long-term contract to 174 Power Global.

The battery system, which is expected to be one of the biggest in New York State, will be built and owned by 174 Power Global.

The new energy storage system represents a redevelopment of the Charles Poletti Power Plant property, repowering New York City’s grid with a clean energy resource.

“The New York Power Authority is committed to moving clean energy technologies forward and supporting initiatives that reduce greenhouse gas emissions and contribute to a healthier environment,” Gil Quinones, NYPA president and CEO, said in a statement.

 “Additional energy storage development, especially in long duration storage, is key for the continued growth of renewable energy, such as hydro, wind and solar, to help us meet our peak energy demands and bring greater flexibility and resiliency to the New York State electric grid,” he said.

“This adaptive reuse of this land will help realize yet another clean energy project that moves us another step forward in meeting our aggressive climate leadership goals.”

The East River Energy Storage System is designed to balance peak electricity demands and provide grid reliability by delivering reactive power, voltage support and frequency stability to the New York region.

The energy storage system is expected to achieve commercial operation on Jan. 1, 2023.

Ames Electric, with Iowa State University, is hosting a ‘mobile microgrid’

December 16, 2020

by Peter Maloney
APPA News
December 16, 2020

Ames Electric Services in Iowa is providing support for a mobile microgrid project initiated by the Iowa National Guard.

The mobile microgrid comprises solar panels with a total capacity of about 15 kilowatts (kW) and six Tesla Powerwall lithium-ion batteries with a combined capacity of 60 kW, 78 kilowatt hours, all packed into a 20-foot shipping container.

The “microgrid in a case” can be readily shipped anywhere via truck or train or ship, unpacked and set up and be ready for service in two hours, Donald Kom, electric services director at Ames Electric, said. The equipment can generate single phase or three phase power at either 110 volts or 220 volts.

The mobile microgrid also includes a 6.5 kW diesel generator in case “all else fails,” Kom said, and Ames Electric Services is also looking at adding a small wind turbine to the equipment.

The project was developed by the Electric Power Research Center (EPRC) at Iowa State University and its partners, SunCrate and PowerFilm Solar for the Iowa Army National Guard.

Funding came from the National Guard and the Iowa Economic Development Authority.

The National Guard was interested in finding a way to have power at remote locations.

Even though the mobile microgrid was designed for uses such as emergency outages, in its current location it can be used by the public to charge electric vehicles. It is sited and in operation on a utility lot at the end of Main St. in Ames.

Kom said Ames Electric intends to add an electric vehicle charger to the box and begin offering electricity to EV owners.

“We want to use it as much as possible otherwise it is bad for the batteries,” Kom said. The mobile microgrid will provide a valuable test site for the performance and operation of the equipment and will also provide visibility for the microgrid and the renewable energy technology. “We are hoping that the public will come and check it out and plug stuff in,” Kom said. “This is a win-win for the both the project creators and the public. The site offers great visibility and opportunity for public education.”

“One of things we are trying to do is see how long the batteries last,” Kom said. “We are going to load it up as much as we can. We are going to put it through its paces.” The mobile microgrid is expected to stay on its current site for six to nine months. Ames Electric intends to collect data from the unit and share it with the EPRC, which can use it to make improvements and produce a second generation of the unit.

Kom said he also sees a potential benefit for the utility having a mobile microgrid. In August, Ames Electric was hit by a derecho that left some customers without power for up to a week. It would have been “a huge benefit” to have a mobile unit that could have provided power for customers to charge cell phones and other essential equipment, as well as providing a focal point from which the utility could disseminate information for customers, Kom said.

Separately, Ames Electric is preparing to go live with its first community solar project just before Christmas. Ames Electric is selling shares – what it calls Power Packs – in the 2.2 megawatt (MW) solar farm to its customers. Each share requires a $300 one-time investment and represents 175 watts of capacity.

Share owners will receive monthly credits on their utility bill, expected to be about $1 per month, based on the electrical output of the solar farm. Ames estimates customers could earn back their investment in 16 or 18 years, depending on how much the sun shines. About one-third of the shares will likely go to Iowa State University. Ames Electric would use the solar output not taken up by share owners to feed into its grid.

Ames Electric is also a recipient of an award stemming from a settlement with Volkswagen and is using the money to install at least two level-three electric vehicle chargers on Interstate 35.

Public power officials detail plans for COVID-19 vaccine distribution

December 16, 2020

by Paul Ciampoli
APPA News Director
December 16, 2020

Public power officials in a Dec. 3 webinar hosted by the American Public Power Association discussed how the public power community is preparing for the distribution of COVID-19 vaccines.

Webinar participants were Matthew Sinn, Manager of Emergency Management at the Tennessee Valley Authority (TVA), Barry Moline, Executive Director at the California Municipal Utilities Association (CMUA), and Thomas Pierpoint, Austin Energy’s Vice President of Engineering.

At the start of the webinar, Sam Rozenberg, Director of Security and Resilience at APPA, noted that APPA, working with CMUA, has developed a template letter that utility organizations can send to their local and state government leaders requesting vaccine prioritization.

“APPA acknowledges that vaccine prioritization for the electric utility workforce should be after that of health care workers and obviously the most vulnerable of our population,” Rozenberg said.

TVA’s Sinn said that states are likely to use multiple methods to get vaccines to people including delivery by public health strike forces or through partnerships with major pharmacies.

With respect to the question of how the utility sector will receive vaccines, Sinn said that “in TVA’s case, none of our seven states have finalized selection of critical populations for each phase and we know that each of the seven states has their own perspective on whether energy sector workers should be eligible and are eligible.” He said it’s unclear to TVA “whether states will actually require providers to screen for residency.”

TVA’s power service territory covers 80,000 square miles, including most of Tennessee and parts of Alabama, Georgia, Kentucky, Mississippi, North Carolina and Virginia.

Sinn said that “there’s a lot that’s unclear.” For example, he said that it remains unclear “how our states will prioritize electric sector workers and other utility workers.”

He said that TVA’s emergency management group has acquired and is reviewing state plans. “We maintain open weekly communication with our state departments of public health and the associated emergency management agencies for each state,” Sinn noted.

“We have sought guidance from them on what we can do to best prepare and that seems to be to segment our workforce. We are looking at segmenting our workforce around our business continuity plan. We’re looking at methodologies to do this right now.”

Sinn also noted that “our own medical team is keeping an eye out with local medical service providers to understand what they know about how the vaccine will be distributed.”

CMUA, other organizations send letter related to vaccine prioritization

CMUA was a signatory to a Dec. 4 letter related to vaccine prioritization that was sent to officials with the California Department of Public Health.

“The undersigned organizations, representing the electric, natural gas, and water sector, respectfully urge you to ensure that California’s energy and water Essential Critical Infrastructure Workers – as identified by the State Public Health Officer – are part of the Phase 1-B vaccine distribution of the state’s COVID-19 Vaccination Plan,” the letter said.

The essential critical infrastructure workers “critical to keeping the water and power flowing have remained on the job since Day 1 of the COVID-19 crisis to keep the lights on and water flowing across California,” CMUA and the other organizations said in the letter. “For the greater good, these essential critical infrastructure workers have been putting their personal health at risk every day. Providing them reasonable priority access to the COVID-19 vaccine will help ensure that they can remain on the job to perform their critical functions while protecting the health and safety of themselves and those around them,” the letter said.

The groups said they recognize the seriousness of the decisions that must be made when it comes to prioritizing what appears to be a safe and efficacious vaccination for COVID-19. “We understand that there are myriad priorities and metrics to consider, including complex coordination with federal and local government partners. We also recognize the importance of ensuring California’s healthcare workforce is prioritized in receiving the vaccine.”

The Interim draft of the California Department of Public Health’s COVID-19 vaccination plan, dated Oct. 16, 2020, provides that people at increased risk for severe illness or death from COVID-19 and other essential workers, may receive the vaccine in Phase 1-B of the three-phase approach to vaccine allocation.

The interim draft does not define what are considered “other essential workers,” but does recognize that the state is currently identifying and estimating the critical populations for Phase 1, the letter noted.

California’s state public health officer has designated certain utility employees as essential critical infrastructure workers. “These essential critical infrastructure workers perform work at critical infrastructure locations (such as water treatment plants and power plants) to keep electric and water infrastructure operating in neighborhoods, making necessary repairs to utility lines, and in the field carrying out wildfire prevention activities such as vegetation management and inspections for safe operations,” the letter said.

“To reduce the risk of COVID-19 transmission, our organizations, member organizations, and essential critical infrastructure workers, have changed the way they work,” the groups noted.

For example, utilities are using staggered shifts or smaller teams of essential critical infrastructure workers.

“However, due to the nature of the work, there are times when these employees need to be in close proximity to each other, making vaccination – and PPE – highly important to the job,” the letter noted. “For example, essential critical infrastructure workers in grid control rooms often work in open floor plan environments with no walls or separation between desks, and the work requires frequent consultation between employees. Some work activities also require essential critical infrastructure workers to be in the community conducting field work, often in teams, which increases their potential exposure to the virus.”

 

During the webinar, Moline said that “we are surveying our members to quantify the essential workers. We actually don’t know the number right now, but we need to know that number so that we can pinpoint it and let them know how many vaccines we think we need.”

Moline said that “if you have not yet communicated with your state department of health,” that should be done immediately.

“These are people that don’t know us. These are medical people and we don’t necessarily interact frequently with the department of health,” he said. “We’ve found they’ve been really open to learning about our essential workers and the valuable service they provide our community.”

Scenarios for vaccine distribution

In his presentation, Austin Energy’s Pierpoint included a list of scenarios tied to the distribution of vaccines. “These scenarios might change over time. We’ll probably have new scenarios emerge and as this whole vaccination process works its course, we may have multiple scenarios in place simultaneously,” he said.

“I think each utility and maybe us as an industry group should identify the scenarios and manage outcomes that can best protect our workforces,” said Pierpoint.

Scenarios listed by the Austin Energy official in his presentation include broad government-facilitated distribution, federally facilitated distribution specifically geared for critical infrastructure workers, vaccines available for workers via their traditional healthcare channels, utilities working with their key health care providers to streamline worker vaccinations and utilities directly obtaining and administering vaccines.

Pierpoint also outlined guidelines for utilities to consider in helping their workforce navigate through the vaccine rollout process.

Included in those guidelines, he said, is that it is going to be a lengthy effort.

In addition, he said that utilities will probably not be able to require that personnel get vaccines. But utilities may have the ability to require that returning personnel provide evidence of a vaccination or positive anti-bodies. “Having said that, there’s a lot of aspects of this that need to be explored in advance.”

 FDA recently authorized emergency use of vaccine

The Food and Drug Administration (FDA) this month authorized emergency use of a COVID-19 vaccine developed by Pfizer and BioNTech for emergency use and the vaccine is now being distributed and administered in the U.S.

And the coronavirus vaccine made by Moderna “is highly protective, according to new data released on Tuesday, setting the stage for its emergency authorization this week by federal regulators and the start of its distribution across the country,” the New York Times reported on Dec. 15.

APPA supports prioritization of COVID-19 vaccine for mission essential workers

Organizations representing state and local governments should ask their members to designate energy industry mission-essential workers as high priority for voluntary access to initial inoculation against COVID-19, a group of energy industry trade associations including APPA and unions said in a Dec. 3 letter.

The letter was sent to the Council of State Governments, International City/Council Management Association, National Association of Counties, National Association of Regulatory Utility Commissioners (NARUC), National Council of State Legislatures, National Governors Association, National League of Cities, and the U.S. Conference of Mayors.

House, Senate reach deal on energy bill that includes provisions that APPA supports

December 15, 2020

by Paul Ciampoli
APPA News Director
December 15, 2020

The House and Senate on Dec. 14 reached a deal on a bipartisan, bicameral energy bill that includes several provisions that the American Public Power Association supports.

Lawmakers hope to include the “Energy Act of 2020” in a must-pass government funding bill.

The draft energy bill, which covers a wide range of energy topics including nuclear power, energy efficiency, energy storage, and carbon capture, is the result of a compromise between the American Energy Innovation Act (AEIA), introduced last March by Senators Lisa Murkowski (R-AK) and Joe Manchin (D-WV), and the Clean Economy Jobs and Innovation Act, which passed the House of Representatives in September by a vote of 220 to 185.

Controversial provisions, and those which APPA did not support, including several Public Utility Regulatory Policies Act section 111(d) “must consider” requirements, a requirement for the Department of Energy (DOE) to report on the interregional transmission planning process, and for the Federal Energy Regulatory Commission (FERC) to issue a rulemaking on the interregional transmission planning process, did not make it into the final energy package.

At the same time, the bill does not include language APPA supported to assist public power and rural electric cooperatives with their cybersecurity efforts.

 Overall, several provisions that APPA supports made it into this compromise deal, while provisions that APPA opposed in the Clean Economy Jobs and Innovation Act (H.R. 4447) have not been included.

 Notable provisions include:

OUC bringing together hydrogen project, nanogrid to test storage technologies

December 15, 2020

by Peter Maloney
APPA News
December 15, 2020

OUC—The Reliable One is looking forward to combining two research projects to test and demonstrate the possibilities of energy storage technologies, including hydrogen storage, that could be used to smooth out intermittent power from solar resources.

OUC has a goal of reaching zero carbon dioxide (CO2) emissions by 2050, with interim goals of 50% by 2030 and 75% by 2040. There usually is abundant sunshine in Florida, but there is also a lot of cloud cover across the state that can be very sporadic and make solar output particularly erratic.

“Energy storage technologies with longer durations are important to us,” Sam Choi, manager of emerging technologies and renewables at OUC, said. That gives OUC a strong interest in alternatives to lithium ion batteries that have to date dominated the market for energy storage, he said.

OUC has two projects that are testing longer duration energy storage technologies. One is a nanogrid now in operation at the public power utility’s Gardenia operations center. This spring, OUC completed the installation of the equipment for its Gardenia nanogrid project, including doubling the existing solar panels, which float on a pond at the site, to 64 kilowatts (kW), two vanadium redox flow batteries with a total capacity of 20 kW, 80 kilowatt hours (kWh), and three electric vehicle charging stations, including one with vehicle-to-grid capability that the utility is getting ready for operation.

OUC chose flow batteries because they offer longer durations than lithium ion batteries and because, unlike li-ion batteries, the duration (energy) and capacity (power) of flow batteries can be scaled independently. “As we scale up the energy, we may not need as much power,” Choi said.

The eventual goal is to be able to “island” or separate the nanogrid from the surrounding grid in order to power the Gardenia operations center during a storm or an outage.

The other project is funded by a grant from the Department of Energy (DOE).

In August 2019, OUC and its partners won a $4 million grant under the DOE’s H2@Scale program, which explores the potential for wide-scale hydrogen production and utilization to enable resiliency in the power generation and transmission sectors.

OUC’s partners in the hydrogen grant are Giner ELX, OneH2 and the Florida Solar Energy Center at the University of Central Florida. After partner contributions are counted, the total value of the project is $9 million. Progress on the three-year grant was on hold for a few months when Giner was acquired by Plug Power over the summer. OUC, in June, received carbon fiber tanks to store hydrogen and expects to install the rest of the equipment by mid-2021

The remaining equipment includes a 510-kW electrolyzer that produces hydrgen and oxygen from water, two fuel cells, which use hydrogen to produce electricity, one stationary (600 kW), the other mobile (300-kW), a transformer and fuel cell vehicles.   

The fuel cell vehicles, both light duty and larger vehicles, will be able to take advantage of the higher energy density of hydrogen compared with lithium-ion batteries for purposes of demonstrating the potential for electrification of the transportation sector, Choi said.

The electrolyzer will be sited near the pond with the solar panels so that their electrical output can be used to produce “green” hydrogen. The hydrogen project is on track to begin operation by late 2021, and the operations of the two projects, hydrogen production and storage and the nanogrid, could be combined as early as 2022.

When both projects come together, OUC will be able to produce solar power and either store it in the flow batteries or run it through the electrolyzer.

“One of the key research concepts of this project is the electrolyzer,” Choi said. When it is producing hydrogen, the electrolyzer can be ramped up or down to mitigate fluctuations in solar output, he said.

OUC will also be able to store hydrogen in tanks and, by combining tanks stored on a trailer with the mobile fuel cell, will have an emergency, backup generator that can deliver green energy where it is needed during storms and outages.

OUC is also in the process of procuring two flywheel energy storage devices. Flywheels have been most often used to store energy for short periods of time to inject bursts of energy into the grid for services such as frequency regulation. Once again, OUC is looking for a longer duration system, 8-kW flywheels with durations of up to four hours. “We are looking for solar smoothing, and flywheels have a very fast response time and no degradation,” Choi said.

OUC plans to use its Gardenia campus as a test bed that will be able to swap out and test different types of storage technologies. “We are looking to see what works and, especially with distributed resources, what potential there is for us as a utility,” Choi said.