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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.

MMWEC expands residential demand management program to include thermostats

December 15, 2020

by Paul Ciampoli
APPA News Director
December 15, 2020

Massachusetts Municipal Wholesale Electric Company (MMWEC), the joint action agency for municipal utilities in Massachusetts, is expanding its residential demand management program, “Connected Homes.” Beginning this month, select wifi thermostats have been added to the program for all participating municipal light plants (MLPs).

Connected Homes allows residential customers to better manage wifi-connected devices in their homes while reducing their carbon footprint.

Connected Homes, launched in April 2020 with 11 MLPs, is offered through MMWEC’s residential energy conservation service, the Home Energy Loss Prevention Services (HELPS) program.

HELPS is working with the company Virtual Peaker, a software platform, to allow customers of the participating MLPs to leverage the technology of smart appliances and devices into energy and cost savings for the light department and its customers, MMWEC noted.

By enrolling a smart device in the Connected Homes program, customers agree to allow their light department to make brief, limited adjustments to their devices during times of peak electric demand, such as temporarily reducing the charging rate of an electric vehicle during peak hours. Customers will be informed of possible adjustments in advance via email and given the choice to opt out of each adjustment. Customers who participate are given a stipend or bill credit.

Starting in December, select wifi thermostats have been added to the program for all participating MLPs.

Other devices already in the program are home batteries, electric vehicle chargers, electric hot water heaters and mini-split controllers. Devices and incentive amounts may vary by MLP.

In addition, two additional MLPs have signed on to participate, bringing the total number of participating utilities to 13.

Beginning January 1, the municipal utilities in Belmont and Shrewsbury join those in the communities of Groton, Holden, Holyoke, Ipswich, Mansfield, Marblehead, Princeton, South Hadley, Sterling, Wakefield and West Boylston.

“Through participation in Connected Homes, the growing number of customers moving toward electrification can easily and conveniently manage their home’s energy use, by adjusting the device’s energy usage remotely, or by setting an automatic schedule,” MMWEC said in a Dec. 14 news release.

MMWEC is a non-profit, public corporation and political subdivision of the Commonwealth of Massachusetts, created by an Act of the General Assembly in 1975 and authorized to issue debt to finance a wide range of energy facilities.

MMWEC provides a variety of power supply, financial, risk management and other services to the state’s consumer-owned municipal utilities. It has 20 municipal utility members and 28 project participants.

Fitch says public power utilities are well positioned financially headed into 2021

December 14, 2020

by APPA News
December 14, 2020

U.S. public power utilities are well positioned financially headed into next year, as lower expenses have helped preserve margins and liquidity in the wake of pandemic-driven declines in electric demand and revenue, according to Fitch Ratings.

However, Fitch’s 2021 outlook report points to some concerns related to the lingering effects of the coronavirus pandemic and economic contraction, as well as more aggressive climate issues, the rating agency said on Dec. 9.

The rating outlook for the public power sector is stable.

“The operational and financial resilience exhibited by the public power sector through 2020, together with improving operating fundamentals, support Fitch’s stable outlook,” said Managing Director Dennis Pidherny.

Fitch said that electric demand is expected to stabilize in 2021 as the U.S. economy recovers from recession and achieves pre-pandemic gross domestic product levels.

“A continuance of low, stable energy prices and interest rates should also help preserve operating margins and affordability. These factors are to expected ease upward pressure on electric rates, support strong cash flow and moderate leverage throughout the sector,” Fitch said.

At the same time, uncertainty surrounding the lingering effects of the pandemic and the potential for more aggressive environmental mandates could disrupt longer term performance, according to the rating agency.

Greater support from public power systems may be required by local governments facing pandemic-related fiscal challenges, particularly those facing severe declines in tax revenue, Fitch said.

Meanwhile, Fitch said that an increased focus on carbon dioxide emissions reduction by federal leadership is expected to develop under President-elect Biden and could lead to more aggressive environmental policies with an evenly divided Senate.

“While many states continue to forge their own paths to address climate issues, the implementation of a national renewable standard could pressure operating costs, as well as the affordability metrics, at public power systems located in states with no standards or targets, or that have exemptions in place,” Fitch said.

Moody’s says 2021 outlook for public power is stable

Moody’s Investors Service this month said its outlook for the U.S. public power sector is stable because the rating agency expects the sector to be relatively resilient through the ongoing global recession.

“Public power utilities’ business model inherently helps maintain stability; they provide essential services in a non-profit oriented manner, have strong liquidity and have self-regulated rate-setting ability to help manage cost recovery,” Moody’s said in a Dec. 7 report.

Vermont Public Power Supply Authority to bring mapping software, data analytics to members

December 14, 2020

by Paul Ciampoli
APPA News Director
December 14, 2020

Vermont Public Power Supply Authority (VPPSA) and mPower Innovations on Dec. 10 announced a strategic partnership to bring mapping software and data analytics to VPPSA’s 11 community-owned electric utilities.

The partnership is a key step in deploying future utility technology advancements, including VPPSA’s anticipated 2021 rollout of advanced metering infrastructure for Vermont’s smallest electric utilities, VPPSA noted.

VPPSA is a joint action agency that provides services and solutions to their member municipal electric utilities and their combined 30,000 customers. mPower Innovations is a GIS software developer.

Under the partnership, mPower and VPPSA will build and maintain a geographic information system (GIS) mapping program for each VPPSA member utility.

A services and software licensing agreement will allow VPPSA and its members access to mPower’s Integrator software, which retrieves data from AMI meters and enables geospatially-based load analysis, voltage analysis, interconnection studies, and insight into energy use trends.

VPPSA members can also use the software for multiple purposes including cost-effectively managing utility assets, preventative maintenance, vegetation management, and outage tracking and analysis.

“GIS mapping and circuit modeling provide a solid foundation from which to build out further technological innovations, but it’s a service that small utilities may struggle to afford on their own,” said VPPSA General Manager Ken Nolan in a statement. “VPPSA is constantly exploring opportunities to bring economies of scale benefits to our members. We are grateful to mPower for developing an accessible price structure and think this arrangement could serve as a model to joint action agencies around the country.”

VPPSA noted that as an indication of its commitment to the partnership, it has hired a full-time GIS Technician to work with member utilities and mPower to successfully deploy mapping software.

Boston to launch community choice electricity program in February

December 14, 2020

by Paul Ciampoli
APPA News Director
December 14, 2020

Boston Mayor Martin Walsh on Dec. 4 announced a series of milestones in the development of the City of Boston’s community choice electricity program, which will officially launch Feb. 1, 2021 and will be the largest municipal aggregation program in New England.

Boston has contracted with Constellation NewEnergy Inc. as the supplier and will offer three product options for customers.

“Designed as an opt-out program, CCE offers customers flexibility in their electricity choices without any change in delivery or any contractual commitments,” the mayor’s office said.

Investor-owned Eversource offers city residents a default electric supply option called basic service. The City of Boston recently began sending notices to residents on Eversource basic service. Those residents will be automatically enrolled in the program unless they actively choose to opt out.

The CCE effort is a key strategy in the city’s Climate Action Plan to lower emissions and achieve carbon neutrality by 2050, Walsh’s office noted.

Boston’s CCE program will offer the opportunity for more than 20,000 low-income customers to receive meaningful discounts on their electricity costs through the Commonwealth of Massachusetts’ Solar Massachusetts Renewable Target (SMART) Program.

The City of Boston has partnered with NextGrid Inc. which will build 100 megawatts of new solar PV modules within Massachusetts. When completed, the incentives from the new solar projects will result in an estimated $72 annual savings for the average low-income household, and more than $28 million over 20 years.

The city is seeking to contract with other developers for more solar energy capacity to increase low-income customer savings and spur job creation. 

Additional information about the CCE program is available here.

APPA weighs in on FEMA proposed rules tied to disaster grant closeout procedures

December 14, 2020

by Paul Ciampoli
APPA News Director
December 14, 2020

The American Public Power Association recently weighed in on proposed rules put forth by the Federal Emergency Management Agency (FEMA) related to disaster grant closeout procedures.

The Dec. 10 comments were submitted by Alex Hofmann, APPA’s Vice President, Technical and Operations Services.

“Every year, our member utilities critical facilities and infrastructure, including poles, lines, and transformers, are impacted by extreme weather events such as ice storms, fires, tornadoes, floods, hurricanes,” Hofmann noted.

When this damage comes as a part of a major disaster as declared by the President of the United States, public power response and recovery costs are eligible for reimbursement through FEMA.

These grants, authorized by the Robert T. Stafford Disaster Relief and Emergency Assistance Act and administered under FEMA’s Public Assistance Program, “can amount to tens of millions of dollars and are critical to the ability of our member utilities, cities, and towns to recover from disasters,” the comments said.

Therefore, FEMA’s development and application of the closeout procedures policy is of great interest to APPA.

FEMA’s proposal to allow unlimited tolling of the statute of limitations is not what Congress intended nor what the statute provides, APPA said in the comments.

FEMA argues that it can retain the right to toll the statute because seeking additional information “constitutes the beginning of an administrative action.”

However, the actual effect is to puts the grantee in a permanent state of limbo, APPA argued. “On the one hand the threat of clawback remains, but on the other, FEMA has taken no administrative action against which the grantee can seek relief.”

This is “precisely the kind of abusive situation” that Section 705(a) (Statute of Limitations) of the Stafford Act was intended to address, Hofmann wrote.

“It also subverts the fair trade-off intended by section 705(a) – the grantee must wait up to three years before it can be certain that FEMA will not take administrative actions to recover a public assistant grant; whereas FEMA has just three years to discover ‘an issue that the recipient and/or subrecipient needs to address’ and take administrative actions resulting from that issue.”

FEMA’s proposal “is all the more frustrating because it implies that as a regular course of business, FEMA will not really begin to review certified final expenditure reports until years after the fact and that grantees, when a request for information is made, should assume that they will have to wait more than three years to have such issues resolved,” Hofmann wrote.

“Again, that is not what Congress intended when it enacted section 705(a). What Congress intended was that FEMA would use the three-year period to complete its review of a completed report, to make requests for additional information, and to decide whether to seek administrative action.”

Moreover, there is nothing about the intended process — rather than the one proposed by FEMA — that puts FEMA at a disadvantage, the comments pointed out.

“For example, one of the more common reasons for taking administrative actions to recover is a grantee’s failure to adequately document a public assistance request. The intended process simply requires FEMA to decide sooner, rather than later, that a request is inadequately documented.”

APPA also argued in its comments that FEMA should not “re-open” a project after it has been approved and closed out to de-obligate funds.

Once FEMA has reviewed and closed a project, FEMA should not be allowed to later reopen the project to reverse these determinations to the detriment of a recipient or sub-recipient, the trade group said.

“Post approval and close out challenges to procurement should not be allowed, as proper procurement supports reasonableness of the costs, and FEMA’s closeout of a project includes confirmation that FEMA has determined a cost is reasonable – so procurement compliance at that point should be moot,” wrote Hofmann.

CISA urges affected organizations to take action in response to exploitation of SolarWinds software

December 14, 2020

by Paul Ciampoli
APPA News Director
December 14, 2020

The Cybersecurity and Infrastructure Security Agency (CISA) on Dec. 13 said that it is aware of active exploitation of a vulnerability in versions of the SolarWinds Orion Platform software.

Versions 2019.4 through 2020.2.1 of the software were released between March 2020 through June 2020.

CISA, which falls under the purview of the Department of Homeland Security (DHS), is encouraging affected organizations to read SolarWinds and FireEye advisories for more information and FireEye’s GitHub page for detection countermeasures. FireEye is a cybersecurity firm.

In its security advisory, SolarWinds said it was made aware that its systems “experienced a highly sophisticated, manual supply chain attack” on SolarWinds Orion Platform software builds.

“We have been advised this attack was likely conducted by an outside nation state and intended to be a narrow, extremely targeted, and manually executed attack, as opposed to a broad, system-wide attack,” SolarWinds said.

In the security advisory, SolarWinds offers several steps for parties to take related to use of the SolarWinds Orion Platform.

Meanwhile, DHS on Dec. 13 said that the relevant SolarWinds Orion products are currently being exploited by malicious actors. This tactic permits an attacker to gain access to network traffic management systems, DHS said. Disconnecting affected devices is the only known mitigation measure currently available, it said.

DHS said that CISA has determined that this exploitation of SolarWinds products poses an unacceptable risk to federal civilian executive branch agencies and requires emergency action.

This determination is based on: (1) Current exploitation of affected products and their widespread use to monitor traffic on major federal network systems; (2) High potential for a compromise of agency information systems; and (3) Grave impact of a successful compromise.

“CISA understands that the vendor is working to provide updated software patches. However, agencies must wait until CISA provides further guidance before using any forthcoming patches to reinstall the SolarWinds Orion software in their enterprise,” DHS said.

ESCC

“The electric power industry takes all vulnerabilities and threats to the energy grid and our supply chains very seriously, including the latest SolarWinds Orion Platform vulnerability that cuts across many sectors,” the CEO-led Electricity Subsector Coordinating Council (ESCC) said in a Dec. 14 statement.

The ESCC “is highly engaged and already has conducted a situational awareness call on this threat,” the ESCC said.

The North American Electric Reliability Corporation’s Electricity Information Sharing and Analysis Center (E-ISAC) also has provided potential indicators of compromise and other technical data that electric companies, public power utilities, electric cooperatives, and independent power producers in North America are utilizing to run comprehensive diagnostics of their systems to identify and to remediate any threat exposure, the ESCC noted.

“This information sharing is representative of the strong industry-government partnership that the ESCC embodies and is vital to guarding the energy grid from all possible threats,” the ESCC said.

Public power utilities should follow the guidance from the E-ISAC “as well as the Cybersecurity and Infrastructure Security Agency (CISA) as this situation unfolds,” said Sam Rozenberg, CPP and Director of Security and Resilience at the American Public Power Association.

Questions related to this development can be directed to: Cybersecurity@PublicPower.org.

Traverse City Light and Power becomes first utility to deploy SF6-free circuit switchers

December 11, 2020

by Peter Maloney
APPA News
December 11, 2020

Traverse City Light and Power (TCL&P) located in Traverse City, Michigan has installed circuit switchers that use clean dry air instead of traditional sulfur hexafluoride (SF6) insulating gas, making it the first utility in the United States to use the new technology.

The Blue Clean Air 72.5-kilovolt (kV) CPV2V Circuit Switcher was built by Siemens Energy in the company’s Richland, Mississippi plant and commissioned at TCL&P in October 2020.

The new switchers “provide more reliability to our customers and save maintenance costs along with being more environmentally friendly,” Tony Chartrand, system engineer at TCL&P, said In addition, SF6 will likely be outlawed at some point in the future – as many refrigerants have – and it is getting harder and harder to refill a bottle of SF6, he said.

TCL&P has set a goal of deriving 100% of its generation needs from renewable energy resources by 2040. The new switchers “match up with that goal by getting rid of devices that could leak greenhouse gases into the atmosphere,” Chartrand said.

Sulfur hexafluoride has a global warming potential 23,500 times that of carbon dioxide.

The clean air switchers use a vacuum tube to break the arc instead of SF6. The vacuum tube is surrounded by a normal air mixture that is dried and filtered in order to remove any possible contaminants that could cause an arc around the vacuum bottle. Clean air is readily available from industrial suppliers, but Siemens provided a G-size tank of air to fill the switchers that is expected to last as long as the switchers do. The new technology also eliminates the need to store and handle sulfur hexafluoride gas.

Siemens says its Blue Clean Air circuit switchers are capable of reliable short-circuit interruption at voltage levels above 69 kV and that it can in temperatures as low as -50° C (-58° F), thus eliminating the need for external heaters.

TCL&P has been upgrading its 69-kV distribution system. The two new switchers were installed to replace fuses that were protecting the transformers. It was the utility’s last substation that was still using transformer fuse protection, Chartrand said.

TCL&P has a number of other SF6 switchers, most of which are not even 20 years old and still have life in them, Chartrand said, adding that the utility is taking a phased approach to replacing them.

Eventually TCL&P plans to replace all its traditional SF6 switchers with clean air switchers, but they are more expensive, currently costing about 68% more than traditional technology, Chartrand said. On the other hand, the new switchers offer estimated life cycle cost savings of up to 40% over SF6 circuit switchers, and the new switchers have a longer expected operating life and have longer maintenance intervals. “We have no plan to buy any more SF6 devices; we plan to move exclusively to vacuum technology for all of our breakers and circuit switchers,” Chartrand said.