EPA Says That It Plans To Retain Primary, Secondary Ozone National Ambient Air Quality Standards
July 13, 2020
by Paul Ciampoli
APPA News Director
Posted July 13, 2020
The Environmental Protection Agency (EPA) on July 13 announced a proposal to retain the primary and secondary ozone National Ambient Air Quality Standards (NAAQS).
The standards, established in 2015, are currently set at 70 parts per billion (ppb), in terms of a three-year average of the annual fourth-highest daily maximum 8-hour average ozone concentrations.
The Clean Air Act requires EPA to set national ambient air quality standards for “criteria pollutants.”
Currently, ozone and related photochemical oxidants, and five other major pollutants are listed as criteria pollutants. The others are carbon monoxide, lead, nitrogen oxides, particulate matter and sulfur oxides.
The Clean Air Act also requires EPA to periodically review, at least every five years, the relevant scientific information and the standards and revise them, if appropriate, to ensure that the standards provide the requisite protection for public health and welfare.
In the prior review of the ozone standards, which was completed in 2015, EPA increased the stringency of the levels of the ozone standards to 70 ppb from the 2008 standard of 75 ppb.
Emissions from sources such as cars, trucks, buses, industries, power plants, and products such as solvents and paints are among the major man-made sources of ozone-forming emissions.
According to the EPA, from 2017 to 2019, ozone concentrations fell four percent and since the beginning of the Trump Administration it has also re-designated 13 nonattainment areas for the 2008 eight-hour ozone standards to attainment.
EPA will accept comment on its proposed decision for 45 days after it is published in the Federal Register.
Additional information on the proposed decision is available here.
Virginia To Become Newest And The Southernmost Member of RGGI
July 13, 2020
by Peter Maloney
APPA News
Posted July 13, 2020
Virginia is set to become the newest member of the Regional Greenhouse Gas Initiative (RGGI) cap-and-trade program.
An announcement on Wednesday by Ralph Northam, the state’s governor, hailed Virginia as the southernmost state to join RGGI. Joining the group sends “a powerful signal that our Commonwealth is committed to fighting climate change and securing a clean energy future,” Northam said in a statement.
Current RGGI members are Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont.
The groundwork for joining RGGI was set as far back as 2017 when Virginia regulators unanimously approved draft power plant emissions trading regulations that established an initial 2020 carbon dioxide emissions cap at either 33 million tons or 32 million tons. The cap then falls by 3 percent a year for a decade.
On April 12, Northam signed the Virginia Clean Economy Act and amending the Clean Energy and Community Flood Preparedness Act that requires the state to join RGGI.
The Clean Economy Act also replaced the state’s voluntary Renewable Portfolio Standard with a mandatory RPS under which Dominion Energy’s Virginia operations will have to produce electricity from 100 percent renewable energy by 2045, and American Electric Power’s Virginia operations will have to produce electricity from 100 percent renewable energy by 2050.
On June 25, David Paylor, director of the state’s Department of Environmental Quality, signed the final Virginia Carbon Rule. The rule became effective July 1, and Virginia becomes a full participant in RGGI on Jan. 1, 2021.
RGGI is composed of individual carbon dioxide trading programs that each participating state draws up based on the RGGI Model Rule. Within each RGGI state, fossil-fuel generating plants with a capacity of 25 megawatts (MW) or greater are required to hold allowances equal to their CO2 emissions over a three-year control period.
One allowance represents authorization to emit one short ton of CO2. Regulated power plants can use a CO2 allowance to demonstrate compliance in any RGGI state.
Generators may acquire allowances by purchasing them at regional auctions or through secondary markets.
RGGI’s regional cap, as set forth in its model rule amendments, is 75,147,784 tons of CO2 in 2021, which is set to decline by 2.275 million tons of CO2 per year thereafter, resulting in a total 30% reduction in the regional cap from 2020 to 2030.
Virginia’s CO2 Budget Trading Program base budget for 2021 is 27.16 million tons of CO2, falling to 19.6 million tons in 2030. For 2031 and each succeeding year, Virginia’s CO2 base budget is 19.60 million tons unless modified as a result of a program review and future regulatory action.
States sell nearly all emission allowances through auctions and invest proceeds in energy efficiency, renewable energy, and other programs. Under the law passed in April, Virginia will use its RGGI proceeds for community flood preparedness, coastal resilience, and energy efficiency programs benefitting low-income residents of the state.
The Department of Housing and Community Development, in coordination with the Department of Mines, Minerals and Energy, will administer approximately 45 percent of the proceeds to community flood prevention and coastal resilience programs, and three percent will be used by the Department of Environmental Quality to further statewide climate planning efforts.
In October, Pennsylvania Gov. Tom Wolf (D) signed an executive order directing the state’s Department of Environmental Protection to join RGGI.
Pennsylvania House lawmakers last week approved legislation that would require legislative authorization before the state could enter RGGI, but Wolf is expected to veto the measure.
Court Denies Appeal of FERC Orders On Energy Storage Participation In Markets
July 11, 2020
by Paul Ciampoli
APPA News Director
Posted July 11, 2020
The U.S. Court of Appeals for the District of Columbia Circuit on July 10 issued an opinion that denied an appeal filed by the American Public Power Association and several other parties that challenged certain aspects of Federal Energy Regulatory Commission Order Nos. 841 and 841-A, which established rules for the participation of electric storage resources (ESRs) in regional transmission organization (RTO) and independent system operator (ISO) markets.
In 2019, APPA, the Edison Electric Institute (EEI), the National Rural Electric Cooperative Association (NRECA) and American Municipal Power (AMP) challenged FERC’s conclusion that state and local regulators may not “broadly prohibit” ESRs located on a distribution system or behind a retail meter — what the court refers to as “local ESRs” — from participating directly in wholesale markets.
While the Federal Power Act (FPA) gives FERC jurisdiction over wholesale sales, the FPA leaves regulation of distribution facilities to state and local regulators.
APPA and the others primarily argued that FERC exceeded its jurisdiction in Order Nos. 841 and 841-A by concluding that state and local regulators could not exercise their jurisdiction over distribution facilities to prohibit local ESRs from participating in RTO/ISO markets.
APPA and the other groups also asserted that FERC acted arbitrarily and capriciously by not applying to ESRs the same “opt-in/opt-out” framework that FERC adopted for demand response in Order Nos. 719 and 719-A, under which a relevant electric retail regulatory authority can restrict aggregated retail customer participation in wholesale demand response programs.
The National Association of Regulatory Utility Commissioners (NARUC) filed an appeal raising similar issues, which was consolidated with the appeal made by APPA, EEI, NRECA and AMP.
Court addresses jurisdictional issues
As framed by the court, the primary question in dispute was whether Order No. 841 unlawfully regulates matters left to the states. On this issue, the court concludes that, in allowing local ESRs to access wholesale markets, FERC is not directly regulating distribution facilities. The fact that local ESRs will use the distribution system “is the type of permissible effect of direct regulation of federal wholesale sales that the FPA allows,” the court said.
The court turned aside arguments that authority over distribution facilities allows state and local regulators “to close their facilities to local ESRs seeking to transport electric energy to the wholesale markets,” citing principles of federal preemption under the Supremacy Clause of the U.S. Constitution.
The court said that the argument that a local ESR does not participate in the federal wholesale market — and therefore cannot fall within FERC’s authority — until after it navigates through state-regulated facilities falls short.
Any state effort that aims directly at “destroying” FERC’s jurisdiction by necessarily dealing with matters which directly affect the ability of the Commission to regulate comprehensively and effectively over that which it has exclusive jurisdiction invalidly invades the federal agency’s exclusive domain, the court said.
While agreeing that state and local regulators cannot broadly prohibit wholesale market participation by local ESRs, the court points out that, under Order No. 841, states retain their authority to prohibit local ESRs from participating in the interstate and intrastate markets simultaneously, “meaning states can force local ESRs to choose which market they wish to participate in.”
The court also emphasized that state and local regulators retain authority to impose restrictions on local ESR participation in wholesale markets, short of broadly prohibiting such participation, even if such requirements hinder FERC’s efforts to facilitate wholesale market participation by local ESRs.
Thus, for example, states retain their authority to impose safety and reliability requirements without interference from FERC, the court said.
The court also noted that states “will be free to challenge” Order Nos. 841 and 841-A as applied to their own state regulations or imposed conditions.
The court also responded to the argument made by APPA, EEI, NRECA and AMP that allowing state and local regulators to broadly prohibit local ESR participation would be preferable to the inevitable litigation over which state restrictions on local ESRs are permissible and which are not.
The court said that “Petitioners are likely correct that litigation will follow as states try to navigate this line, but such is the nature of facial challenges.”
The court also rejected the argument that FERC acted arbitrarily and capriciously by not applying to local ESRs the “opt-in/opt-out” framework that FERC applies to demand response resources. The court said that FERC’s decision to treat local ESRs different from demand resources was “neither unexplained nor unsupported.”
Order No. 841 was issued in February 2018
Order No. 841, issued in February 2018, adopted rules aimed at removing barriers to the participation of ESRs in wholesale power markets operated by RTOs and ISOs. At the time, several organizations, including APPA, asked FERC to reconsider some aspects of Order No. 841, arguing that FERC was overstepping its jurisdictional authority and encroaching on state and local authority over distribution utilities and networks.
APPA also argued that FERC should have given state and local authorities the ability to opt out of allowing ESRs in their jurisdictions from participating in wholesale markets, as the Commission did for demand response aggregation in Order Nos. 719 and 719-A. FERC largely rejected these arguments in Order No. 841-A, issued in May.
Customer Trust In Utilities Reaches Historic High Due To Effective COVID-19 Response
July 10, 2020
by APPA News
Posted July 10, 2020
Due to the industry’s effective response to the COVID-19 pandemic, customer trust in utilities – including a number of public power utilities — has reached an historic high, according to a recent survey.
The Cogent Syndicated Brand Trust Index posted a record high score of 696 (on a 1,000-point scale), with 44 utilities being named the 2020 Most Trusted Brands, having scored highest on the Brand Trust Index among the 140 utilities that were surveyed.
The Brand Trust Index is a composite score of utility performance on customer focus, community support, communications effectiveness, reliable quality, environmental dedication and reputation.
Escalent, a human behavior and analytics firm, conducted surveys among 70,438 residential electric, natural gas and combination utility customers of the 140 largest US utility companies based on residential customer counts.
While customer trust in utilities had been increasing before the pandemic, the industry’s effective response to COVID-19 accelerated the trend.
Customers rated the industry a high 7.2 (on a 10-point scale) when asked how responsibly their utility responded to the COVID-19 crisis. Half of utility customers “strongly agree” their utility responded well to the pandemic.
A number of public power utilities are included among the group of most trusted utility brands:
* CPS Energy, San Antonio, Texas
* Orlando Utilities Commission, Orlando, Florida
* Salt River Project, Tempe, Arizona
* Seattle City Light, Seattle, Washington
* OPPD, Nebraska
The following information reflects regional peer benchmark Brand Trust scores among the 140 utilities surveyed. The scores reflect the amount of trust customers have with each utility. Scoring is based upon a 1,000-point maximum scale. (The regional breakouts include non-public power utilities, which are not listed).
South Region Utilities Brand Trust Performance
Combination Service (electric and natural gas – total of four entities)
* CPS Energy, San Antonio, Texas (715) (#1)
* MLGW (633) #4
Electric Service (total of 26 utilities)
* Orlando Utilities Commission, Orlando, Florida (752) (#1)
* Nashville Electric Service, Nashville, Tennessee (717) (#5)
* JEA, Jackson, Florida (697) (#13)
* Austin Energy (671) (#23)
Midwest Region Utilities Brand Trust Performance
Electric Service (total of 11 utilities)
* OPPD (714) #3
West Region Utilities Brand Trust Performance
Electric Service
* Seattle City Light (723) #2
* Salt River Project (721) #3
* SMUD (699) #4
* Los Angeles Department of Water & Power (658) #12
For additional information, click here.
Rapid Growth Prompts CPS Energy To Move Ahead With Substation Plans
July 10, 2020
by Peter Maloney
APPA News
Posted July 10, 2020
CPS Energy, the public power utility serving San Antonio, Texas, is moving ahead with plans for two substations designed to meet the needs of the growing metropolitan area.
CPS Energy held an open house in September 2019 with area residents to discuss its planned Midtown substation on a site just north of downtown San Antonio. The utility purchased the property for the substation in March and is now finalizing design aspects to ensure that construction begins in summer 2021.
In October 2019, CPS Energy held a public open house for its planned Scenic Loop substation project, which is sited near Boerne outside of San Antonio city limits. Because the substation and associated transmission project are outside city limits, the utility will need approval by the Public Utility Commission of Texas (PUCT) in the form of an amendment to CPS Energy’s Certificate of Convenience and Necessity (CCN) to own and operate transmission facilities within Texas.
For the past several months, CPS Energy has been preparing its application to submit to the PUCT this summer. The utility said the application would include alternative locations for the planned substation, as well as alternate routes for the associated transmission line.
Landowners close to the alternative substation sites and transmission line routes will have an opportunity to participate in the PUC’s consideration of the project. Following PUCT approval, CPS Energy will be required to pass a Board resolution and obtain a city ordinance enabling it to acquire the land needed for the chosen route and substation.
CPS Energy anticipates a June 2022 start date for construction of the Scenic Loop project with a January 2024 completion date.
The design calls for two 138-kV/35-kV, 100 MVA transformers that would be installed in two phases. The timing of the second phase has not been determined.
The proposed Midtown project calls for gas-insulated switchgear and a three-unit substation with one initial 138/13 kV transformer and 13 kV 4-feeder distribution switchgear. The substation will connect to CPS Energy’s existing Comal-to-Olmos 138-kV transmission line by two single-circuit transmission lines with a total length of about 0.07 mile. The project is scheduled to be in service by January 2023.
The Midtown substation is designed to provide additional electric capacity to support community growth and to improve the reliability of electric service in the area. CPS Energy’s forecast shows that load in the area will equal the existing electrical capacity by 2024.
CPS Energy completed another substation, Southton, in April 2020 and is working on another, the Shepherd Road substation and transmission line, slated for completion in November 2020.
San Antonio expects to add 1 million inhabitants to its population by 2040, according to SA Tomorrow, the city’s initiative for economic development and long term planning.
“Our goal has always been to provide safe, reliable, environmentally friendly services to Greater San Antonio,” LeeRoy Perez, Senior Director, Substation and Transmission, for CPS Energy, said. “The COVID-19 pandemic has not stopped us from making sure our fast-growing city and our customers in our service area, both inside and outside the San Antonio city limits, have the services they need.”
APPA, Other Groups Urge FCC Not To Further Expand Unlicensed Operations In 6 GHz Band
July 10, 2020
by Paul Ciampoli
APPA News Director
Posted July 10, 2020
In recent joint comments submitted to the Federal Communications Commission (FCC), the American Public Power Association and several other trade groups argue that the FCC should refrain from further expanding unlicensed operations in the 6 GHz band “until such time that additional testing has been conducted to prove that unlicensed operations will not cause harmful interference to licensed microwave systems.”
APPA and the other groups submitted the June 29 comments in response to a Further Notice of Proposed Rulemaking (FNPRM) related to the unlicensed use of the 6 GHz band.
Along with APPA, the other groups joining in the comments were the National Rural Electric Cooperative Association (NRECA), American Gas Association (AGA), American Water Works Association (AWWA) and the Utilities Technology Council (UTC).
The FCC issued a Report and Order (R&O) to open the 6 GHz band of spectrum to unlicensed usage back in May. The rules will go into effect on July 27.
The R&O allows two types of unlicensed operations, low powered indoor use and outdoor use with automated frequency coordination (AFC) technology.
The FCC asserts that these are tailored to protect incumbent services that operate in distinct parts of the 6 GHz band.
However, despite the objections of a number of parties, including incumbent license holders and federal agencies regarding the lack of adequate protection from interference afforded in the underlying R&O, the FCC’s FNPRM seeks to go further by allowing more unlicensed operations in the band.
The FNPRM sought comments on whether to further permit unlicensed devices, operating both indoors and outdoors, across the entire band at power levels low enough to prevent interference to licensed services and whether to allow for unlicensed access points that are restricted to indoor operation to operate at a power level over what is set by the R&O.
In addition, the FNPRM sought comments on whether to permit access points that operate under the control of an AFC system in two sub-bands (the 5.925-6.425 GHz and 5.512-6.875 GHz) for mobile applications.
APPA, other groups weigh in
The groups pointed out that two years have passed since the FCC initiated this rulemaking proceeding. During that time frame, the Commission received numerous comments in opposition and studies that showed the impacts interference will have on critical infrastructure from unlicensed usage.
“Now, less than two months after adopting its Report and Order, the Commission proposes additional rules and invites comments on expanding unlicensed operations in the 6 GHz band. At best, this is premature without further experience in a real-world environment; at worst, it recklessly disregards the risk to critical safety and control systems that allow utilities to safely, reliably and securely deliver electric, gas and water services to 330 million Americans.”
Loss of energy and water utility services “can have widespread effects on public safety, the economy, and national security. Moreover, it will affect not only utilities; it will affect any critical infrastructure industry and public safety agency that relies on the 6 GHz band for mission critical communications,” APPA and the others said in their comments.
The groups said that the FCC should refrain from very low power authorization across the band until testing has been done and real world impacts has been determined regarding current operations. Further, the Commission should not allow an increase in the power level for low power indoor devices because it further increases the probability of harmful interference.
In addition, APPA and the other groups said that authorization of both mobile standard-power devices or higher power standard-power devices should not be allowed because the Commission itself recognizes the potential they create for interference, and specifically for mobile devices, the greater complexity they create for an effective AFC.
The groups also said that the FCC should engage with a multi-stakeholder group to ensure the “the development of effective solutions for the implementation of AFC to protect licensed microwave systems and resolve instances of interference and to test low power indoor devices prior to commercial deployment to ensure that they will not cause interference to licensed microwave systems.”
Salt River Project Puts Together A Custom-Fitted Mask Solution
July 9, 2020
by Peter Maloney
APPA News
Posted July 9, 2020
Arizona public power utility Salt River Project (SRP) has engaged in a collaborative effort to come up with a well- fitting mask to protect employees and customers against COVID-19.
In April, faced with pending shortages of personal protective equipment, the Arizona public power utility reached out to local businesses to fill its need for more face masks and hand sanitizer. But for employees in the field who cannot avoid contact with customers SRP was concerned that it could run out of N95 masks that provide a higher level of protection.
N95 masks are most frequently used in hospitals and health care settings to avoid the transmission of highly contagious diseases, and health care workers often have priority for available supplies of those masks.
SRP has an employee mask policy that allows for face covers as well as masks. “We still use all those other measures,” Chad Barrett, strategic operations manager for transportation services at SRP, said.
But for employees working on power lines, in distribution operations centers, interacting with customers, and ensuring water delivery the utility needed masks with a near-perfect seal around each the nose and mouth.
“Our health services team has been conducting COVID-19 tests and health screens for employees, and we were nervous when we noticed our supply of N95 masks was getting low,” Jodie Broderick, SRP’s manager of health services, said in a statement.
With knowledge gained from previous 3D-printed solutions to internal challenges, SRP’s transportation department prototyped different 3D-printed mask options. Barrett did a lot of the development work in his house.
SRP partnered with 3D modelers and 3D print fulfillment companies locally and nationally to come up with a mask design as effective as an N95 that was also practical for wear at work. The utility tested 3D designs publicly available on the National Institute of Health 3D print exchange website and made hybrid solutions.
The SRP development team worked with local Phoenix area company Athena 3D Manufacturing, which helped print mask concepts and recommended they contact Bellus3-D, a California technology company.
One of Bellus3D’s main products is facial scans for dental applications. Responding to the coronavirus pandemic, the company also developed a product it calls Mask Fitters, personalized 3D printed frames that improve the seal of face masks.
In June, SRP began scanning employees’ faces using the Bellus3D app on iPad kiosks in its facilities. The resulting Mask Fitter files are sent to a 3D print fulfillment company in Chicago, Custom Color 3D Printing.
SRP’s transportation services team also worked with Athena 3D Manufacturing to develop a design for a 3D-printed adjustable strap solution that keeps the Mask Fitter comfortably in place.
For the actual filter material for the masks, the SRP team turned to their surplus of KN95 masks. The KN95 mask filters out the same amount of particulate matter as an N95, but it does not seal as well around the nose and mouth, Barrett said. It is more readily available, he said.
SRP set up a process that includes scanning employees’ faces, sending the data off to create a digital facial profile, sending that file to the printer, and then testing the masks for fit using a smoke test.
“We’ve tested a lot of mask solutions the Transportation Services team came up with, and the 3D-printed solution with the Mask Fitter attachment is clearly the best,” Broderick said.
“The beauty of these Mask Fitters is their simplicity, and they can be worn an unlimited number of times if well cared for,” Barrett said.
So far, SRP has deployed about 130 custom-fitted masks and is looking to reach a total of 200, but “we are leaving our options open,” Barrett says. “We don’t have a final number. We are making sure all of the groups in SRP know about it.”
Barret says his transportation services team participated in finding out what is available in 3D realm. The utility’s purchasing and warehousing groups “get kudos for getting the filtration parts of our masks,” he said.
The IT department provided the needed tracking for the personalized fitting technology, the safety team had a “huge” role, and the utility’s nursing station worked on the testing and fitting of the masks, Barrett said. “It was a neat, collaborative effort.”
NYPA, OUC
New York Power Authority employees are using 3D printers to make face shields for local health care workers fighting the COVID-19 pandemic.
The effort grew out of a suggestion by Joseph Kessler, NYPA executive vice president and chief operating officer, that the statewide public power utility take advantage of its recent use of the 3D printer technology to help protect medical workers.
And Justin Kramer, the supervisor of emerging technologies at Orlando Utilities Commission (OUC) in Florida, has made and delivered more than 150 3D masks to Orlando Health Orlando Regional Medical Center, a longtime OUC community partner.
Senate Bill Would Reinstate Taxable Direct Payment Bonds
July 9, 2020
by Paul Ciampoli
APPA News Director
Posted July 9, 2020
Sens. Roger Wicker, R-Miss., and Michael Bennet, D-Colo., on July 8 unveiled the introduction of S. 4303, the American Infrastructure Bonds Act, which would allow the issuance of taxable direct payment bonds, akin to a Build America Bond.
The American Public Power Association, which has included reinstatement of the issuance of direct payments bonds as part of its bond modernization agenda, said that it was pleased to see the bill’s introduction.
The credit rate for bonds would be 35 percent for bonds issued before January 1, 2026, and 28 percent for bonds issued after December 31, 2025.
The legislation, which was introduced on July 2, includes a provision to hold credit payments harmless to budget sequestration.
“American Infrastructure Bonds” could be issued for any purpose that would also qualify for purposes of issuing a tax-exempt municipal bond. The legislation would also allow the issuance of such bonds for qualified facility private activity bonds.
Bipartisan Senate bill would reinstate ability to issue tax-exempt advance refunding bonds
In other recent bond-related news, a bipartisan group of senators on July 1 introduced the Lifting Our Communities through Advance Liquidity for Infrastructure (LOCAL Infrastructure) Act, which would reinstate the ability to issue tax-exempt advance refunding bonds.
The lead co-sponsors of the bill are Wicker and Debbie Stabenow, D-Mich.
Additional original cosponsors include Senators John Barrasso, R-Wyoming, Shelly Moore Capito, R-W.Va., Michael Bennet, D-Colo., Tom Carper, D-Del., Bob Menendez, D-N.J., and Jerry Moran, R-Kans.
The bill is a companion to H.R. 2772, the Investing in Our Communities Act, and is identical in effect, but is drafted quite differently.
APPA supports both of these bills.
NERC’s Robb Praises Power Industry’s Response to Pandemic
July 8, 2020
by Paul Ciampoli
APPA News Director
Posted July 8, 2020
The power sector deserves “a tremendous amount of credit” for the way in which it has responded to the COVID-19 pandemic, said Jim Robb, President and CEO of the North American Electric Reliability Corporation, in a recent interview with the American Public Power Association.
“I think you have to sit back and give the electric industry a tremendous amount of credit for the way it reacted to this situation,” Robb said.
Robb noted that the Electricity Subsector Coordinating Council (ESCC), which serves as the principal liaison between the federal government and the electric power industry on national level response issues such as pandemics, “really has a very effective process.”
In the wake of the pandemic’s emergence, the ESCC playbook was activated in March. The playbook provides senior industry and government executives with a framework to coordinate response and recovery efforts and communication with the public during major incidents.
“It’s hard to remember now, but if you go back to the March timeframe this was evolving very, very quickly,” Robb noted. The ESCC held meetings twice a week “just so everybody knew what was going on, could share their experiences,” and learn from each other, he said.
Moreover, the meetings also provided an opportunity to hear updates from the Department of Homeland Security, the Department of Energy and, on occasion, the Department of Health and Human Services “as to what was actually going on.”
The ESCC also formed “Tiger Teams” in order to start to identify and address cross-cutting issues across the energy industry, Robb noted.
The ESCC’s COVID-19 Resource Guide, which is a living document developed under the direction of the ESCC, has been updated and distributed regularly by the ESCC Secretariat, based on input from Tiger Teams. Version 9 of the guide was released in late June.
In talking with one of his Board of Trustee members who’s very involved with the water sector, that official said he was “blown away by” the resource guide, Robb said. “He said this was so far beyond what we’ve seen,” the NERC President and CEO said.
“I think that’s just an example of how well the electric sector can come together when it needs to,” Robb said.
The ESCC resource guide has been updated with the input of the American Public Power Association and public power utilities.
Members of the ESCC Steering Committee include Robb and Joy Ditto, President and CEO of APPA.
Meanwhile, along with its work with the ESCC in response to the pandemic, NERC has also joined with the North American Transmission Forum, the DOE and the Federal Energy Regulatory Commission to jointly develop a pandemic planning guide.
The resource focuses on planning/preparedness, response, and recovery activities for a severe epidemic/pandemic.
The first version of the planning guide was published in May and the second version was published in mid-June.
E-ISAC issued all-points bulletin to industry
Robb noted that in the early part of 2020, NERC’s Electricity Information Sharing and Analysis Center issued an all-points bulletin to industry related to the pandemic.
The initial concern was focused on the supply chain, Robb said, given that so many electronic components are made in China. At the same time, E-ISAC asked industry to “dust off their pandemic plans” and identify key workers.
The power sector has been proactively thinking about how to address pandemics for quite some time. The electricity sector came up with a pandemic plan 10 years ago, which was part of a High Impact Low Frequency (HILF) event plan development. In 2010, sector entities were urged to review their pandemic and business continuity plans to incorporate lessons learned from the 2009 A/H1N1 outbreak and consider much worse scenarios.
Meanwhile, Robb said that the COVID-19 pandemic brought the DHS, DOE and E-ISAC together “in ways, at least in my time here, we haven’t worked together as well as we have over the last three to four months.”
The amount of information sharing out of the government, “whether it’s cyber threats, physical threats to the grid, trends that they’re seeing, issues we need to be aware of and then using the ISAC as a vehicle for getting that rapidly communicated out to industry was, I think, just superb.”
Robb said that the best of that “ecosystem around the ISAC, and the intelligence community and the government partnerships that we have has worked” since he took the helm at NERC two years ago.
“I think the whole model served us all very, very well through this period,” Robb said.
FERC also plays role
NERC in April asked the Federal Energy Regulatory Commission to approve a motion in which NERC sought approval to defer the implementation of several reliability standards that have effective dates or phased-in implementation dates in the second half of 2020. NERC said that the action was a measure to help assure grid reliability amid the impacts posed by the COVID-19 pandemic.
APPA, the Edison Electric Institute, the National Rural Electric Cooperative Association and the Large Public Power Council submitted a filing at FERC in support of NERC’s motion.
FERC approved the NERC motion in April.
During industry conference calls related to the pandemic, participants have emphasized the need for regulatory relief.
Reliability outlook for the summer
Meanwhile, NERC has said that potential workforce disruptions, supply chain interruptions and increased cyber security threats caused by COVID-19 have elevated the electric industry’s reliability risk profile.
Robb was asked whether NERC is giving equal weight to these pandemic-related threats to reliability as the country heads into the summer months or if it is concerned about one of these threats, in particular, and if so why.
“I think there are a lot of countervailing factors in place, recognizing that the glass that we’re looking through right now is murkier than it typically is for a whole bunch of reasons,” Robb said.
“From a core reliability perspective, had this been a normal year the places we’d be really concerned about would be Texas, for example, because their reserve margins are so tight, but the fact of the matter is that loads are off and they’ve been able to bring some new generation on,” he noted. “They’ve got some breathing room that we wouldn’t have expected. Now, of course, we’re highly dependent on weather in Texas for loads.”
“I think the one thing that we’re not as clear about is the ability of the industry to fully prepare for the summer,” Robb said. In terms of maintenance turnarounds and construction projects, in some jurisdictions “those were very hard to move forward during the height of the pandemic, so there’s still a little bit of a bet as to generation readiness for the summer, but in general everybody’s reporting a high degree of confidence on that front.”
Another issue that looms as the country heads into the summer, particularly in the Southeast, is that “everyone’s projecting this to be a pretty active storm season,” Robb noted.
NERC distributed an alert in March to get a better handle on industry pandemic planning including mutual aid “and whether companies would be prepared to honor mutual aid requests as we move into the storm season,” he said in the interview.
Two-thirds of the entities surveyed, “which are probably 90 percent of the people who would provide mutual aid anyway, all said that they would, so that bodes well,” Robb said.
“We’re headed into what’s always a tough season with one arm tied behind our back. I’m sure the industry will work through issues as they arise, but it will be that much more difficult as we move through.”
Robb said that the power sector’s response in terms of early season storms, such as those that hit Tennessee, was “as good as it always is. I don’t think that there was any sense that it was hindered as a result of the pandemic in terms of restoration efforts.”
GridEx
The President and CEO of NERC also discussed the most recent GridEx, which occurred in 2019.
GridEx, which takes place every two years, allows utilities, government partners and other critical infrastructure participants to engage with local and regional first responders, exercise cross-sector impacts, improve unity of messages and communication, identify lessons learned and engage senior leadership.
The exercise began in 2011 and NERC hosts the GridEx series. The 2019 GridEx, which occurred in November 2019, marked the fifth such exercise.
Robb said that GridEx V was the most successful GridEx to date “because we had more participation – particularly more participation out of the public power utilities.”
APPA played “a really important role in getting more of them to participate in the distributed play aspect of the drill,” he went on to say. In 2017, 53 public power entities participated in GridEx, while in 2019, 100 public power entities participated.
At the same time, he said that each GridEx has built on the previous one, so therefore it is “kind of apples and oranges to say which was better.”
With GridEx V, a different approach was taken, which was “very successful and timely,” Robb said. “I think previous ones focused on national level issues and really some high-level policy questions. One of our design goals in this one was to take the focus down a level and not spend so much time on broad, sweeping policy statements, but really to focus in on the more operational issues that you’d actually face.”
A regional scenario was created for the executive tabletop “where we basically had a combined physical/cyberattack on Manhattan, which then cascades through New York State and then up into Ontario.” The regional focus “allowed us to get a very specific set of players to the table.”
In addition, “we also focused on getting more operational – like COO types – rather than the CEOs, to really work through what set of issues we are going to run into.”
The overall construct was “more operational, more focused,” while also including an international element.
“I think this time we also had the best success we’ve had to date at getting non-electric sector participants,” Robb said. “We had a couple of large telecom companies, a couple of large pipelines at the table. We had a major equipment supplier.”
Therefore, there was an opportunity “for a much richer conversation around supply chain and the cross-sector dependencies that we would have, particularly with the telecom sector, which is something I think we’re going to continue to work on exercising because that’s less well developed than some of the others.”
Robb said that “the other thing that we did is we brought DOE to the table and asked them to exercise their authorities under the FAST Act to create a grid security emergency order.” This move prompted a “very rich conversation around what should an order entail, how specific should it be, what should be left to industry to figure out versus what the government needs to be able to do.”
One of the lessons learned is that the government should be clear about setting restoration priorities, “and then let the utilities work through, well, what’s the best way to get to that objective,” he noted.
“We also had some interesting learnings around the applicability of a grid security emergency order to the natural gas industry,” he said. Natural gas in most places but particularly in the Northeast is a fuel of last resort.
“It’s the fuel that keeps the lights on when nothing else is available,” he said. “You can imagine the importance of making sure that you’ve got fuel supply to those critical generating plants” that are important for blackstart purposes and “reboot the system if you will.”
Robb said that figuring out “how you move gas from where it is to where it needs to be when the pipelines don’t own the gas wasn’t really an issue we really thought about very much, but it became very clear that there’s a whole host of liability protections and so forth that need to be put in place for the pipeline operators in order to be able to support grid restoration.”
Addressing the broader question of reliability risks, Robb said that along with the “ubiquitous risk” of cybersecurity, there are three risks that NERC and the power sector are highly focused on.
The first revolves around supply chain. “That’s a really thorny, complicated issue,” he said. “Our new supply chain standard requirements will go in effect now in October” and NERC will continue to evaluate “whether we’ve got those right and what modifications to those might need to be put in place.”
NERC is working with the DOE on implementation of a supply chain executive order.
President Donald Trump on May 1 signed an executive order that authorizes U.S. Secretary of Energy Dan Brouillette to work with the Cabinet and energy industry to secure the country’s bulk-power system.
Meanwhile, NERC has seen several issues emerge lately tied to facility ratings, Robb noted. NERC has an initiative underway jointly with the North American Transmission Forum in order to get an understanding “and whether there are any systemic issues that we need to be addressing and raise awareness” for utilities around ensuring that their equipment ratings are correct.
The third area that NERC will continue to push on relates to issues surrounding fuel adequacy. With the shift towards a power sector that has more variable supplies such as solar and wind, along with the issues surrounding the just in time nature of natural gas deliveries, “particularly if you don’t have gas storage in your area, you really have to have your eyes open to fuel as well as iron in the ground.”
As for cybersecurity, Robb said that the “adversaries are persistent, opportunistic, very opportunistic.” He said that “we have to continue to ensure that the industry continues to be vigilant, never takes its eye off the ball and of course that’s a high priority for the CEOs. Our posture in this area I think is very good, but it only takes one.” Cyber “hygiene” remains a very important risk area for the industry, he said.
Construction Starts On Logansport Municipal Utility’s First Solar Power Project
July 8, 2020
by Taelor Bentley
APPA News
Posted July 8, 2020
Inovateus Solar has begun construction of Logansport, Indiana’s first solar power plant. The installation will be developed for Logansport Municipal Utility (LMU).
Financed by a power purchase agreement (PPA), the solar installation will reduce LMU’s carbon emissions, help to stabilize energy costs for LMU’s customers, and also host a bee and butterfly habitat that will benefit agriculture in the surrounding area.
The 30-year PPA, financed by Alchemy Renewable Energy, allows LMU to purchase the solar generation at a fixed kilowatt-hour rate with no upfront capital costs, Inovateus noted.
The contract also includes options for LMU to buy the solar energy system in the future.
The 16-megawatt solar installation will be sited on 80 acres and construction on the solar project is scheduled to be completed in the first quarter of 2021. LMU recently retired a coal-fired power plant.
Inovateus noted it is also designing a solar education program and launching a college scholarship contest for naming the solar park.
Inovateus has also designed a 45-foot vegetation buffer around the solar array. The buffer will feature native Northern Indiana tress, plants, and more than 100 tulip trees donated by the community.
Inovateus has partnered with Fresh Energy and the Bee & Butterfly Habitat Fund to plant a pollinator seed mix under and around the solar panels instead of traditional ground cover. The pollinator mix will cultivate honeybees and butterflies that local farmers rely on for pollinating their crops.