California Community Choice Aggregator Unveils Virtual Power Plant Program
June 22, 2022
by Paul Ciampoli
APPA News Director
June 22, 2022
California community choice aggregator (CCA) Marin Clean Energy (MCE) on June 21 unveiled a Virtual Power Plant (VPP) program that is slated to launch in 2025.
MCE said the program will provide bill savings and increase local grid reliability, safety, and efficiency for low-income residents as part of Richmond, Calif.’s Advanced Energy Community project, which includes $3 million in funding from the California Energy Commission and will rehabilitate abandoned homes with energy efficiency retrofits and establish a VPP.
The Advanced Energy Community brings together a variety of partners including the project developer, ZNE Alliance, and ALCO Building Solutions, Ecoshift Consulting, Energy Solutions, mPrest, Richmond Community Foundation, THG Energy Solutions, TRC, and ZGlobal.
Similar to traditional power plants, VPPs provide electricity to the grid, but instead of coming from a single source, VPPs are made up of a network of digitally-connected technologies distributed across a community. VPPs help stabilize the power grid by quickly dispatching power to and from resources on the grid to shift energy consumption out of peak hours and take greater advantage of midday solar generation.
MCE’s VPP will include energy storage, smart thermostats, rooftop solar, heat pump space and water heating, and EV charging.
The VPP will initially be connected to up to 100 Zero Net Carbon Homes (ZNC Homes) and larger commercial and industrial sites. The ZNC Homes program will finance the acquisition, complete rehabilitation, and re-sale of homes as affordable properties. These ZNC homes will be built to be energy efficient and resilient, and each home will have a full complement of smart appliances and cost-saving equipment, including rooftop solar, battery energy storage, and heat pumps.
Local businesses will also have an opportunity to install batteries that provide resilience to grid outages, bill savings, and revenue generation potential, MCE said.
MCE will use the VPP in the statewide power markets – managed by the California Independent System Operator (CAISO) – to demonstrate the aggregation of customer resources by a CCA, and the integration, scheduling, and settlement of these resources in the CAISO markets.
Participating residents “will be paid for their role in providing localized grid services through a dynamic value-sharing agreement,” MCE said.
MCE is a load-serving entity supporting a 1,200 megawatts peak load. MCE provides electricity service and programs to more than 540,000 customer accounts and more than one million residents and businesses in 37 member communities across four Bay Area counties: Contra Costa, Marin, Napa, and Solano.
The American Public Power Association has initiated a new category of membership for community choice aggregation programs.
Florida Public Power Utility Gainesville Regional Utilities Interested In Energy Storage Options
June 22, 2022
by Paul Ciampoli
APPA News Director
June 22, 2022
Florida public power utility Gainesville Regional Utilities (GRU) recently issued a request for information (RFI) for energy storage.
The discharge duration for the energy storage facility should be at least 8 hours, the RFI said.
“While GRU is historically a summer peaking utility, it is trending towards becoming a dual season peaking utility. Load is forecast to increase both with population growth as well as greater electricity consumption due to electrification,” the RFI noted.
The energy storage system “will be used to reduce those peaks to fulfill its mission of providing reliable and affordably priced electricity.”
While long-duration batteries are of particular interest, GRU said it is open to other forms of energy storage. Geologic and geographic constraints preclude pumped storage and underground compressed air energy storage as viable choices. All other forms of energy storage will be reviewed.
The 2022 Infrastructure Investment and Jobs Act (IIJA) made funds available for use in developing and operating certain battery storage projects. GRU is pursuing a facility that will meet the application criteria for these grants and intends to apply for funding from the Department of Energy to partially finance this project. Novel projects that will improve the GRU’s candidacy for grant funding are preferred.
The Energy Authority (TEA) is acting as facilitator of the RFI. Responses are due July 15, 2022.
The RFI is available here.
Owned by the City of Gainesville, Fla., GRU provides electric, natural gas, water, wastewater, and communication utility services.
The American Public Power Association’s Public Power Energy Tracker is a resource for association members that summarizes public power energy storage projects that are currently online. The tracker is available here.
Public Power Officials Discuss Supply Chain Challenges At MMUA Event
June 21, 2022
by Paul Ciampoli
APPA News Director
June 21, 2022
Officials from Minnesota public power utilities, the American Public Power Association (APPA) and a power industry manufacturer recently discussed the power sector’s response to ongoing supply chain challenges facing the sector during a virtual roundtable held by the Minnesota Municipal Utilities Association (MMUA).
“What we’re facing right now truly is a perfect storm,” said Alex Hofmann, Vice President, Technical and Operations Services, at APPA.
He noted that when it comes to supply chain priorities, transformers are the highest-ranking priority for APPA’s members, “but there are many other concerns.”
APPA has been meeting with federal agencies to discuss supply chain issues, as well as with manufacturers.
“We’ve developed a simple voltage matching and sharing tool” through APPA’s eReliability Tracker. APPA is offering free access to the tracker for all public power utilities, he noted, because “to us, this is an emergency.”
Hofmann said that public power utilities, cooperatives and investor-owned utilities (IOUs) are all working together at the federal level.
“We plan to share, so if you reach out to your fellow public power utilities using this tool, you find that you’re not getting the response you need and we don’t have anything, we’re going to give that to the cooperatives and the IOUs and us their networks as well,” he said.
“Be creative. Pursue every measure you can. Your fellow utilities are in the same situation,” he said.
“I’m not here trying to bring you a doom and gloom story. I think that as infrastructure providers, we’re naturally very conservative, so we’re alarmed now that our stocks are getting low, but we still have stock and there are still people with units, it’s just those lead times are making our warehouses order larger amounts.”
Chad Backes, District Manager for Irby Utilities, a manufacturer for the electric utility sector, addressed the question of lead times in the context of supply chain issues.
“It depends upon the product line. It depends upon how much technology is involved and, of course,” how much copper and aluminum is involved, among other things.
“No manufacturer really has an ample supply of finished goods. They’re really struggling to get all their components,” Backes said.
He pointed out that “when one manufacturer goes down or isn’t taking any orders, that puts extra pressure on the other manufacturers that are still taking orders and they have to go out on the open market and buy the raw materials. Well, a lot of those purchases aren’t under contract and they’re having to pay spot prices.”
Backes also noted in core steel there is only one domestic manufacturer, AK Steel. “Everything else has to be imported and we’ve all seen pictures of the big container ships sitting in ports and nobody there to unload them or nobody there to load them.” All of the extra material “that’s being requested is driving that price up – just simply supply and demand.”
Backes also said that most of the core steel that needs to be used for transformers is also being used for batteries in electric vehicles and manufacturers are “making more money selling into the EV market than they are the transformers.”
Other participants in the roundtable included Mike Willetts, Director of Training & Safety at MMUA.
EIA Forecasts ‘Significant’ Increases In Wholesale Power Prices This Summer
June 21, 2022
by Peter Maloney
APPA News
June 21, 2022
Wholesale electric prices will rise significantly this summer over last summer’s prices, the Energy Information Administration (EIA) said in its latest Short-Term Energy Outlook (STEO).
The Northeast and New York will be hardest hit with expectations of $153 per megawatt hour (MWh) in ISO New England and $121/MWh in New York ISO, up from $50/MWh and $46/MWh last summer, respectively.
The EIA also expects wholesale electric prices to be over $100/MWh in the Northwest and MidAtlantic regions with the Northwest reaching $108/MWh and prices in the PJM Interconnection hitting $101/MWh, compared with $91/MWh and $45/MWh last summer, respectively.
The STEO forecasts wholesale prices for one price hub in each of the 11 market regions in the continental United States. The wholesale price data in the STEO reflect the monthly average electricity price in a region during on-peak hours between June and August.
While a variety of factors determine wholesale electricity prices, the cost of fuel for fossil-fuel generators, particularly natural gas, is an important driver in rising electric prices, the EIA said.
Natural gas-fired generation is often the most expensive source of dispatchable marginal generation, and the gas price at the Henry Hub averaged $8.14 per million British thermal units (MMBtu) in May 2022, compared with $2.91/MMBtu in May 2021, the EIA noted. “We expect the price of natural gas delivered to electric generators to average $8.81/MMBtu this summer, up from $3.93/MMBtu last summer,” the STEO noted.
In the past generators could substitute coal fired generation when the cost of gas-fired generation rose, but in recent months, coal plants have responded less than in the past as an alternative source of generation, most likely as a result of continued coal capacity retirements, constraints in fuel delivery to coal plants, and lower-than-average stock piles at coal plants, the STEO said.
The EIA forecasts that the share of U.S. generation from coal-fired power plants will decline from 25% last summer to 23% this summer, and natural gas’s share will remain relatively constant at 40%.
Other factors could also push wholesale electricity prices higher this summer, the EIA said, including the extended drought in the western United States.
The EIA forecasts a slight increase in hydroelectric generation in California this summer compared with last summer, but the forecast remains relatively low.
Less hydropower output this summer will likely lead California to generate more electricity from natural gas and to import electricity from neighboring states, the EIA said.
The STEO expects wholesale power prices in the California ISO to reach $98/MWh compared with $67/MWh last summer. Prices in the Southwest will be slightly lower, $97/MWh versus $82/MWh last summer, according to the STEO.
The Midcontinent ISO and the Electric Reliability Council of Texas (ERCOT) will also reach the $90 mark with MISO hitting $92/MWh versus $45/MWh last summer, and ERCOT hitting $90/MWh versus $54/MWh last summer, according to STEO forecasts.
The STEO puts Southwest Power Pool (SPP) prices at $82/MWh compared with $45/MWh last summer,
The STEO sees wholesale prices in the Southeast (SERC) hitting $76/MWh versus $45/MWh last summer, and in Florida (FRCC) the STEO forecasts prices $66/MWh compared with $41/MWh last summer.
At the residential level, the STEO forecasts prices will average 14.6 cents per kilowatt hour (kWh) between June and August, up 4.8 percent from last summer. Commercial prices will average 12 cents/kWh, a 4.7 percent increase, and industrial prices are expected to average 7.7 cents/kWh, 3.2 percent increase, according to the STEO.
Meanwhile, renewable generation sources are expected to contribute a growing share of electricity production, the STEO said. “We expect renewable energy will provide 22 percent of U.S. generation in 2022 and 24 percent in 2023, up from a share of 20 percent last year,” the report said.
The rise in renewable generation is coming from rising levels of new renewable capacity. Solar capacity additions in the electric power sector total 20 gigawatts (GW) for 2022 and 22 GW for 2023, the STEO reported, noting that solar photovoltaic installation delays from 2022 to 2023 account for about 1 GW of the expected installed solar capacity. The STEO also forecasts that small-scale solar systems – less than 1 GW – will grow to 39 GW by year-end 2022 and to 46 GW in 2023.
The STEO estimates that U.S. wind capacity additions will total 11 GW in 2022 and 5 GW in 2023.
FERC Proposes To Reform Generator Interconnection Procedures
June 20, 2022
by Paul Ciampoli
APPA News Director
June 20, 2022
The Federal Energy Regulatory Commission (FERC) on June 16 issued a Notice of Proposed Rulemaking (NOPR) to reform its generator interconnection procedures and pro forma interconnection agreements to address interconnection queue backlogs.
Although the proposals in the NOPR are not directly applicable to public power transmission owners, public power utilities in regional transmission organization (RTO)/independent system operator (ISO) regions may be subject to the proposed requirements under RTO/ISO tariffs or other governing agreements.
Also, as FERC specifically states in the NOPR, transmission providers that are not utilities subject to FERC’s general transmission jurisdiction (such as public power utilities) would be required to adopt the requirements of the NOPR as a condition of maintaining the status of any safe harbor tariff or otherwise satisfying the reciprocity requirements of FERC Order No. 888.
FERC noted that at the end of 2021, there were more than 1,400 gigawatts of generation and storage waiting in interconnection queues throughout the country. This is more than triple the total volume just five years ago (Docket No. RM22-14-000).
“Projects now face an average timeline of more than three years to get connected to the grid. As the resource mix rapidly changes, the Commission’s policies must keep pace,” it said in a news release.
The proposed rule includes several key areas of reforms.
First, it would Implement a first-ready, first-served cluster study process: Under the proposed first-ready, first-served cluster study process, transmission providers would conduct larger interconnection studies encompassing numerous proposed generating facilities, rather than separate studies for each individual generating facility.
FERC said this approach would increase the efficiency of the interconnection process and help minimize delays. To ensure that ready projects can proceed through the queue in a timely manner, transmission providers also would impose additional financial commitments and readiness requirements on interconnection customers.
The NOPR also aims to improve interconnection queue processing speed.
The NOPR proposes to impose firm deadlines and establish penalties if transmission providers fail to complete interconnection studies on time, except in instances where force majeure is applicable.
Additionally, the NOPR proposes a more detailed affected systems study process, including a specific modeling standard and pro forma affected system agreements. The NOPR also proposes reforms to administratively simplify the process of studying interconnection requests that are all related to the same state-authorized or mandated resource solicitation.
The NOPR also incorporates technological advancements into the interconnection process. It proposes to require transmission providers to allow more than one resource to co-locate on a shared site behind a single point of interconnection and share a single interconnection request. This would create a minimum standard that would remove barriers for co-located resources by creating a more efficient standardized procedure for these types of configurations.
The NOPR also proposes to allow interconnection customers to add a generating facility to an existing interconnection request under certain circumstances without automatically losing their position in the queue. In addition, the NOPR proposes to require transmission providers to consider alternative transmission solutions if requested by the interconnection customer.
It also calls for updating modeling and performance requirements for system reliability.
Specifically, the NOPR proposes certain modeling and performance requirements for non-synchronous generating facilities to address the unique characteristics of the changing resource mix. For example, to ensure that non-synchronous resources are better able to support reliability, the NOPR proposes to require them to continue providing power and voltage support during grid disturbances.
Comments on the NOPR are due 100 days after publication of the NOPR in the Federal Register. Reply comments are due 130 days after publication in the Federal Register.
FERC Acts On DER Aggregation Filings Submitted By California, N.Y. Grid Operators
June 20, 2022
by Paul Ciampoli
APPA News Director
June 20, 2022
The Federal Energy Regulatory Commission on June 16 responded to filings submitted by the California Independent System Operator (CAISO) and the New York Independent System Operator (NYISO).
The filings were made in compliance with FERC Order No. 2222 addressing the participation of aggregated distributed energy resources in wholesale markets administered by regional transmission organizations (RTOs) and independent system operators (ISOs).
The action, which took place at FERC’s monthly meeting, marked the first two compliance filings that FERC has acted upon tied to Order No. 2222.
In the CAISO order (Docket No. ER21-2455), FERC accepted the grid operator’s compliance filing, subject to a further compliance filing to be submitted within 60 days of the date of issuance of the order.
FERC directed CAISO to file a further compliance filing that either revises its distributed energy resource aggregation model or demonstrates that its existing demand response models are compliant with Order No. 2222.
FERC also directed further compliance associated with coordination requirements of Order No. 2222, such as the distribution utility review process.
In the NYISO order (Docket No. ER21-2460), FERC accepted NYISO’s compliance filing, subject to a further compliance filing to be submitted within 60 days of the date of issuance of the order.
Among other things, FERC directed NYISO to file a further compliance filing that allows distributed energy resources in heterogeneous aggregations to provide all of the ancillary services they are technically capable of providing through aggregation.
FERC also directed further compliance with respect to interconnection, participation, and coordination requirements of Order No. 2222, such as the distribution utility review process.
The Commission said that it will continue reviewing the remaining compliance filings, which were filed by ISO New England, Midcontinent Independent System Operator, the PJM Interconnection and Southwest Power Pool.
FERC Aims To Boost Grid Reliability Against Extreme Weather Conditions
June 20, 2022
by Paul Ciampoli
APPA News Director
June 20, 2022
The Federal Energy Regulatory Commission (FERC) on June 16 launched two rulemakings aimed at improving the reliability of the bulk power system against the threats of extreme weather.
FERC noted that these are the first proposed rulemakings stemming from a climate change and extreme weather proceeding that the Commission initiated in June 2021.
Commissioners voted on the Notice of Proposed Rulemakings (NOPRs) at FERC’s monthly meeting.
NOPR on Transmission System Planning Performance Requirements For Extreme Weather
In one of the NOPRs (Docket No. RM22-10), FERC proposes to direct the North American Electric Reliability Corporation (NERC) to develop and submit for Commission approval modifications to Reliability Standard TPL-001-5.1 (Transmission System Planning Performance Requirements). The modifications will address transmission system planning for extreme heat or cold weather events that impact the reliable operation of the bulk power system.
FERC staff noted that this proposed rule focuses on Reliability Standard TPL-001 because this standard establishes transmission system planning performance requirements to ensure the reliable operation of the bulk power system over a broad spectrum of system conditions and following a wide range of probable contingencies, including extreme events based on operating experience.
However, while TPL-001 references studies for “extreme events,” it does not specifically require performance analysis for extreme heat and cold weather conditions that affect wide geographical areas simultaneously over several days.
In addition, FERC staff noted that while the standard requires responsible entities (i.e., planning coordinator and transmission planner) to evaluate possible actions to reduce the likelihood or mitigate the consequences of extreme events, these entities are not obligated to develop and implement corrective actions.
To address this reliability gap in bulk power system planning, the NOPR proposes to direct NERC to develop modifications to Reliability Standard TPL-001-5.1 to require responsible entities to:
- Develop benchmark planning cases based on information such as major prior extreme heat and cold weather events or future meteorological projections;
- Plan for extreme heat and cold events using steady state and transient stability analyses expanded to cover a range of extreme weather scenarios including the expected resource mix’s availability during extreme heat and cold weather conditions, and include the broad area impacts of extreme heat and cold weather; and
- Develop a corrective action plan that includes mitigation for any instances where performance requirements for extreme heat and cold events are not met.
In addition to extreme heat and cold weather events, the NOPR also seeks comment on whether drought should be included in the scope of Reliability Standard TPL-001 to be modeled in the future to improve system performance during these events.
One-Time Reports On Extreme Weather Vulnerability Assessments
In the second NOPR (Docket Nos. RM22-16 and AD21-13), FERC proposes to direct transmission providers to submit one-time informational reports describing their current or planned policies and processes for conducting extreme weather vulnerability assessments and mitigating identified extreme weather risks.
FERC staff noted that the NOPR builds on the record of FERC’s June 2021 Technical Conference on Climate Change, Extreme Weather, and Electric System Reliability. FERC staff said that during this conference there was widespread agreement that utilities and other industry participants should assess the vulnerabilities of their systems to these risks.
However, the record to date does not indicate whether and to what extent transmission providers are conducting extreme weather vulnerability assessments, the methods used to conduct those assessments, and what is done with the information from those assessments, FERC staff said.
The proposed one-time reports would ensure the Commission can fulfill its statutory obligations with respect to system reliability and just and reasonable rates.
FERC staff said the goal of this proceeding is to gather information, not to establish new requirements. Therefore, the NOPR does not require transmission providers to conduct extreme weather vulnerability assessments where they do not do so already, or to require transmission providers to change how they conduct or plan to do such assessments.
The NOPR proposes to define an extreme weather vulnerability assessment as any analysis that identifies where and under what conditions jurisdictional transmission assets and operations are at risk from the impacts of extreme weather events, how those risks will manifest themselves, and what the consequences will be for transmission system operations.
The NOPR also proposes to require transmission providers to submit one-time informational reports on how they: (1) establish a scope for their extreme weather vulnerability assessments, (2) develop inputs, (3) identify vulnerabilities and determine exposure to extreme weather hazards, (4) estimate the costs of impacts, and (5) develop mitigation measures to address extreme weather risks.
Commissioners Weigh In
“Increasingly frequent cold snaps, heat waves, drought and major storms continue to challenge the ability of our nation’s electric infrastructure to deliver reliable affordable energy to consumers,” FERC Chairman Richard Glick said in discussing the NOPRs. The actions “are necessary to ensure that we are prepared for the challenges ahead.”
Commissioner Willie Phillips in his opening statement for the meeting said he agreed with the NOPR on transmission system planning performance requirements for extreme weather “to emphasize the critical importance of ensuring that the bulk power system is prepared for extreme weather events in both the near-term and long-term.”
While the NOPR “has the potential to reduce the threat to the reliability of the electric system, I note that we must remain vigilant as much work remains to ensure reliable delivery of power to consumers during times of stress and to resolve resilience concerns on the transmission system,” he said.
“In my view, this NOPR is another step on the path to mitigating the long-term effects of extreme weather; however, I remain concerned about the grid’s near-term reliability, particularly during the upcoming summer and winter seasons,” he said.
Phillips also said that the regional nature of extreme weather “highlights the difficulties facing our industry in addressing highly variable risks. The challenges facing California are very different from the challenges facing Texas. I believe a minimum transfer capability requirement is needed, because enhanced transfer capability may be the best way to take advantage of the diversity of energy sources and the many ways in which we can support the grid.”
Commissioner Allison Clements offered a concurrence on the NOPR directing NERC to revise its transmission planning reliability standard.
She said that while the NOPR represents “an important step in tackling extreme weather’s myriad impacts on the transmission system, strong follow through from NERC will be required to ensure a reliability standard that addresses extreme weather reliability challenges in a comprehensive and cost-effective manner.”
Clements said that while the NOPR seeks comments on whether drought should be included along with extreme heat and cold weather events within the scope of Reliability Standard TPL-001-5.1, she believes “that what we already know about meteorological projections and drought’s anticipated impacts on the electricity system compel the development of drought benchmark events in applicable regions of the country.”
The question for her is not whether such events should be included, but how TPL-001-5.1 should cover the impact of drought induced reductions in supply on regions already experiencing unprecedented reductions in reservoir supply and increased wildfire risk.
Clements also said that it is important to note “that if we are to cost-effectively ensure system reliability as the frequency and intensity of extreme weather events continues to increase, further action is necessary to complement” the NOPR.
Commissioner James Danly, while concurring in both NOPRs, challenged the Commission’s focus on extreme weather. In his concurrence to the NOPR directing NERC to revise Reliability Standard TPL-001-5.1, he argued that “even if one were to grant that certain parts of the United States were experiencing statistically unusual weather when compared to historical baselines, that has absolutely nothing to do with whether the markets and regulated utilities are procuring sufficient generation of the correct type to ensure resource adequacy and system reliability.” According to Danly, weather is not the problem, “[t]he problem is federal and state policies which, by mandate or subsidy, spur the development of weather dependent generation resources at the expense of the dispatchable resources needed for system stability and resource adequacy.”
Comments on both proposals are due 60 days after the date of publication in the Federal Register.
Lawmakers Highlight Supply Chain Challenges Facing Public Power In Letter To FEMA
June 20, 2022
by Paul Ciampoli
APPA News Director
June 20, 2022
A group of federal lawmakers from Florida on June 10 sent a letter to the Federal Emergency Management Agency (FEMA) in which they highlight “the dangerous supply chain shortages affecting Florida’s electric cooperatives and municipalities.”
The letter, which was sent to FEMA Administrator Deanne Criswell, said that labor shortages and competition from other industries for steel have made equipment procurement difficult.
“As a result, critical electric grid equipment delivery times have increased 20-fold in the past 2 years. Transformers, the most integral pieces in ensuring electricity to homes, took only 3 months to be delivered in 2018. Currently, delivery delays for transformers are averaging 52 to 75 months, and some manufacturers are not even taking orders,” the letter said.
“This is particularly concerning given that the 2022 Atlantic hurricane season is forecasted to produce hurricanes and tropical storms of above-average strength,” the lawmakers said.
“As the onset of the 2022 Atlantic hurricane season approaches, we urge FEMA to mitigate this issue before a severe hurricane or tropical storm devastates our Floridian communities.”
The letter noted that each year, Florida electric cooperatives and municipalities prepare for the upcoming hurricane season by stockpiling supplies. “When disasters occur, destroyed equipment needs to be replaced to ensure quick power restoration. The severe delay of critical parts has made this preparation nearly impossible, leaving many electric companies without reserves. It would take only one hurricane or severe tropical storm to cause devastating damage to our constituents, and with the absence of a stockpile, power restoration for these communities would take substantially longer than previous years.”
Local electric utilities “play a critical role in the growth and development of the communities they serve. Unfortunately, these new supply chain issues adversely affect the growth and management of these communities. Without proper equipment, local utilities must triage parts, which delays upgrades and ‘non-essential’ repairs,” the letter said.
The weakened systems “will make them more susceptible to damage when disaster occurs. FEMA must employ mitigation efforts with the local Florida electric community to ensure that transformers, bare wire, meters, and other electric grid equipment will be available ahead of the first disaster.”
TVA’s Lyash Underscores Need For Public Power Utilities To Share Expertise, Best Practices
June 17, 2022
by Paul Ciampoli
APPA News Director
June 17, 2022
Now more than ever it is crucial for public power utilities “to share our expertise, our best practices, our best thinking as we collaborate on solutions” to solving new challenges, said Jeff Lyash, President and CEO of the Tennessee Valley Authority, on June 14 in a speech at the American Public Power Association’s (APPA) 2022 National Conference in Nashville, Tenn.
As an example, Lyash noted that supply chain challenges “are an immediate concern.”
APPA has taken a leadership role when it comes to addressing supply chain challenges, Lyash said, noting that APPA held a supply chain summit in May and has developed a voltage matching and sharing tool through APPA’s eReliability Tracker.
“I’m grateful to everyone who’s working with others to mitigate delays and shortages in transformers and other equipment,” Lyash said.
He noted that TVA leaders recently met “with many of our local power companies that we serve and like many of you we’re focused on how we can best leverage resources and collaborate to meet these immediate needs.”
TVA Strategic Intent And Guiding Principles Document
Meanwhile, Lyash noted that a year ago, TVA issued a Strategic Intent and Guiding Principles document, which he stressed “reinforces our commitments and sets realistic and clear targets.”
TVA’s board in May 2021 approved a resolution endorsing TVA’s Strategic Intent and Guiding Principles.
Lyash said that TVA is on a path to “reduce our carbon emissions by 80 percent against a 2005 benchmark by 2035. We’ve already reduced carbon emissions by 60 percent and we’re executing a plan to reach 80 percent.” TVA believes it can deliver on this plan without raising prices or adversely affecting reliability.
“Going further or faster will take research, development and the deployment of technologies that, frankly, we don’t have today at a competitive price,” he said.
Maintaining a balance
Electricity “is foundational to national security, quality of life, health and safety, and it will be more so in the coming decades than it is today,” Lyash said.
There is a balance “that we have to maintain,” he said, noting that his “view of this is that balance is between” affordability, reliability, resiliency, and sustainability.
“If you sacrifice one for the others, it all falls apart,” Lyash said.
“We cannot have net zero carbon if we triple the price of electricity,” he said. “Likewise, we can’t have low-cost electricity and not address greenhouse gas reduction and cleaning up our industry. We can’t sacrifice reliability for price. This is a balance among these four that is critically important.”
Transitioning To The Future
Addressing the energy industry’s transition to the future, Lyash said that “this is a generational transition. It would be nice to do this tomorrow, but it’s mandatory that we do it successfully.”
There needs to be a focus on practicality “and doing what we can do, when we can do it and staying focused on that mission,” he said.
Lyash believes that the power industry is “going to be one of the keys for the next three decades.”
Public power “has the opportunity to be at the forefront of that because the people in the room I’m looking at don’t wake up every morning” worried about things like shareholder return and earnings.
“We all wake up every morning worried about the one hundred million people that we collectively serve and what’s best for them and how can we contribute to that,” he said.
“On our path to a clean energy economy for our customers and the nation, no one technology, no one point of view will get us there. Our collaborative journey is going to require” the best science, best leadership and it’s going to have to happen across multiple fronts, he said.
“Broad perspectives on energy sources, opportunities, and innovation will be required. We need to share knowledge, we need to forge strong partnerships, we need to build effective collaboration on a wide range of issues, particularly new technology.”
Public power utilities “know those requirements well. They are some of public power’s strengths, in fact – collaboration, commitment and leadership. As with any important issue, how we achieve the clean energy economy needs to foster varying points of view and I encourage you to share your ideas, share your perspectives, share those of your customers and your communities,” Lyash said.
Ditto Urges Deliberative Process Tied To Implementation of Cyber Incident Reporting Law
June 17, 2022
by Paul Ciampoli
APPA News Director
June 17, 2022
American Public Power Association (APPA) President and CEO Joy Ditto on June 9 sent a letter to Jennifer Easterly, Director of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) regarding implementation of the Cyber Incident Reporting for Critical Infrastructure Act of 2022.
In the letter, Ditto asks for a commitment from Easterly “to take a careful and deliberative process that takes into account existing reporting mandates and to appropriately tailor reporting mandates commensurate with risk to national security.”
Signed into law by President Biden in March, the law requires critical infrastructure entities to report cyber incidents to CISA within 72 hours and ransomware payments within 24 hours. CISA is directed to publish a notice of proposed rulemaking to implement the reporting requirements within 24 months.
Ditto noted in her letter that the electric sector has mandatory and enforceable federal regulatory standards in place for cyber and physical security. These standards include mandatory reporting of specific cyber incidents to the Department of Energy (DOE) via an Electric Emergency Incident and Disturbance Report and to the North American Electric Reliability Corporation (NERC) and Federal Energy Regulatory Commission (FERC).
Outside of these mandatory reporting standards, public power utilities participate in robust voluntary information sharing systems such as the Electric Subsector Coordinating Council and the Electricity Information Sharing and Analysis Center, as well as the Multi-State Information and Sharing Analysis Center.
Moreover, electric utilities worked closely with the National Security Council, DOE, and DHS on the “100 Day Electric Sector Industrial Control Systems Cybersecurity Sprint” to encourage and support utilities’ visibility and monitoring of their industrial control system and operational technology networks, as well as automated sharing into government, Ditto pointed out.
The electric sector “is unique among critical infrastructure sectors in the extent and maturity of existing information sharing regulations and programs,” she wrote. Public power utilities, as units of state and local governments and varying so widely in size and risk profiles, are still more unique.
“Given these complexities, and pursuant to Congress’ expressed intent, it is critical that CISA work directly with our industry’s sector risk management agency, DOE, as well as FERC and NERC, and industry itself, to harmonize, to the maximum extent possible, new reporting mandates and processes with those that already exist.”
In addition, Ditto strongly urged CISA to use “the considerable discretion given to it by Congress in the law to define covered entities for the purposes of mandated reporting of cybersecurity incidents in a risk-based manner.”
As Congress explicitly stated in the law, CISA must define the types of entities that constitute covered entities based on the “consequences that disruption to or compromise of such an entity could cause to national security, economic security, or public health and safety,” she said.
“This is of particular importance to public power utilities, as APPA’s members have widely different risk profiles ranging from an electric utility with transmission assets that serves millions of customers to a very small distribution electric utility without an industrial control system serving 200 customers,” wrote Ditto.
She requested a meeting with Easterly and her team leading implementation to discuss the matters raised in the letter in detail.