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Groups Urge Congress To Prevent The Potential Elimination Of Bond Payments

June 27, 2022

by Paul Ciampoli
APPA News Director
June 27, 2022

The American Public Power Association (APPA) and 13 other members of the Public Finance Network recently urged leaders of the House and Senate Budget Committees to prevent the potential elimination of direct payment bond payments starting in 2023.

The June 21 letter stems from concern that unless Congress acts to waive the Pay As You Go Act (PAYGO) in relation to the American Rescue Plan Act (ARPA) enacted last year, payments to issuers of direct pay bonds will be eliminated in 2023 through 2026.

At the end of 2021, Congress moved to prevent PAYGO from applying to ARPA in 2022. However, Congress failed to provide a permanent fix to the problem. Based on Office of Management and Budget data, unless Congress acts, direct payment bond payments will be cut by $14 billion — roughly eight percent of which would fall on public power issuers.

“As we collectively worked to emerge from the Great Recession over a decade ago, state and local governments utilized options made available to stimulate the economy and undertook several hundred billion dollars in critical, long-term infrastructure obligations through the issuance of direct subsidy bonds,” the letter noted.

At the time, the understanding was that federal payments related to these bonds would not be subject to the appropriation process and would not be subject to sequestration. “To our dismay, the federal government appears on the brink of completely reneging on this deal by eliminating $14 billion in payments to state and local entities,” APPA and the other groups said.

Specifically, unless new legislation is enacted that will waive PAYGO) as it relates to the budgetary effects of ARPA, thousands of state and local entities will not receive any Build America Bond (BAB), Qualified School Construction Bonds (QSCB), Qualified Zone Academy Bonds (QZAB), New Clean Renewable Energy Bonds (New CREB), or Qualified Energy Conservation Bonds (QECB) payments otherwise guaranteed to them under the law. 

The letter notes that entities that issued these bonds — generally in 2009, 2010, and 2011 — did so in partnership with the federal government.

Payments to issuers of the special purpose bonds “are already laboring under a steady stream of cuts triggered by the Budget Control Act of 2011 due to the failure of the Joint Select Committee on Deficit Reduction,” APPA and the other groups said.

These “Joint Committee Reductions” began in 2013 and are now expected to continue through 2031. Joint Select Committee reductions will have cut payments by nearly $3 billion by the end of Fiscal Year 2022 and will cut payments by another $1.6 billion by the end of Fiscal Year 2031.

“Allowing Joint Committee Reductions to continue is a travesty,” the groups argued. Allowing PAYGO to eliminate these payments entirely “would be catastrophic: to communities that stepped up during the Great Recession to try to create jobs when job creation was desperately needed; to students in schools that are already underserved; and to renters and homeowners that are already struggling to pay utilities, taxes, and other bills.”

As a result, the groups said that they hope that Congress “will overcome its differences and fix this problem for all Americans.”

Those also signing the letter include, among others, the Large Public Power Council, American Public Gas Association, U.S. Conference of Mayors, National League of Cities, National Association of Counties, and Government Finance Officers Association.

FMPA Implementing Strategies To Mitigate Rising Fuel Costs For Florida Public Power

June 27, 2022

by Paul Ciampoli
APPA News Director
June 27, 2022

The Florida Municipal Power Agency (FMPA) is taking a number of steps to mitigate rising fuel costs, including selling excess power generation to other cities, prepaying for natural gas at discounted prices, operating highly available and efficient units, and refinancing debt, said Navid Nowakhtar, Resource and Strategic Planning Manager at FMPA, in a recent presentation.

He made his remarks during a June 7 presentation to the Fort Pierce Utilities Authority (FPUA) Board. FPUA is a member of FMPA, a wholesale power agency owned by 31 municipal electric utilities in Florida.

In his presentation, Nowakhtar detailed the drivers behind some of the energy price increases seen in the U.S., including higher natural gas prices.  

He noted that in Florida, 80% of “our electric generation is from natural gas – that’s our primary fuel source.”

Across the U.S., “historically, we would have had coal resources pick up some of the slack as gas prices rose, but as a result of retirements and additional infrastructure challenges related to coal generation and transport with coal, we don’t have that substitute effect any longer to the extent we had it in prior periods,” Nowakhtar said.

He said the demand for natural gas has increased, while production remains flat, and noted that natural gas inventories remain low.  

“As we look at these price challenges, one of the opportunities” potentially in play “is to look at fixed-price natural gas,” Nowakhtar said. “Certainly, not over the course of this coming summer — gas prices already are well above the norm.”

At a later point in his presentation, he noted FMPA is doing several things to help mitigate the impact of high fuel costs on customers.

Nowakhtar noted that FMPA’s efforts have saved more than $32 million since fiscal 2021.

Those savings are as follows, FMPA noted:

He also noted that “if you look at where Fort Pierce’s rates are today through the end of last year, they’re actually lower than they were in 2008.” Residential rates are down about 23%, while U.S. rates have gone up about 22%.

He said FMPA has “done a lot of work to try to keep our costs as low as we can to you.”

Nowakhtar also pointed out that FMPA is continuing to pursue low-cost solar. “We’re in the process right now of the procurement efforts for phase three of our solar project. We already have two sites totaling 149 megawatts” that are online.

In 2022, FMPA’s percentage of solar energy stood at 2%, but that is projected to grow to 7% of its generation mix by 2027.

He said there are seven to 10 FMPA communities “or more” that could be interested in the third phase of the solar project, which will involve as much as two to three sites of additional solar.

In a recent letter to leaders of the U.S. Senate Energy and Natural Resources Committee, FMPA’s General Manager and CEO Jacob Williams said Florida is uniquely impacted by the 150% cost increase for natural gas, given the state’s dependence on natural gas for electricity generation.

He noted in the May 2 letter that residential bills in Florida were already 15-30% higher. “This is especially challenging for us since our power consumption is 25% higher than the national average and income is 10% lower than the national average. In addition, Florida residents consume half of the electricity generated in Florida, the largest share of any state in the U.S. And the skyrocketing energy prices in the U.S. very well may get worse,” Williams wrote in his letter to Sen. Joe Manchin, D-W.Va., Chairman of the committee, and Sen. John Barrasso, R-Wyo., and ranking member on the committee.

APPA Seeks Nominations for Three Openings on RP3 Review Panel

June 22, 2022

APPA News
June 22, 2022

The American Public Power Association (APPA) is accepting nominations now through Tuesday, July 5, 2022 for an open position on the Reliable Public Power Provider (RP3) Program Review Panel. 

APPA’s RP3 program is based on industry-recognized leading practices in four important disciplines:

A RP3 designation is a sign of a utility’s dedication to operating an efficient, safe, and reliable distribution system. Being recognized by the RP3 program demonstrates to community leaders, governing board members, suppliers, and service providers a utility’s commitment to its employees, customers, and community. Currently 275 of the nation’s more than 2,000 public power utilities hold a RP3 designation. 

Each member of the Panel can serve for up to three consecutive two-year terms (for a total of six years), and is expected to attend three meetings per year, one in the spring and two in the fall. The appointed member’s first term will begin immediately and expire after two years in 2024 (at the Business meeting of that year). Please find the position requirements below:

More information on the RP3 program is available on the RP3 website. To nominate someone, please click here to download the nomination form: 

The completed nomination form and any supplementary materials should be emailed to RP3@PublicPower.org. If you have questions, contact RP3 Staff at RP3@PublicPower.org or 202-467-2931.

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:

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.