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Vermont Senate Passes Budget That Provides AMI Funding For Public Power

April 26, 2022

by Paul Ciampoli
APPA News Director
April 26, 2022

The Vermont Senate recently approved an $8 billion budget that includes a significant investment for advanced metering infrastructure (AMI) in the state’s public power communities. The budget passed the Senate on April 20, 2022.

In March, House lawmakers recognized a need for AMI funding for public power and cooperative electric utilities. The House passed its version of the budget bill with $5 million in one-time funding from the General Fund appropriated to AMI.

The Senate Appropriations Committee then provided unanimous support for an additional $3 million in funding, for a total $8 million “towards the affordable, equitable implementation of AMI in Vermont’s rural communities,” the Vermont Public Power Supply Authority (VPPSA) noted.

The $8 million of AMI funding will be administered by the Vermont Department of Public Service. It will be applied as a reimbursement to public power and cooperative electric utilities that implement AMI systems that have been approved by the Vermont Public Utilities Commission.

The bill will now likely head to a conference committee consisting of House and Senate negotiators. Action on the budget will be taken by Vermont Governor Phil Scott later this spring.

VPPSA provides municipal electric utility members with a broad spectrum of services and solutions, including regulatory assistance, financial planning, and power supply.

VPPSA members include Barton Village, Village of Enosburg Falls, Hardwick Electric Department, Village of Jacksonville Electric Company, Village of Johnson Electric Department, Ludlow Electric Light Department, Lyndonville Electric Department, Morrisville Water & Light Department, Town of Northfield Electric Department, Village of Orleans, and Swanton Village Electric Department.

FERC Issues Proposal To Reform Regional Grid Planning, Cost Allocation Requirements

April 25, 2022

by Paul Ciampoli
APPA News Director
April 25, 2022

The Federal Energy Regulatory Commission (FERC) on April 21 issued Notice of Proposed Rulemaking (NOPR) to reform the Commission’s electric regional transmission planning and cost allocation requirements. 

The proposed reforms are intended to remedy deficiencies in the Commission’s existing regional transmission planning and cost allocation requirements to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential, FERC staff noted in a presentation given at the Commission’s monthly open meeting (Docket No. RM21-17).

The NOPR, which was issued pursuant to Section 206 of the Federal Power Act, builds on FERC Order Nos. 888, 890, and 1000, in which the Commission incrementally developed the requirements that govern regional transmission planning and cost allocation processes to ensure that Commission-jurisdictional rates remain just and reasonable and not unduly discriminatory or preferential.

Of particular note to public power utilities, the NOPR seeks to promote joint ownership of transmission facilities by proposing to modify FERC Order No. 1000 to permit incumbent transmission owners to exercise a federal right of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation, conditioned on the incumbent transmission provider establishing joint ownership of those facilities.

In late 2021, the American Public Power Association (APPA) urged the Commission to promote joint transmission ownership through the transmission planning process. APPA’s comments came in response to an advance notice of proposed rulemaking (ANOPR) issued by FERC in July 2021 to reform its transmission planning, cost allocation, and generator interconnection rules.

Regional Transmission Planning

With respect to regional transmission planning, the reforms proposed in the NOPR would require transmission providers to conduct long-term regional transmission planning on a sufficiently forward-looking basis to meet transmission needs driven by changes in the resource mix and demand. 

As part of this long-term regional transmission planning, transmission providers would be required to:  (1) identify transmission needs driven by changes in the resource mix and demand through the development of long-term scenarios, including accounting for high-impact, low-frequency events such as extreme weather; (2) evaluate the benefits of regional transmission facilities to meet these needs over a time horizon that covers, at a minimum 20 years starting from the estimated in-service date of the transmission facilities; and, (3) establish transparent and not unduly discriminatory criteria to select transmission facilities in the regional transmission plan for purposes of cost allocation that more efficiently or cost-effectively address these transmission needs. 

Additionally, the NOPR proposes to require that transmission providers more fully consider dynamic line ratings and advanced power flow control devices in regional transmission planning.

Cost Allocation

With respect to transmission cost allocation, the reforms proposed in the NOPR would require that transmission providers in each transmission planning region seek to obtain the agreement of relevant state entities within the transmission planning region regarding the cost allocation method or methods that will apply to transmission facilities selected in the regional transmission plan for purposes of cost allocation through long-term regional transmission planning and revise their OATTs to include those methods.

The NOPR also proposes to not permit transmission providers to take advantage of the Commission’s construction-work-in-progress (CWIP) rate incentive for transmission facilities selected in the regional plan for purposes of cost allocation through long-term regional transmission planning.

With respect to federal rights of first refusal, the NOPR proposes to amend Order No. 1000’s requirements, in part, to permit the exercise of federal rights of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation, conditioned on the incumbent transmission provider establishing joint ownership of the transmission facilities.

With respect to transparency and coordination, the NOPR proposes to require transmission providers to adopt enhanced transparency requirements for local transmission planning processes and improve coordination between regional and local transmission planning with the aim of identifying potential opportunities to “right-size” replacement transmission facilities.

With respect to interregional transmission coordination and cost allocation, the reforms proposed in the NOPR would require that transmission providers revise their existing interregional transmission coordination procedures to reflect the long-term regional transmission planning reforms proposed in the NOPR.

The proposed reforms in the NOPR related to regional transmission planning and cost allocation requirements, are focused on the transmission planning process, and not on any substantive outcomes that may result from this process. 

The NOPR seeks comment on the proposed reforms and encourages commenters to identify enhancements to those reforms that could better support development of more efficient or cost-effective transmission facilities.

Comments on the NOPR are due 75 days from the date of publication in the Federal Register, with reply comments due 30 days after the initial comment deadline. 

Commissioners Weigh In

“Transmission facilities provide a broad range of benefits,” FERC Chairman Rich Glick said. “Planning for those facilities with a longer-term forward-looking approach, in addition to fairly allocating their costs, is essential to ensuring we are developing energy infrastructure in a manner that reduces costs and enhances reliability.”

FERC Commissioner Allison Clements said in her opening statement at the meeting that the NOPR “is not a plan to foist the costs of one state’s policies onto another.  It is also not a policy action to advance renewable energy interests.”

The NOPR “contains a sensible suite of reforms to shore up” cost protections and reliability of the U.S. electricity system “based on clear market signals about generation development and demand, the risks of extreme weather, and the increasing threat of cyber- and physical attacks,” she said.

Commissioners Christie and Phillips Concurred With Order

Commissioners Willie Phillips and Mark Christie concurred with the order.

“The record here appears to show that transmission expansion is increasingly occurring in a piecemeal and inefficient fashion outside of the regional transmission planning process, which may not be cost-effective for consumers in the long run,” said Phillips.

“While commenters’ views vary on how best to address this problem, nearly all commenters endorse some form of proactive planning for the future resource mix and demand,” he said in the concurrence.

“I believe the NOPR proposal to require long-term scenario planning, including accounting for extreme weather events, is necessary to maintain the reliability of the grid and to ensure that transmission costs are just and reasonable,” wrote Phillips. “I also note that while this NOPR proposes to require the evaluation of benefits of long-term regional transmission facilities over a 20-year time horizon, it does not propose to prescribe any particular definition of ‘benefits’ or ‘beneficiaries,’ nor require use of any specific benefit.”

Commissioner Christie noted in his concurrence that the NOPR “will formally put the states — for the first time — at the center of regional transmission planning and cost allocation decision-making for policy-driven projects in all regional transmission entities, if the states choose.”

The NOPR “will shift the risk of financing policy-driven projects from consumers back to developers, where it should be.”

He said that he “will not support any final rule that exceeds our FPA authority and/or threatens to cause unjust and unreasonable rates to consumers.”

Commissioner Danly dissents

In his dissent, Commissioner Danly said that while he welcomes long term transmission planning reform, he would prefer that Regional Transmission Organizations (RTOs) and other interested utilities “simply file their own proposals” under section 205 of the FPA. “They are fully capable of proposing rate changes and reforms on their own,” he wrote.

The NOPR “goes far beyond that. It contemplates a Federal Power Act section 206 finding that existing transmission planning across the nation—in every region, for every utility and market—is so unjust and unreasonable that it must be replaced with mandatory, pervasive, and invasive ‘reforms,’” Danly argued.

He further asserted that the NOPR’s “primary purpose is to achieve narrow environmental policy objectives, not to address legitimate requirements under the Federal Power Act like ensuring just and reasonable rates or reliability.”

While he believes the NOPR is a mistake, “I am happy to be convinced that particular reforms are justified by sound legal argument and solid record evidence,” Danly went on to say. “Where reform is needed to ensure just and reasonable rates and reliable service, and the reform itself is just and reasonable, I can be persuaded that it is worthy of support.”

But he reiterated his strong preference that FERC allow utilities to file their own transmission planning solutions under FPA section 205. 

He said that if the Commission really believes that it cannot rely on utilities to seek more efficient transmission planning of their own volition, “my second option would be to issue section 206 orders requiring the RTOs to show cause why their existing transmission planning processes are just and reasonable. Whether you agree or disagree with these alternative procedural vehicles for change, please say so in your comments.”

California Public Power Utilities To Participate In DOE “Vehicle to Everything” Initiative

April 25, 2022

by Paul Ciampoli
APPA News Director
April 25, 2022

The U. S. Department of Energy (DOE) and partners on April 20 announced the Vehicle to Everything (V2X) memorandum of understanding (MOU), which will bring together resources from DOE, DOE national labs, state and local governments, utilities, and private entities to evaluate technical and economic feasibility as the country integrates bidirectional charging into energy infrastructure.

Included among the MOU signatories are two public power utilities — Los Angeles Department of Water and Power and the Sacramento Municipal Utility District.

The MOU will also advance cybersecurity as a core component of V2X charging infrastructure, DOE said.

Bidirectional plug-in electric vehicles (PEVs) “present immense potential for increasing the country’s energy security, resilience, economic vitality, and quality of life while supporting the electrical grid. A bidirectional EV fleet could serve as both a sustainable mobility option as well as an energy storage asset that sends power back to everything from critical loads and homes to the grid. A bidirectional fleet could also create new revenue opportunities for EV owners or fleets,” DOE said.

DOE also announced that it is tackling the technical challenges and barriers to the integration of tens of millions of EVs with the electric grid, commonly referred to as Vehicle Grid Integration (VGI) through the EVs@scale lab consortium.

The consortium brings together six DOE national laboratories to conduct RD&D in the areas of smart charge management, high power charging and facilities, dynamic wireless charging, codes and standards, and cyber physical security.

In addition to addressing the near-term challenges to VGI to benefit all electric vehicle (EV) stakeholders, the lab consortium will conduct high risk, high reward research on the EV charging and grid integration technologies the U.S. will need in the future, according to DOE.

DOE said that this collaboration can accelerate and enable bidirectional PEV integration into the electrical grid by:

Click here for the MOU.

Energy Storage Will Grow Quickly, NREL Report Says

April 25, 2022

by Peter Maloney
APPA News
April 25, 2022

Energy storage deployments could grow rapidly in the coming decades, reaching between 130 gigawatts (GW) and 680 GW by 2050, enough to support renewable generation of 80 percent or higher, according to a new report from the National Renewable Energy Laboratory (NREL).  

The report, Storage Futures Study: Key Learnings for the Coming Decades, which is the seventh and final of NREL’s Storage Futures Study (SFS) series launched in 2020, argues that energy storage will likely play a critical role in a low-carbon, flexible, and resilient future grid.

“Each phase of the study has indicated a potential coming wave of energy storage, with U.S. installed storage capacity increasing by at least five times by 2050,” Nate Blair, principal investigator of the study, said in a statement. “Overall, we find energy storage offers significant value, from easier grid operations to fewer costly thermal start-ups to reduced emissions.”

Among the key findings, the report found that diurnal storage is economically competitive across a variety of scenarios that include a range of cost and performance assumptions for storage, as well as power generated from wind, solar, or natural gas. “Even the most conservative case represents a fivefold increase compared to the installed storage capacity of 23 GW in 2020,” the majority of which is pumped storage hydropower, the report’s authors said.

NREL’s modelling indicated that “significant deployments” of both renewable energy and energy storage could be deployed even without additional carbon policies, which, the authors said, demonstrates their increasing cost-competitiveness as resources for provision of energy and capacity services.”

And while “stacking” the functions that energy storage devices can perform, which runs from time shifting peak demand to avoiding new transmission investments, the ability of storage to provide firm capacity to offset the need for conventional generation to meet peak demand is “critical to realizing its full potential,” the authors found.

NREL’s models also showed that increased levels of energy storage deployment flatten the peak load curve and thus increases the amount of stored energy required to provide firm capacity and to continue reducing net peak demand. That could present opportunities for emerging technologies capable of longer durations, or even for the next generation of existing long-duration technologies such as pumped storage hydropower, the report’s authors said.

However, the report’s authors also noted that widescale electrification of heating could shift the peak load to the winter for much of the United States, which would create longer peaks that are more difficult to meet with storage and solar power. If that occurs, it could increase the value of wind generation and longer-duration storage, the report said.

And even though energy storage is highly competitive as a new source of peaking capacity without carbon dioxide mitigation policies in place, “it is important to recognize that technology or policy changes could affect the growth prospects of energy storage,” the report noted.

“Despite important modifications to regulatory frameworks over the past decade, storage remains a challenging technology to appropriately value and compensate, particularly in restructured markets,” the authors wrote. “If storage is not compensated fairly, it could result in nonoptimal storage deployment.”

The report also noted that flexibility will be key to decarbonizing the power sector at least cost and that will likely require a variety of resources, some of which may cost less than energy storage. “Establishing better characterization of demand response, flexible loads’ realistic contribution potential, and cost is critical to better understanding the opportunities for energy storage,” the authors said.

The Key Learnings report modeled hundreds of future scenarios and added new capabilities to NREL’s publicly available Regional Energy Deployment System (ReEDS) capacity expansion model to represent the value of diurnal battery energy storage. To simulate grid operations in the ReEDS scenarios, NREL used the commercially available PLEXOS production cost model. On the distribution side, NREL added new storage capabilities to its open-source Distributed Generation Market Demand (dGen) model to simulate customer adoption of solar-plus-storage systems under different battery and backup-power value assumptions.

FERC Directs Grid Operators To Report On Changing System Needs, Plans

April 25, 2022

by APPA News
April 25, 2022

The Federal Energy Regulatory Commission on April 21 directed the operators of six regional organized electric power markets to provide information regarding their changing system needs and plans for potential reforms. 

The California Independent System Operator Corp., ISO New England, Inc., Midcontinent Independent System Operator, Inc., New York Independent System Operator, Inc., PJM Interconnection, L.L.C., and Southwest Power Pool, Inc. have 180 days to file reports in response to the order.

The order follows a staff whitepaper and four technical conferences conducted in 2021 that explored the changing nature of the organized markets and their operations.  

The Commission received comments on the potential challenges associated with “one size fits all” solutions and is gathering additional information from each market operator to better understand how their unique resource mixes and load profiles impact their respective system needs across all their markets and their respective plans to address those needs. 

Reports are expected to comprehensively address current system needs given recent changes in resource mixes and load profiles; operator expectations regarding system needs over the next five years and ten years; whether and how each market operator plans to reform its markets to meet expected system needs.

Public comments are due 60 days following the filing of the reports. The Commission will review the reports and comments to determine whether further action is appropriate.

Advisory Offers Most Comprehensive View On Cyber Threat Posed By Russia Since Invasion

April 23, 2022

by Paul Ciampoli
APPA News Director
April 23, 2022

The Cybersecurity and Infrastructure Security Agency (CISA), along with other U.S. government entities and a number of international organizations, recently issued a joint cybersecurity advisory on Russian state-sponsored and criminal cyber threats to critical infrastructure that could impact organizations both within and beyond Ukraine.  

“It is the most comprehensive view of the cyber threat posed by Russia to critical infrastructure released by government cyber experts since the invasion of Ukraine in February,” CISA said on April 20.

The advisory provides technical details on malicious cyber operations by actors from the Russian Federal Security Service, Russian Foreign Intelligence Service, Russian General Staff Main Intelligence Directorate, and Russian Ministry of Defense, Central Scientific Institute of Chemistry and Mechanics.

It also includes details on Russian-aligned cyber threat groups and cybercrime groups. Some of these cybercrime groups have recently publicly pledged support for the Russian government and have threatened to conduct cyber operations in retaliation for perceived cyber offensives against Russia or against countries or organizations providing materiel support to Ukraine. 

The advisory recommends several immediate actions for all organizations to take to protect their networks, which include prioritizing patching of known exploited vulnerabilities, enforcing multifactor authentication, monitoring remote desktop protocol and providing end-user awareness and training. 

“We know that malicious cyber activity is part of the Russian playbook. We also know that the Russian government is exploring options for potential cyberattacks against U.S. critical infrastructure. Today’s cybersecurity advisory released jointly by CISA and our interagency and international partners reinforces the demonstrated threat and capability of Russian state-sponsored and Russian aligned cyber-criminal groups to our Homeland,” said CISA Director Jen Easterly. “We urge all organizations to review the guidance in this advisory as well as visit www.cisa.gov/shields-up for continually updated information on how to protect yourself and your business.”  

CISA was joined in the April 20 advisory by the Federal Bureau of Investigation, the National Security Agency, the Australian Cyber Security Center, the Canadian Center for Cyber Security, New Zealand’s National Cyber Security Center and the United Kingdom’s National Cyber Security Center and National Crime Agency, with contributions from industry members of the Joint Cyber Defense Collaborative.

SMUD, Among Other Utilities, Uses Cloud Seeding To Increase Hydropower

April 23, 2022

by Peter Maloney
APPA News
April 23, 2022

Cloud seeding could become increasingly prevalent in California as utilities there face the twin challenges of drought and reaching the state’s net zero emission goals intended to combat global warming.

The Sacramento Municipal Utility District (SMUD), one of several California utilities with a cloud seeding program, provides an example of how a public power utility uses the technology to augment its hydroelectric resources.

SMUD uses cloud seeding to increase snowfall on the Upper American River Basin where the utility has a series of hydroelectric dams. Increased snowfall leads to more snowpack. When the snow melts and runs off, it increases the amount of water in the utility’s reservoirs, providing greater potential for hydropower generation during high electric demand summer months.

SMUD has been using cloud seeding since 1969 and has found that “on average cloud seeding increases snowpack by roughly three to 10 percent,” Kaitlyn Bednar, SMUD’s hydrographer, said.

“So, for example, in an average year if we get 50 inches of snow water equivalent, cloud seeding can increase that value to 55 inches, translating to a large increase in runoff and power generation,” Bednar said.

“That extra five inches more than pays for itself and provides carbon free power,” Bednar said, noting that the equivalent generation from a natural gas-fired plant would produce “six thousand times as much carbon dioxide as our seeding program.”

SMUD’s current budget for its cloud seeding program is $1.5 million over five years, but the allocations vary from year to year depending on the hydrological conditions and the number of suitable storms.

SMUD’s program focuses on glaciogenic seeding, which laces clouds with microscopic silver iodide particles. Those particles have a similar crystal structure to ice that allows moisture to attach to them and grow heavy enough to precipitate in the form of snow.

SMUD’s seeding season runs from Mid-November through mid-April. In addition, certain criteria are needed for a successful seeding. The clouds need to have a suitable water content, and the temperature has to be cold enough, at least negative 4 degrees Celsius, for moisture to crystalize on the silver iodide particles and then precipitate as snow. “We rarely have a season we don’t cloud seed,” Bednar said. This season, SMUD had 10 seedable events. The goal is to have the utility’s reservoirs completely full by the end of the winter months. “We’ll take all the moisture we can get,” she said.

A third party, RHS Consulting, does the actual seeding for SMUD by flying in or above clouds and setting off silver iodide flares mounted either on the plane’s wing or belly. Each seeding event uses a handful of flares with each flare emitting anywhere between 20 to 200 grams of silver iodide.

The amount of silver iodide released during cloud seeding is not harmful to the environment, Bednar said. It is low in toxicity, insoluble in water, and has low bioavailability. SMUD also tests the areas seeded every five years and to date has found no adverse effects. The utility uses two control areas outside of the project area where cloud seeding does not occur to compare with its seeded area.

Other California public power and investor-owned entities, such as the Northern California Power Agency and Pacific Gas and Electric, also have been engaged in cloud seeding operations for years. And the California Energy Commission (CEC) with the state Department of Water Resources in November hosted a workshop on Cloud Seeding for Precipitation Enhancement.

The CEC, in fact, “may consider future research related to cloud seeding, as described by the proposed EPIC 4 investment plan,” Michael Ward, CEC’s media officer, said via email.

If approved by the state’s Public Utilities Commission, that initiative could support efforts to, “advance strategies for managing California’s hydropower resources for optimal contribution to grid operations and foster development of cost-effective, robust approaches for meeting anticipated needs for zero-carbon, fast-ramping resources,” the CEC said.

Those efforts could include “field research to measure, and ultimately improve, the cost-effectiveness and efficacy of precipitation enhancement through seeding clouds with tiny particles intended to increase the amount of atmospheric water vapor that condenses and falls to the ground as snow or rain,” The CEC said.

APPA DEED Board Awards Grant Funding to Eight Utility Projects

April 22, 2022

by Vanessa Nikolic
APPA News
April 22, 2022

The American Public Power Association’s (APPA) Demonstration of Energy & Efficiency Developments (DEED) program advisory board recently awarded $495,292.43 in funding to eight APPA member utility grant proposals. 

The projects range from evaluating heat pump performance to providing guidance on grid-interactive and efficient building programs. 

Tacoma Power in Washington State received $125,000 in funding for its project focused on Commercial Heat Pump Water Heating (CHPWH) technology. The project will accelerate the deployment of high-performance CHPWH systems to equitably decarbonize and increase efficiency of the multifamily sector. 

The utility’s goal is to create a standard prescriptive program tool which could be used by any utility to run a CHPWH program for multifamily construction with minimal specialized knowledge about CHPWHs.

Wisconsin’s Manitowoc Public Utilities (MPU) earned funding for its renewable fuel conversion study for coal generation. The objective of the project is to evaluate options to secure renewable fuel source(s) sufficient to operate two circulating fluidized bed (CFB) boilers at maximum capacity factors.  

Within a rapidly-changing economic and regulatory landscape, MPU has been actively investigating the ability to successfully transition to burning solely renewable fuel pellets. However, finding raw materials has been a challenge for the utility. 

“MPU has four goals for this project: assess options to secure renewable fuel source(s); explore an in-house pelletization facility; investigate storage options for raw materials and/or pellets; and conduct an analysis of qualified biomass materials under MPU’s current Air Permit,” MPU General Manager Troy Adams said. “This grant will help fund consultant costs to conduct research on renewable biomass pelletizing facilities, storage facilities, raw material analysis, and associated project management expenses.” 

Nebraska’s Lincoln Electric System received funding from the DEED program for its heat pump rating representativeness project, a collaborative effort of utility and industry partners to improve the representativeness of ratings for variable speed heat pumps used in homes and small commercial buildings. This will be accomplished through observation of heat pump performance in a controlled field installation and comparison with corresponding laboratory test results. 

Littleton Electric Light and Water Departments in Massachusetts will use DEED funding to develop independent system operator (ISO) data integrated generator control software using artificial intelligence. The utility will create a web-based software solution and a mobile application to autonomously monitor load forecast and dispatch two peak shaving generators by utilizing real time ISO data. 

This “all in one” software will be customizable to alert utility staff when peak-shaving events should occur or any other aspect important to the utility.

Utah Associated Municipal Power Systems (UAMPS) will apply DEED funding to its Gridware Pilot Program. This Pilot Program will deploy 50 devices on a single line segment in each of the five UAMPS member utilities to demonstrate the capabilities of the Gridware System’s monitoring system.

The Gridware System is a self-powered, low-cost monitoring solution designed to detect distribution grid faults and monitor for equipment degradation. It will provide the five UAMPS member utilities near-real-time visibility into the status of their distribution equipment, the precise dates, times and locations of unique fault classes, and insight into how equipment shifts over various time frames. 

The FREEDM Systems Center at North Carolina State University received funding for its planned demonstration of a portable solar carport with integrated electric vehicle charger. This product will increase solar adoption rates for low- and middle-income households as well as at commercial locations. 

The FREEDM Systems Center will use the funding to purchase two GismoPower carports, install electrical connections at multiple locations on its university campus to demonstrate the technology, and rent a trailer for transporting the units to various public education events throughout the year.

“Our original intent was to lease a unit for perhaps two months of evaluation,” FREEDM Systems Center Director of Industry and Innovation Ken Dulaney said. “But with DEED funding, we plan to purchase two units and host multiple demonstrations across the state.”  

Wisconsin joint action agency WPPI Energy received funding for its utility guidebook on grid-interactive and efficient building (GEB) programs. 

WPPI Energy says GEBs are highly energy efficient and have the potential to reshape buildings into valuable grid resources that can reduce electric system costs and provide customer benefits such as improved comfort and resilience.

The project aims to support small to mid-sized utilities, especially those serving rural communities, in developing their first GEB programs and offerings. WPPI will provide best practices, useful data, and a program development guidebook.

Alabama’s Huntsville Utilities accepted DEED funding for development work on a stochastic model of extreme temperature events in the region, to assist decision making by utility planners.

More-accurate extreme temperature prediction models would help the public power industry as a whole anticipate and respond to spikes in demand levels that often lead to interruption of power supply to customers during extreme temperature events. While outages cannot be completely eradicated, Huntsville’s goal is to plan effectively to ensure a reliable and robust system during extreme events.

In addition to research, development, and demonstration grant funding, the DEED program advisory board awarded $89,000 in funding to scholarship applicants and utilities hosting student interns.

Four lineworker and technical education scholarships were awarded to students referred by the City of Gastonia, North Carolina, Missouri River Energy Services, ElectriCities of North Carolina, Inc., and the City of Parker, South Dakota. 

16 APPA member utilities and joint action agencies were also awarded funds to work alongside students, who will complete important projects and tasks for their utilities’ day-to-day operations and learn more about careers in public power. 

APPA members can learn more about the DEED program and future funding opportunities on our website. The program’s next application cycle will open on May 1, 2022.

Groups Urge FERC To Convene Forum On Internal Network Security Monitoring Proposal

April 20, 2022

by Paul Ciampoli
APPA News Director
April 20, 2022

Before the Federal Energy Regulatory Commission (FERC) moves to develop new or modified mandatory reliability standards related to internal network security monitoring it should first convene a forum that would allow for an exchange of information on the state and availability of existing technology, as well as its cost and efficacy, the American Public Power Association (APPA) and several other trade associations recently said.

APPA was joined in submitting comments in late March at FERC by the Edison Electric Institute, the Electric Power Supply Association, the Large Public Power Council, and the National Rural Electric Cooperative Association (Docket No. RM22-3).

The trade groups submitted the comments in response to a FERC notice of proposed rulemaking (NOPR) issued in January 2022. The NOPR proposes to direct the North American Electric Reliability Corporation (NERC) to develop new or modified mandatory reliability standards requiring internal network security monitoring within a trusted critical infrastructure protection networked environment for high and medium impact bulk electric system (BES) cyber systems. 

The groups said that they agree with the Commission that the implementation of internal network security monitoring in some form may improve the security posture of responsible entities owning or operating high impact BES cyber systems.  

But they also argued that there are significant obstacles to the near-term implementation of this technology. 

APPA and the other groups noted that forms of internal network security monitoring are in their infancy, only now being utilized by a relatively small group of utilities, and the necessary technology is not widely available. 

Moreover, there is a limited group of subject matter experts (SMEs) capable of working with the technology, the groups told FERC.

“Further, related processes associated with the application of the technology (particularly, ‘baselining’ existing network traffic and ‘packet capture’ and analysis) are expected to be challenging, and consensus concerning best practices has not yet been reached,” the groups said in their comments.

Therefore, before issuing any directive, the groups said that FERC should convene a forum in which Commission staff, stakeholders, SMEs and NERC staff can exchange information on the state and availability of existing technology, as well as its cost and efficacy. 

APPA and the other groups said that this discussion could help inform decisions regarding the most effective ways to deploy internal network security monitoring for high-impact BES cyber systems, while also assessing the potential benefits and challenges of applying internal network security monitoring requirements to all medium-impact BES cyber systems, for which internal network security monitoring is likely to have limited utility.

The discussion could also include how to accomplish the security objectives the Commission seeks to achieve using the internal network security monitoring tool given the rapidly evolving market for cybersecurity tools, they went on to say. 

Following this discussion, and assuming the Commission moves ahead with a directive, the groups “ask that it be limited to high-impact BES cyber systems and medium-impact BES cyber systems at control centers for now.”

APPA and the other groups also said that use of internal network security monitoring for low-impact BES cyber systems is unlikely to be practicable, would increase rather than mitigate risk to the BES, and would not be cost-effective from a BES reliability perspective. 

“Accordingly, any directive issued by the Commission should not extend to low-impact assets, or to any subset thereof,” they said.

Department of Energy Moves To Offer Support For At-Risk Nuclear Power Plants

April 20, 2022

by Paul Ciampoli
APPA News Director
April 20, 2022

The U.S. Department of Energy (DOE) on April 19 announced plans to seek applications and sealed bid submissions under the $6 billion Civil Nuclear Credit Program (CNC) to support the continued operation of U.S. nuclear reactors.

The guidance directs owners or operators of nuclear power reactors that are expected to shut down due to economic circumstances on how to apply for funding to avoid premature closure. This includes instructions on formulating and submitting sealed bids for allocation of credits.

“This critical investment, made possible by President Biden’s Bipartisan Infrastructure Law, will help avoid premature retirements of reactors across the country due to financial hardship, preserve thousands of good-paying clean energy jobs to sustain local economies and protect our supply of carbon-free electricity generation,” DOE said.

The Biden-Harris Administration has identified the nation’s current fleet of reactors as a vital resource to achieve net-zero emissions economy-wide by 2050, DOE said, noting that shifting energy markets and other economic factors have resulted in the early closure of 12 commercial reactors across the United States since 2013.

The first CNC award cycle will prioritize reactors that have already announced their intention to cease operations. Future CNC award cycles — including for the second to be launched in the first quarter in FY2023 — will not be limited to nuclear reactors that have publicly announced their intentions to retire.  

For the first CNC award period, DOE is accepting certification applications and bid as a single submission to implement the program on a more rapid timeline.  

Additional information about the CNC Program and the guidance is available here.

Applications for certification and sealed bids for credits for the first CNC award cycle must be submitted no later than 11:59 p.m. Mountain Time on May 19, 2022.