Skip Navigation

Seattle City Light, agencies release clean transportation electrification plan

March 24, 2021

by Peter Maloney
APPA News
March 24, 2021

Seattle City Light, along with other local government agencies, has released a plan to transition the city to a transportation system with lower greenhouse gas emissions and air pollution while increasing electric mobility options and creating a pipeline of clean energy jobs and workforce diversity.

Along with Seattle City Light, the effort was co-led by the Office of Sustainability and Environment, the Seattle Department of Transportation, and the Office of Economic Development.

The Transportation Electrification Blueprint calls for Seattle to take immediate action to plan for the policy changes, infrastructure investments, and partnerships that will be needed to meet the city’s 2030 goals.

Those goals require that 100 percent of shared mobility, such as carshare services, have zero emissions; 90 percent of all personal trips are zero emission; 30 percent of all goods delivery is zero emission; 100 percent of the city’s vehicle fleet is zero emission; the city shall have one or more “Green & Healthy Streets,” areas where streets are closed to cars and goods are delivered by electric vehicles; and electric power infrastructure is in place to enable the transition to electric transportation technologies and vehicles.

“As the plan is implemented City Light will co-convene new internal working groups to coordinate progress throughout the City towards milestones that deliver towards the 2030 goals stated in the plan,” David Logsdon, director of electrification and strategic technology at City Light, said via email.

Specifically, Logsdon said Seattle City Light plans to develop entirely new program offerings for its customers; drive higher customer adoption with incentives, rebates, discounts and promotions; integrate demand-side management components into new program offerings to avoid or reduce the need for traditional transmission and distribution upgrades and optimize the grid and City Light’s resources; and explore opportunities to increase customer access to substantial private capital investments in electric vehicle charging services in the region.

Seattle City Light has already launched time-of-day rate pilot programs for residential and commercial customers and is working with King County Metro to support the adoption of battery-powered buses and with Washington State Ferries and the Port of Seattle to support electrification. Seattle City Light also is implementing several cross-sector pilots and demonstration projects to inform future program designs.

In addition, there already are 16 City Light-owned electric vehicle fast chargers in Seattle City Light’s service territory, and the utility plans to have more than 25 by the end of 2021.

Seattle City Light in 2019 began preparing a Transportation Electrification Strategic Investment Plan outlining its approach to electrification and defining its framework to develop transportation electrification programs. The electrification plan was approved by the Seattle City Council in October 2020.

The plan “lays out the priorities for City Light’s Transportation Electrification efforts, the equity outcomes we intend to achieve via the portfolio, and what initial milestones we will achieve as we invest in the key sectors of public transit; commercial, government, and nonprofit fleets; and personal mobility,” Logsdon said.

The plan builds on the utility’s core mission to achieve a vision of the healthy future that our region depends on—one that is built in concert with our community stakeholders and delivers a grid that is equitable, carbon-neutral, modernized, and future-enabled,” Logsdon said.

APPA recognizes 129 utilities for outstanding safety practices

March 24, 2021

by Paul Ciampoli
APPA News Director
March 24, 2021

One hundred twenty-nine utilities have earned the American Public Power Association’s (APPA) Safety Award of Excellence for safe operating practices in 2020, APPA reported on March 24.

APPA said that 329 utilities from across the country entered the annual safety awards.

Entrants were placed in categories according to their number of worker-hours and ranked based on the most incident-free records during 2020.

Utilities’ incidence rate, used to judge entries, is based on the number of work-related reportable injuries or illnesses and the number of worker-hours during 2020, as defined by the Occupational Safety and Health Administration (OSHA).

“Utilities that receive an APPA Safety Award have demonstrated that they have made the health and safety of their employees a core value,” said Brandon Wylie, Chair of APPA’s Safety Committee and Director of Training & Safety at Electric Cities of Georgia. “Designing and maintaining a top-notch utility safety program takes a lot of hard work and commitment. These utilities and their communities should be very proud.”

The safety awards have been held annually for more than 65 years.

A complete list of winners is available at www.PublicPower.org. 

Ditto says public power access to clean energy tax incentives is ‘low hanging fruit’

March 24, 2021

by Paul Ciampoli
APPA News Director
March 24, 2021

Allowing public power utilities to have access to clean energy tax incentives is “low hanging fruit” in terms of policy-related action that can be taken in the short term in order to incentivize not-for-profit utilities to build their own clean energy generation, said Joy Ditto, President and CEO of the American Public Power Association (APPA) on March 22.

She made her comments while participating in a panel at the Sixth Annual Sustainable Energy Week sponsored by The Economist. The panel discussed how utilities can prepare their business models for the future.

“U.S. electric utilities overall have actually done quite a bit to address climate change in the last fifteen years,” Ditto pointed out. “We have more to do, but we have reduced greenhouse gas emissions thirty percent since 2005,” which she said is attributable to a number of factors.

“One is there has been some form of incentive for clean energy production since the 1992 Energy Policy Act, and more was added in the 2005 act and subsequently, particularly related to clean energy tax incentives” that investor-owned utilities and independent power producers can take advantage of. This helps to explain why there has been “an exponential growth in wind, solar and other clean energy technologies,” Ditto said.

But the not-for-profit electric sector is not able to take direct advantage of those tax incentives. Allowing not-for-profit utilities to have access to these clean energy tax incentives is a “low hanging fruit that we could do in the very short term to incentivize not-for-profit utilities to build their own clean energy generation going forward.”

Meanwhile, Ditto noted that there have been technology improvements in terms of electrification.

She noted that there is “a very major focus” in the U.S. on electric vehicle deployment including among public power utilities that are putting in place programs to incentivize EVs and the infrastructure to support them.

Moreover, public power utilities are hearing from their customers that they want to decarbonize to reduce greenhouse gas emissions and they often want to contribute to that locally, Ditto said.

There has been an influx of community solar programs “particularly within our membership and other ways to improve the clean energy landscape.” Even in the absence of federal legislation “we’ve seen great strides made in this country.”

If federal policy does emerge in the short term under the Biden Administration, APPA believes that Congress should pass an economywide bill to address greenhouse gas emissions, “as well as to focus on the reliability and affordability of electricity as we move forward,” Ditto said.

City of Tallahassee Electric Utility, Heartland Consumers Power District earn R&D excellence award

March 24, 2021

by Paul Ciampoli
APPA News Director
March 24, 2021

Heartland Consumers Power District and the City of Tallahassee Electric Utility in Florida have earned the 2021 Award of Continued Excellence (ACE) from the American Public Power Association’s Demonstration of Energy & Efficiency Developments (DEED) program.

The award recognizes continued commitment to the DEED program and its ideals, including support of research, development and demonstration, improving efficiency, renewable resources, and support of public power. The award was presented during the APPA’s virtual Engineering & Operations Technical Conference this week.

South Dakota-based Heartland has been a DEED member since 1987 and extends its DEED membership to all its utility members and actively promotes DEED programs to their customers.

Heartland has benefited from sponsoring four interns with scholarships, which included projects that ranged from performing customer research to evaluating the effect of economic development incentives to creating a renewable energy calculator.

Heartland won an Energy Innovator Award in 2020 for the renewable energy calculator created as a result of internships and participated in two DEED webinars to share how to use the calculator with others. 

Heartland launched its energy efficiency program, Power Forward, in 2009. As a wholesale power supplier, Heartland provides rebates to residential and commercial customers within customer communities for energy efficiency upgrades. Heartland also provides energy efficiency grants to customers who make energy efficient upgrades to city facilities. Heartland has assisted with the upgrade of more than 2,000 streetlights to LED.

Heartland continues to investigate new methods and systems to improve utility operations and help its utility members to operate more efficiently, such as by funding meter upgrades and investing in forecasting software and other tools to provide cost savings to its utility customers.

Tallahassee joined DEED in 1986 and has been involved in several projects, including a 1994 grant for a thermal mapping project, sponsoring and mentoring three DEED scholarship recipients, and earning two Energy Innovator Awards; one in 2012 for its Neighborhood REACH Program, a collaborative effort to improve livability in traditionally low-income areas, and a second in 2015 for its rebate program for energy and water conservation.  

Over the years the utility has been a partner in federal, state and local R&D initiatives. Most recently, it collaborated with the Department of Energy, its national labs, and Nhu Energy to carry out research critically important to expanding solar and energy storage, known as the Florida Alliance for Accelerating Solar and Storage Technology Readiness. In 2020 they shared lessons learned from that project with the wider public power community on a DEED webinar. 

The City of Tallahassee has committed to numerous sustainability goals and efforts including 100 percent clean energy by 2050, 100 percent clean energy for City Operations by 2035, development of a Clean Energy Integrated Resource Plan, electrification of City and Florida State University buses, and installation of fast charging stations. 

For more information about DEED, visit www.PublicPower.org/DEED-Awards.

NREL study outlines how Los Angeles can meet goal of reliable, 100% renewable electricity

March 24, 2021

by Paul Ciampoli
APPA News Director
March 24, 2021

Meeting Los Angeles’ goal of reliable, 100% renewable electricity by 2045, or even 2035, is achievable with rapid deployment of wind, solar, storage, and other renewable energy technologies this decade, according to a years-long analysis by the U.S. Department of Energy’s National Renewable Energy Laboratory (NREL).

The results of the study were released by Los Angeles Mayor Eric Garcetti, Cynthia McClain-Hill, President, Board of Water and Power Commissioners, Marty Adams, General Manager and Chief Engineer, Los Angeles Department of Water and Power, a number of Los Angeles City Council members and Dr. Martin Keller, Executive Director, NREL, on March 24.

They participated in a virtual press event to release the Los Angeles 100% Renewable Energy Study, known as LA100. Secretary of Energy Jennifer Granholm also made remarks during the event.

Three years ago, “we teamed up with NREL to figure out exactly what it would take” to move even faster towards the city’s 100 percent renewable energy goal, Garcetti said. “Together we’ve run over one hundred million simulations to answer that question,” he said.

“We worked with representatives of local communities, listened to our constituents to prioritize environmental justice and how we do this and to identify multiple pathways to get to one hundred percent and here’s what we found,” Garcetti said.

“First, one hundred percent renewable energy is absolutely achievable,” he said. “In fact, it’s within our reach. It can actually make our system more reliable than it is today and more affordable than it is today for Angelenos of all backgrounds.”

Second, “the more that we electrify other sectors, the more our capital investments will reduce costs and increase our health benefits, lifting a burden that too often falls on low income communities of color.”

And third, “We need to get moving on these investments right now. This study isn’t something in the shelf. It is a greenprint for us to jump into action.”

McClain-Hill said, “that we now have several viable paths to achieve 100 percent renewable energy for Los Angeles and maintain a reliable power grid, even in the most extreme conditions, has clear national implications.”

She added, “it is also a testament to the important role that our storied Department of Water and Power continues to play in manifesting the future of Los Angeles.”

The study “makes it clear that it’s possible to achieve our goal while remaining true to the core principles of reliability, environmental stewardship, environmental justice, resiliency and affordability. That’s critical because our challenge and our charge goes far beyond achieving 100 percent renewable energy,” said McClain-Hill.

“Our charge is to support our community by reducing carbon emissions in ways that build and uplift the quality of life for everyone,” she said. “LA100 shows we can do that by creating jobs and opportunities and engaging our customers in being part of the solution. For the Department of Water and Power, this is our roadmap for building a stronger and more vibrant Los Angeles.”

For his part, Adams said that with the completion of the LA100 study, LADWP “now has the tools and the roadmap to continue on the path to one hundred percent renewables and we plan to start right away by developing a set of next steps and the actions that are called for are actions that were in all the scenarios of the study.”

Details on study

“The combined effects of energy efficiency, electrification, and demand response yield large benefits to greenhouse gas reductions and public health and help cost-effectively manage the clean energy transition,” NREL noted in a news release related to the study.

NREL is the U.S. Department of Energy’s primary national laboratory for renewable energy and energy efficiency research and development.

In addition to identifying pathways for Los Angeles, the study illuminates the potential for other municipalities, large and small, to embark on similar analysis and contribute toward national efforts to decarbonize the U.S. power sector by 2035.

NREL said that the study provides insights into how LADWP can meet clean energy targets established by Garcetti and the Los Angeles City Council in 2016 and 2017. LADWP currently generates more than half of its electricity from renewable and zero carbon resources.

The  analysis stops short of making specific policy or project recommendations but identifies “no-regrets” investments the city can consider now to reap potential benefits to reliability and greenhouse gas reductions in the coming decade: namely, deployment of new solar, wind, batteries, and transmission within and outside of the city, paired with upgrades to the local distribution system and smart-grid operational practices that make more efficient use of these investments, NREL noted.

“Unlike other forward-looking studies of high-renewable power systems, LA100 uniquely considered reliability as a fundamental requirement for the future grid,” NREL said.

“Reliability of the grid is paramount — especially in a future when more consumer products like cars are electrified. Our models subjected the grid to multiple stresses — from higher temperatures due to climate change, to wildfire risks that could take out transmission lines for weeks or even months at time,” said Jaquelin Cochran, manager of NREL’s grid systems analysis group and principal investigator of the LA100 study.

Quarterly meetings over three years with the study’s Los Angeles-based Advisory Group, comprising members representing neighborhoods, customers, labor, business, environmental, academic organizations, and institutions, tailored the research to constituents’ needs and concerns, “pioneering a new, more holistic approach to energy analysis that centers the community in the conversation,” NREL said.

The analysis showed multiple paths exist for the city to reach its goal. Each scenario follows a similar trajectory up to 80%–90% renewable generation. Wind and solar resources, enabled by storage, provide the majority of energy required to meet future load: 73%–92% depending on the scenario.

Where the pathways diverge is in how to cost effectively and reliably meet the remaining energy demand that cannot be easily served by wind, solar, and batteries, NREL noted.

For the last 10% (going from 90% renewable electricity to 100%), all scenarios rely on some type of renewably fueled combustion turbine built inside the city that can come online within minutes and run for several days when needed.

Such technology is still used infrequently, like peaking plants today, NREL said. Because there are few commercially available, near-term options for this type of grid service, meeting the challenge of the final stretch toward 100% “highlights future research directions at the local scale and beyond — such as developing the infrastructure required to produce and store hydrogen, or multi-day demand response programs that could provide a lower-cost alternative,” NREL said.

It noted that LA100 establishes a methodology that could inform other municipalities “similarly interested in a clean, equitable, and reliable energy future.”

Along with expertise from partners at the University of Southern California, Colorado State University, and Kearns & West, the study relied on NREL’s objective, holistic capabilities to analyze potential pathways the community can take to achieve Los Angeles’ goal, NREL said.

There is no single model that can perform a study of this scope, so the analysis combined dozens of them — spanning detailed electricity demand modeling, power system investments and operations, distribution grid modeling, economic impact analysis, and life cycle greenhouse gas analysis, among others.

Using NREL’s supercomputer, experts ran more than 100 million ultrahigh-resolution simulations to evaluate a range of future scenarios for how LADWP’s power system could evolve while maintaining its current high degree of reliability.

The study found that decarbonizing the power sector through renewable deployment helps create the enabling conditions for electrifying the buildings and transportation sectors.

“Together, these changes yield large reductions in carbon emissions and air pollutants, which lead to health and other benefits for disadvantaged and non-disadvantaged communities alike, compared with today. However, ensuring prioritization of environmental justice — per the Los Angeles City Council motivations driving the study — would require intentionally designed decision-making processes and policies/programs that prioritize disadvantaged communities,” NREL said.

Chelan PUD outlines potential new approach to energy sales contracts

March 23, 2021

by APPA News
March 23, 2021

Washington State’s Chelan PUD is evaluating its strategies to sell carbon-free, surplus power as long-term energy output contracts expire over the next decade.

Chelan PUD General Manager Steve Wright on March 15 presented a plan that would support more economic growth locally, while also allowing the PUD to capitalize on favorable market conditions, the PUD said.

“With the current long-term market, we’re seeing the opportunity to create revenue that could lead to rate stability for our customer-owners,” Wright said. “We believe the market sees value now in renewable hydropower that can support carbon emission reduction goals.”

Chelan PUD said that its revenue from wholesale purchasers is the reason its customer-owners enjoy some of the lowest rates in the nation, noting that it produces more than enough power to meet local demand for electricity.

 “We are heavily dependent on these revenues to maintain the low rates in Chelan County,” Wright said.

Chelan PUD currently sells the energy it produces based on a formula roughly calculated as 50-30-20:

Wright proposed that commissioners consider a new formula that retains the basic structure for wholesale transactions while creating room for local loads to grow over time.

Specifically, 40-50% would be sold as long-term slice contracts based on cost of operations and the value of hydroelectricity. These contracts could serve customers outside Chelan County, or new large-load customers in Chelan County.

Under the proposal, 20-30% of energy would be sold in fixed-price, market-based contracts over 5 to 10 years. This amount may be reduced over time to serve unanticipated local load growth.

In addition, 20-30% would be used to serve local customer-owners as local load growth occurs.

Chelan PUD Commissioners will consider the proposal over the next month.

Snohomish PUD is launching cloud-based residential DSM pilot

March 23, 2021

by Peter Maloney
APPA News
March 23, 2021

Washington State’s Snohomish County Public Utility District (SnoPUD), with its partner Virtual Peaker Inc., plans to roll out a cloud-based energy management system for its customers in the coming months.

SnoPUD expects to begin the FlexEnergy pilot program this spring and run it for two consecutive winters, concluding in spring 2023.

“The main goal of the program is to study how customers respond to a variety of incentives,” SnoPUD spokesman Aaron Swaney said.

The program is being launched in advance of the utility’s plans to install advanced metering infrastructure (AMI) in 2023. SnoPUD hopes the FlexEnergy program will provide valuable data so that when the new metering system is installed, the PUD will have a better idea of what kind of incentives to offer to help shave peak loads.

SnoPUD, like other utilities in the Pacific Northwest, faces its highest peak demand during the cold winter months. That creates a challenge when it comes to keeping its fuel mix clean, Swaney said. SnoPUD’s fuel mix is now about 98 percent clean and averaged 95 percent over the last five years, he said.

Under Washington State’s Clean Energy Transformation Act, utilities must eliminate coal-fired generation by 2025 – SnoPUD has already reached that goal – must be greenhouse gas neutral by 2030, and by 2045 all utilities must generate 100% of their power from renewable or zero-carbon resources.

When launched, the Flex Energy program will be open to nearly all SnoPUD’s customers and, even though the program will make use of smart technologies, owning a smart device is not a requirement of enrollment into the program.

The program will test out three different types of incentive mechanisms, all aimed at shifting or curbing customers’ peak energy use. Two rely on rate design to influence customers’ energy usage. The third is behavioral and operates like a demand response program, offering incentive payments to customers for lowering their energy use during certain times. SnoPUD has not yet determined what kind of incentives it will offer.

The rate design mechanisms of the FlexEnergy program are a fixed rate option and a fixed peak pricing option.

The first will offer cheaper pricing during set times. The fixed peak pricing option will involve sending alerts to notify customers of opportunities to save money by reducing their energy use during expected peak periods. SnoPUD estimates there could be about six of those types of events per year, Swaney said.

Virtual Peaker will serve as the intermediary between SnoPUD and its customers. The PUD said it plans to leverage Virtual Peaker’s Distributed Energy Resources Management System (DERMS), which will be used to enable customer and communicating device enrollment, event scheduling and management, and pilot analytics.

Virtual Peaker, based in Louisville, Kentucky, is a cloud-based energy management platform that uses internet-of-things technology to connect household smart devices to allow utilities to run residential demand response programs.

Public power utilities honored with APPA award for reliable electric operations

March 23, 2021

by Paul Ciampoli
APPA News Director
March 23, 2021

One hundred eight of the nation’s more than 2,000 public power utilities earned the Reliable Public Power Provider (RP3) designation from the American Public Power Association (APPA) for providing reliable and safe electric service.

The designation, which lasts for three years, recognizes public power utilities that demonstrate proficiency in four key disciplines: reliability, safety, workforce development and system improvement.

Criteria include sound business practices and a utility-wide commitment to safe and reliable delivery of electricity.

With 108 utilities earning the designation this year a total of 270 of the more than 2,000 public power utilities nation-wide hold the RP3 designation.

“I think over the last year or so, we’ve seen the vital importance of running a reliable and safe utility,” says Aaron Haderle, Chair of APPA’s RP3 Review Panel and Manager of Transmission and Distribution Operations at ‎Kissimmee Utility Authority, Florida.

“The utilities receiving the RP3 designation have proven that they are committed to running a top-notch public power utility by implementing industry best practices,” he said.

This is the sixteenth year that RP3 recognition has been offered.

A full list of designees is available at www.PublicPower.org.

FERC affirms small utility opt-in element of DER aggregation order backed by APPA

March 22, 2021

by Paul Ciampoli
APPA News Director
March 22, 2021

The Federal Energy Regulatory Commission recently issued an order affirming the small utility opt-in feature supported by the American Public Power Association of a final rule that allows for distributed energy resource (DER) aggregators to compete in regional organized wholesale electric markets.

At the same time,  contrary to APPA’s position, FERC found that demand response resources participating in aggregations with other types of DERs are not subject to the state and local regulator opt-out/opt-in framework that FERC adopted for demand response aggregations in Order Nos. 719 and 719-A.

At its monthly open meeting, FERC issued an order (2222-A) that responded to requests for rehearing and clarification of FERC Order No. 2222, which addresses the participation of distributed energy resource (DER) aggregations in markets administered by Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs). FERC approved Order 2222 in September 2020.

In November 2020, APPA and the National Rural Electric Cooperative Association urged FERC to reject objections to a small utility “opt in” mechanism that the Commission adopted in Order No. 2222, a final rule that allows for distributed energy resource (DER) aggregators to compete in regional organized wholesale electric markets. In addition, APPA and NRECA said that FERC should not carve out an exception to the small utility opt-in for energy efficiency resources.

In Order No. 2222-A, FERC considered requests for rehearing and clarification of FERC Order No. 2222. 

Among the important features of Order No. 2222, FERC provided an “opt-in” mechanism for small distribution utilities — including most public power utilities. 

Specifically, the Commission determined that customers of utilities that distributed 4 million MWh or less in the previous fiscal year may not participate in distributed energy resource aggregations unless the relevant electric retail regulatory authority affirmatively allows such customers to participate in distributed energy resource aggregations. The small utility opt-in mechanism was supported by APPA, and FERC affirmed it in Order No. 2222-A. 

Order No. 2222-A also addresses the participation of demand response resources in DER aggregations. 

Under regulations adopted in 2008-2009 in FERC Order Nos. 719 and 719-A, an ISO or RTO may not accept bids from a demand response aggregator of retail customers served by utilities that distributed more than 4 million MWh in the previous year if the relevant electric retail regulatory authority (RERRA) affirmatively prohibits wholesale market participation (opt-out). 

In the case of customers served by utilities that distribute 4 million MWhs or less, the ISO/RTO may not accept bids from an aggregator unless the RERRA affirmatively permits it (opt-in). 

In Order No. 2222, FERC said that demand response resources seeking to participate in DER aggregations would still be subject to the opt-out/opt-in regulations.  FERC modifies this ruling in Order No. 2222-A, concluding that the opt-out/opt-in rules ordinarily applicable to demand response resources would apply only “to aggregations made up solely of resources that participate as demand response resources, consistent with our regulations.” 

The opt-out/opt-in rules will not apply “to demand response resources that participate in heterogeneous distributed energy resource aggregations—i.e., those that are made up of different types of resources including demand response as opposed to those made up solely of demand response.”

Order No. 2222-A clarifies a number of other aspects of FERC’s DER aggregation rules, including jurisdiction over interconnection of PURPA QFs and various implementation issues.

The revisions take effect 60 days after publication in the Federal Register.

Danly, Christie offer dissents

Commissioner James Danly and Commissioner Mark Christie offered dissents to the order.

For his part, Christie said FERC’s majority was doubling down “on siding with commercial interests seeking entry into the RTO/ISO markets and against the states and other authorities whose job is to defend the public, not private, interest. By doing so, the majority also sides against the consumers who for years to come will almost surely pay billions of dollars for grid expenditures likely to be rate-based in the name of ‘Order 2222 compliance.’” (Christie discusses Order No. 2222-A, among other topics, in the most recent episode of APPA’s Public Power Now podcast).

Instead of making the states, municipal and public power authorities and electric cooperatives “truly equal partners in managing the timing and conditions of deployment of behind-the-meter DERs in ways that are sensitive to local needs and challenges — both technical and economic — today’s order denies them any meaningful control by prohibiting any opt-out or opt-in options except in relatively tiny circumstances,” wrote Christie.

“This order — and its predecessor — intentionally seize from the states and other authorities their historic authority to balance the competing interests of deploying new technologies while maintaining grid reliability and protecting consumers from unaffordable costs,” he said.

A rapid concentration of behind-the-meter aggregated DERs at various locations on the local grid “will inevitably require costly upgrades to a distribution grid that has largely been engineered to deliver power from the substation to end-user retail customers. Meeting the technological challenges of this re-engineering of the local grid are not insuperable but there are substantial costs and we all know these costs will ultimately be imposed on retail consumers. States, public power authorities and cooperatives are far better positioned to manage these costs and competing interests in their own areas of responsibility than FERC,” Christie said.

Moreover, he argued that Order No. 2222-A is not “cooperative federalism,” but rather its opposite. “It undermines the overarching policy framework that Congress incorporated into the Federal Power Act decades ago: federal regulation of wholesale rates and the bulk power system; state regulation of retail rates and the local distribution grid,” he wrote in the dissent.

“Any argument that allowing state policies to determine the entry of aggregated DERS into capacity or other markets will result in a ‘checkerboard’ or ‘patchwork’ of different policies, is an argument against state authority itself. The existence of fifty states by definition means a patchwork of 50 state retail regulatory structures, but that goes with the territory in our constitutional structure and is entirely consistent with the Federal Power Act’s basic division of federal and state authority. This panoply of diverse state policies is exactly what Justice Brandeis celebrated when he recognized states as laboratories of democracy.”

While encouraging the development of DERs “is a good thing, eviscerating the states’ historic authority in the name of encouraging DER development is not,” Christie said.

“On the contrary, it is the states and other local authorities that are far better positioned than FERC to manage successfully the development and deployment of DERs in ways that serve reliability needs, that protect consumers from inflated costs, and that are far more sustainable in the long run.”

For his part, Danly said he was “dissenting from this order on rehearing of Order No. 2222, the Commission’s distributed energy resource aggregations mandate, for the same reasons that I dissented from the original. It oversteps the reasonable exercise of the Commission’s authority at the expense of the states.”

Danly acknowledged the recent cases upon which the Commission relies to exercise its jurisdiction in the order, “but these cases concerned whether the Commission possesses claimed authority, reserving the question of whether the Commission has discretion to exercise it. Clearly the Commission has the power, exclusive jurisdiction or not, to establish a state opt-out.”

He would “decline to exercise our jurisdiction to obstruct the states from asserting authority over distributed energy resource aggregations. The Commission owes fidelity to the clear division of jurisdiction between the federal government and the states, a due regard for federalism that is embedded in the very structure of the Federal Power Act. This order unnecessarily invades an area best left to the states, burdening them with another of our Good Ideas, the details of which we leave them to figure out, and the burdens of which we leave to them to bear.”

FERC issues NOI

In related action, FERC on March 18 also issued a notice of inquiry on the potential impacts of eliminating the ability of states to prevent demand response resources from participating in organized wholesale markets.

FERC is asking whether the circumstances relevant to this demand response opt-out have changed since the opt-out was established in Order Nos. 719 and 719-A, and what are the potential benefits or burdens of removing it.

Comments are due 90 days after publication in the Federal Register, with reply comments due 30 days after that.

Glick     

In comments at the Commission meeting, FERC Chairman Richard Glick praised Order No. 2222-A as a further improvement to the rules adopted in Order No. 2222. 

“By allowing demand response providers located in states that have opted out of Order No. 719 to participate as part of a DER aggregation as long as other DER technologies are included in the aggregation, the Commission is further expanding our opportunities for DER aggregation in our wholesale markets,” he said at the meeting.

With respect to the NOI, “a lot has changed” since Order No. 719 was first issued “and I think it is prudent for us to reconsider whether the opt out remains appropriate,” he said.

“I recognize that certain state regulators have been frustrated with the” approaches FERC has taken over the last several years, specifically in Order No. 841, which dealt with energy storage, and Order No. 2222.

“With regards to the potential participation of behind-the-meter resources in RTO and ISO wholesale markets, it is not a simple matter,” Glick said. “FERC has the duty pursuant to the Federal Power Act to eliminate undue discrimination in terms of access to jurisdictional wholesale markets. The states have a legitimate interest in ensuring the reliability of their distribution systems.”

Some are concerned that the participation of behind-the-meter resources in wholesale markets will make it more difficult for the states to address distribution reliability, Glick said.

In his view, the states still retain important tools such as jurisdiction over DER interconnections and the ability to condition DER participation in retail markets in a manner that ensures DER participation in wholesale markets won’t impair reliability.

“But we need to continue this dialogue with our state colleagues, which I am very much committed to doing,” he said. “This Commission over the last several years has run roughshod over the states’ responsibilities over resource decision making all in an effort to raise prices in mandatory capacity markets.”

In his comments at the meeting, Commissioner Christie said that if he were to describe the order in one word it would be hubris. “It’s based on the belief that the members of this Commission know better how to manage the complicated issues of timing, grid reliability and the costs of behind-the-meter DER deployment than all the state regulators in all the fifty states who, by the way, are tasked with defending the public interest just like we are here at FERC. Better than all the dedicated people who run the public power and the municipal power authorities. Better than all the dedicated people who run the electric coops do,” he said.

“And it’s based on the false belief that state regulators, public power authorities, municipal power authorities and coops are opposed to behind-the-meter DER deployment, and so these people can’t be trusted to manage the deployment of DER deployment and I know that’s just not true,” Christie said.

“States have been dealing with these issues for years and taking the lead in DER deployment. So have the munis, so have the public power authorities, so have the coops,” he said.

“Consumers are going to pay a lot for this,” Christie said.

Investor-owned utilities are “going to seek to put billions of dollars into rate base and the argument to the state regulators will be, oh, we have to do this to comply with FERC’s Order 2222 and so you state regulators have to approve it. And as a former state regulator who sat on a lot of rate cases, I’ve heard this argument before and it’s very hard – frankly it’s almost impossible – for a state regulator to deny cost recovery when the utility says we have to spend this money to comply with federal regulations. That’s a very hard argument to rebut and so the costs of this are going to be substantial.”

Prior to becoming a FERC Commissioner, Christie served as a Chairman and Commissioner with the Virginia State Corporation Commission.

FERC directs revisions to market power mitigation in PJM capacity market

March 22, 2021

by Paul Ciampoli
APPA News Director
March 22, 2021

The Federal Energy Regulatory Commission on March 18 told the PJM Interconnection, its market monitor and market participants in the region that the existing default market seller offer cap fails to allow for adequate review of potential market power concerns in the capacity market, because it  is based on an unreasonable expectation of the number of performance assessment intervals PJM will experience in a given delivery year. 

The Commission directed parties to propose alternative methods for market power review and mitigation in the capacity market.

FERC’s order stems from two complaints filed in 2019 by the market monitor and consumer advocate groups in the region, alleging that PJM’s calculation of the default market seller offer cap in the capacity market is unjust and unreasonable.

The complaints were supported by the American Public Power Association.

The default market seller offer cap originally was established as part of PJM’s 2015 capacity performance construct, in response to the 2014 polar vortex.

FERC found PJM’s existing rate unjust and unreasonable, but said it needs additional evidence to set the appropriate replacement rate and therefore ordered additional briefing.

FERC’s action on the complaints will not interfere with PJM’s upcoming May 2021 capacity auction for delivery year 2022-2023, FERC said. The auction should take place as scheduled under current rules. 

FERC noted that it will continue to exercise its oversight of the upcoming auction and any anticompetitive conduct observed may be referred to the Office of Enforcement.

The order is available here.