Skip Navigation

FERC Considers Reforms To Transmission Planning And Cost Allocation

July 21, 2021

by Paul Ciampoli
APPA News Director
July 21, 2021

The Federal Energy Regulatory Commission (FERC) on July 15 issued an Advanced Notice of Proposed Rulemaking (ANOPR) to reform its transmission planning, cost allocation, and generator interconnection rules.

At a high level, the potential reforms in the ANOPR “consider the need for more holistic transmission planning and cost allocation and generator interconnection processes, to plan the grid for the future, and to do so in a way that results in rates that are just and reasonable,” FERC staff noted in a presentation made at the Commission’s monthly open meeting.

Comments on the ANOPR will be due 75 days from its publication in the Federal Register, with reply comments due 30 days later (Docket No. RM21-17-000).

The ANOPR seeks comment on potential reforms in three specific areas: (1) reforms for longer-term regional transmission planning and cost-allocation processes that take into account more holistic planning, including planning for anticipated future generation, (2) rethinking cost responsibility for regional transmission facilities and interconnection-related network upgrades, and (3) enhanced transmission oversight over how new transmission facilities are identified and paid for. The ANOPR includes numerous questions for industry comment in connection with each of these three, interrelated topic areas.

Examples of questions raised in the ANOPR include, among others: 

The ANOPR also seeks comment regarding whether the current approach to oversight of transmission investment adequately protects customers, and, if customers are not adequately protected from excessive costs, which potential reforms may be required and are legally permissible to ensure just and reasonable rates.

It also seeks comment on several other important related topics including whether FERC action on various matters would be consistent with its legal authority, consideration of consumer protection, coordination between individual transmission provider planning processes and regional transmission planning processes, and interregional planning.

Glick, Clements Issue Joint Concurrence

In a joint concurrence, FERC Chairman Richard Glick and Commissioner Allison Clements noted that the nation’s generation resource mix is changing rapidly. “Due to a myriad of factors — including improving economics, customer and corporate demand for clean energy, public utility commitments and integrated resource plans, as well as federal, state, and local public policies — renewable resources in particular are coming online at an unprecedented rate.”

As a result, the transmission needs of the electricity grid of the future are going to look very different than those of the electricity grid of the past, Glick and Clements said.

They expressed concern that the current approach to transmission planning and cost allocation cannot meet those future transmission needs in a manner that is just and reasonable and not unduly discriminatory or preferential. 

“In particular, we believe that the status quo approach to planning and allocating the costs of transmission facilities may lead to an inefficient, piecemeal expansion of the transmission grid that would ultimately be far more expensive for customers than a more forward-looking, holistic approach that proactively plans for the transmission needs of the changing resource mix. A myopic transmission development process that leaves customers paying more than necessary to meet their transmission needs is not just and reasonable,” they wrote.

In that regard, Glick and Clements are pleased to see the Commission “taking a consensus first step toward updating its rules and regulations to ensure that we are meeting the nation’s evolving transmission needs in a cost-effective and efficient fashion.” 

Ensuring that transmission rates remain just and reasonable “will require further action, including reforms to interregional transmission planning and cost allocation, as well as other reforms to our regional transmission planning and cost allocation and generator interconnection processes beyond those contemplated herein. Nevertheless, we believe that today’s unanimous Commission action represents a solid foundation for an expeditious inquiry into how we can regulate to achieve the transmission needs of our changing electricity system in a manner consistent with our statutory obligations under the Federal Power Act.”

Glick and Clements also said that they are concerned that, in light of evolving transmission needs, the current regional transmission planning and cost allocation and generator interconnection processes may no longer ensure just and reasonable rates for transmission service.

“In particular, we are concerned that existing regional transmission planning processes may be siloed, fragmented, and not sufficiently forward-looking, such that transmission facilities are being developed through a piecemeal approach that is unlikely to produce the type of transmission solutions that could more efficiently and cost-effectively meet the needs of the changing resource mix,” they wrote.

Glick and Clements argued that regional transmission planning processes “generally do little to proactively plan for the resource mix of the future, including both commercially established resources, such as onshore wind and solar, as well as emerging ones, such as offshore wind. We are also concerned that current regional transmission planning processes are not sufficiently integrated with the generator interconnection processes, and are overwhelmingly focused on relatively near-term transmission needs, and that attempting to meet the needs of the changing resource mix through such a short-term lens will lead to inefficient transmission investments.  As a result, under the status quo, customers could end up paying far more to meet their transmission needs than they would under a more forward-looking approach that identifies the more efficient or cost-effective investments in light of the changing resource mix.”

They are also concerned that the current approach to transmission planning and cost allocation is failing to adequately identify the benefits and allocate the costs of new transmission infrastructure. 

“In addition, we are concerned that, largely due to the potential shortcomings with the current regional transmission planning and cost allocation processes, transmission infrastructure is increasingly being developed through the generator interconnection process. That means that infrastructure with potentially significant benefits for a broad range of entities may be developed through a process that focuses exclusively on the needs of a comparatively small number of interconnection customers—a dynamic that is almost sure to result in comparatively inefficient investment decisions.” 

The participant funding approach to financing interconnection-related network upgrades will often mean that the interconnection customer(s) alone must pay for all—or the vast majority—of the costs of that transmission infrastructure, even where it provides significant benefits to other entities, Glick and Clements said. “That, in turn, may cause those interconnection customers to withdraw projects from the queue, causing considerable uncertainty and delay, and may mean that net beneficial transmission infrastructure is never developed due to a misalignment in how that infrastructure would be paid for.”

Glick and Clements also said that they are concerned that the Commission’s current approach to overseeing transmission investment may not adequately protect consumers. “While transmission infrastructure can provide a broad spectrum of benefits, it is itself a significant investment that represents a major component of customers’ electric bills.  The Commission must vigorously oversee the rules governing how transmission projects are planned and paid for if we are to satisfy our responsibility to protect customers from excessive rates and charges. The potential bases for invigorating our oversight of transmission spending contemplated in today’s order have the potential to go a long way toward ensuring that we fulfill that function,” they wrote.

Christie, Danly issue separate concurrences

FERC Commissioners Mark Christie and James Danly issued separate concurrences.

Danly said that the ANOPR poses several questions “where the answer is ‘no.’ Many of the contemplated proposals would exceed or cede our jurisdictional authority, violate cost causation principles, create stifling layers of oversight and ‘coordination,’ trample transmission owners’ rights, force neighboring states’ ratepayers to shoulder the costs of other states’ public policy choices, treat renewables as a new favored class of generation with line-jumping privileges, and perhaps inadvertently lead to much less transmission being built and at much greater all-in cost to ratepayers.”

Danly, who said that there are obviously problems with the existing transmission regime, hopes that commenters “will supply us with a full record on each issue raised in the ANOPR: whether and why the existing rule works or not, and whether and why the possible reform may work or not. With every proposed change, I specifically solicit comments on two subjects. First: is the contemplated reform a proper exercise of the Commission’s authority, i.e., is it within our jurisdiction? That is always the threshold question before we turn to policy. Second: what will be the ultimate effect on ratepayers? I fear that in the enthusiasm to build transmission, many may tout the benefits of new transmission while overlooking the costs that will eventually be borne by ratepayers. No proposed policy, however worthy, can evade our statutory duty to ensure that rates are just and reasonable.”

For his part, Christie said that he concurred with the ANOPR “because approximately ten years after the Commission issued Order No. 1000, it is appropriate to review the implementation of that order, assess the successes and problems that have become evident over the past decade, and consider reforms and revisions to existing regulations governing regional transmission planning and cost allocation. This consideration of potential reforms is especially timely as the transmission system faces the challenge of maintaining reliability through the changing generation mix and efforts to reduce carbon emissions.”

At the same time, he said that his concurrence to issue the ANOPR does not represent an endorsement at this point in the process of any one or more of the proposals included in the order. 

Christie said the ANOPR “contains a number of good proposals, some potentially good proposals (depending on how they are fleshed out), and frankly, some proposals that are not — and may never be — ready for prime time, or could potentially cause massive increases in consumers’ bills for little to no commensurate benefit or inappropriately expand the role of federal regulation over local utility regulation. Given the early stage of this process, however, I agree it is worthwhile to submit a broad range of proposals to the public for comment in the hope that the final result will be a more reliable, more efficient, and more cost-effective transmission system.”

Department of Energy Accelerates Release Of Cybersecurity Capability Maturity Model Update

July 21, 2021

by Paul Ciampoli
APPA News Director
July 21, 2021

The Department of Energy (DOE) this week released an update to the Cybersecurity Capability Maturity Model (C2M2), which was originally scheduled for release at the end of this year.

The American Public Power Association (APPA), along with a number of cyber experts from public power, rural electric cooperatives and investor-owned utilities, have been working with the DOE’s Office of Cybersecurity, Energy Security, and Emergency Response (CESER) over the past two years to update the C2M2. 

Nathan Mitchell, Senior Director of Operations Programs at APPA, noted that this industry-led effort to update this voluntary cybersecurity model is in response to the continued attacks on information technology/operational technology cyber systems. “APPA wants to thank the public power representatives that have helped in this revision process,” he said.

“APPA recommends that public power utilities review the C2M2 V2.0, conduct a self-assessment of your cybersecurity program, and mitigate any risks you may find to prepare for and prevent cyber-attacks,” he said.

The new model was scheduled to be released at the end of 2021, but DOE-CESER and industry representatives agreed that accelerating the release of the new guidance and recommendations would help the electricity industry assess their cyber systems now.  

APPA also recommends that public power utility managers look at the Axio 360 for Public Power platform to help in tracking the progress of cybersecurity capability at their utility.  The C2M2 V2.0 is available on the Axio platform. Users can reach out to support@axio.com with any questions.

The testing and validation of the model is ongoing and DOE welcomes any feedback based on experience using the updated model.  Email DOE at C2M2@hq.doe.gov to share feedback and lessons learned.  If changes are needed to clarify any C2M2 V2.0 model recommendations, an update will be issued at the end of the year. 

The C2M2 V2.0 is available for download at: https://www.energy.gov/ceser/cybersecurity-capability-maturity-model-c2m2

Any questions or comments on cybersecurity can be directed to APPA’s Cyber Defense Community email address at: OTCyberDefense@publicpower.org

Rep. DeGette Details Net-Zero Emissions Bill That Includes Elements Supported By APPA

July 20, 2021

by Paul Ciampoli
APPA News Director
July 20, 2021

Rep. Diana DeGette, D-Colo., recently detailed legislation intended to drive the innovation of new technologies that she said will be needed to reduce U.S. power sector emissions to net zero. The bill incorporates several suggestions made by the American Public Power Association (APPA) and its members.

DeGette offered details on the Clean Energy Innovation and Deployment Act in remarks made at APPA’s National Conference Virtual Event on July 14, 2021.

The legislation is comprised of five parts.

The first part focuses on clean energy innovation and uses a range of measures to “bring the many promising clean energy technologies that we have out there to the point of commercial availability as soon as possible,” DeGette told APPA National Conference Virtual Event attendees.

The second part of the bill creates tax incentives for entities that install zero emission electricity generation. Included in this section of the bill are provisions that give extra incentives to companies that deploy the technology sooner and that deploy them in parts of the country where they’ll have the greatest impact, she said. These tax incentives would be available as direct payments including to public power utilities, DeGette said.

The third part of the bill seeks to protect low-income ratepayers by reauthorizing the Low Income Home Energy Assistance Program (LIHEAP) and increasing funding for the weatherization assistance program.

The fourth section “is designed to provide support to the workers who would be displaced by the shift in energy policy,” DeGette said.

The fifth section of the bill would create the nation’s first federal clean energy standard — a zero-emission electricity standard — which is intended to be completely technology neutral. “This technology neutral approach is one of the reasons why this bill is so unique. By taking such an approach we’re able to prioritize climate action rather than any particular electricity generating technology,” DeGette said.

Under the bill, credits for zero emission electricity generation would be issued by the Environmental Protection Agency (EPA) to generators that would in turn sell the credits to retail electricity suppliers. Those suppliers would then submit the credits back to the EPA. 

The bill does not place limits on which generators a retail electricity supplier can get credits from. She noted for example that a public power utility in Missouri could buy credits from a generator in Hawaii “or wherever you can get them for the cheapest price.”

DeGette said that creating a national marketplace for credits like this “will help drive down the price and the overall cost of the program and it also helps fuel competition by investors and inventors who will then have an incentive to develop and implement the most cost effective clean energy technology possible.”

In crafting the bill, the lawmaker recognized the fact that many public power utilities don’t have environmental compliance programs, DeGette said. Therefore, she included a provision in the bill that allows a public power utility to enter into an agreement with any generator to manage the credit submission requirements for them.

“Another key part of the bill is the mechanism that’s put in place to automatically tie the nationwide clean energy standard to the availability of new technologies,” DeGette said. “Under the standard, for example, if we still haven’t developed the technology needed to generate affordable, reliable one hundred percent zero emission electricity by 2050, the bill will use offsets to ensure that we’re still able to achieve net zero emissions.”

On the other hand, “if future technological breakthroughs make it possible for us to move much faster and at a lower cost than we think possible today, the requirements that will be put in place under the bill will also advance, moving the target date to achieve nationwide, one hundred percent zero emission electricity up to and as soon as 2030.”

In order to further protect public power utilities and their customers from a high cost of compliance, “we went a step further when we drafted the bill and added three separate off ramps – one that puts a cap on the cost of credits, a second that provides you an exemption if the required technology isn’t available and a third that provides an exemption for generating electricity from a unit that’s deemed essential for maintaining reliability,” she said.      

DeGette serves on two committees — the House Committee on Energy and Commerce and the House Committee on Natural Resources. She also serves on several subcommittees and is chair of the Oversight and Investigations panel of the House Committee on Energy and Commerce.  

Ditto Outlines Opposition To Using Legislation To Encourage Public Facility Privatization

July 20, 2021

by Paul Ciampoli
APPA News Director
July 20, 2021

American Public Power Association (APPA) President and CEO Joy Ditto on July 14 wrote to President Joseph Biden in opposition to using infrastructure funding legislation to encourage the privatization of public facilities.

“In general, privatizing public projects reduces local control, increases costs by providing a higher rate of return for investors, and, contrary to the perception, does nothing to increase project funding, which ultimately comes from residents of the community,” wrote Ditto in the letter. “As a result, while communities should consider all alternatives when assessing their infrastructure, the federal government should not tip the scales of those decisions by favoring privatization,” she said.

Ditto highlighted her concern over “the troubling bipartisan, bicameral interest in the federal government paying states, counties, and cities to sell their roads, bridges, and utilities to raise short-term cash for other infrastructure repairs. This so-called ‘asset recycling’ arguably failed in Australia – just four out of 16 Australian states and territories participated, and the program ended with unspent funding – and has failed to take off elsewhere.”

Ditto said in the letter that a comprehensive review of objective, data-based analyses “shows that up-front costs of privatized projects tend to be higher for several reasons, including higher transaction costs and higher financing costs. These analyses also find that real value of privatization is the extent to which the seller can shift risks onto the buyer, and that shifting those risks — which can reduce later profits — can be quite difficult to do.”

Lackluster results “may be driving declining public interest in privatization of infrastructure globally,” she wrote. Ditto pointed out that since 2006, the number and dollar value of new privatized projects has fallen by more than 70 percent in Europe, according to the European Investment Bank. Outside Europe, the number and dollar value of privatization projects in 2019 were roughly half what they were in 2012, according to the World Bank.

“Conversely, private investment in U.S. infrastructure made through the purchase of tax-exempt municipal bonds has rebounded since 2011: more than $2 trillion in new investments in the last decade and $300 billion in 2020 alone. Most municipal bonds are held by retail investors, such as retirees, union workers, and average American workers with 401k plans, who receive a rate of return commensurate with the relatively low risk.”

Privatizing public facilities “will not get the private sector ‘off the bench.’ Often, privatized project financing comes from investors purchasing private activity bonds instead of municipal bonds. And, insofar as overseas investors or private equity firms are providing a new pool of financing, they are replacing traditional investors, but demanding a much higher rate of return,” Ditto said.

“Likewise, one governor recently defended a privatized express lane project saying it will ‘cost the state nothing.’ But, of course the ‘state’ itself never pays for anything, people do through income taxes, sales taxes, and user fees. Privatizing a public facility doesn’t change that, except perhaps to increase the costs paid as I discussed above.”

Ditto said she takes it “as good news that it appears that in discussing asset recycling, policymakers are not discussing the sale of federal assets, such as the Power Marketing Administrations (PMAs) and the Tennessee Valley Authority (TVA).”

The costs to run the PMAs and TVA are paid by customers and not the federal government and none of the costs are borne by taxpayers. “Furthermore, there is no factual evidence that selling the transmission assets of the PMAs would result in a more efficient allocation of resources. Rather, it is much more likely that any sale of these assets to private entities would result in attempts by the new owners to charge substantially increased transmission rates to PMA customers for the same service they have historically received,” Ditto wrote.

Geothermal Market Potential And Impediments Outlined In NREL Report

July 20, 2021

by Peter Maloney
APPA News
July 20, 2021

There is the potential for as much as 60 gigawatts (GW) of geothermal capacity in the United States by 2050, but several impediments would first have to be addressed, according to a new report by the National Renewable Energy Laboratory (NREL).

Improvements in regulatory processes and technology advances would be key to facilitating the expansion of geothermal resources, both as a form of primary electricity generation and as a source of district heating, the report, 2021 U.S. Geothermal Power Production and District Heating Market Report, said.

In geothermal power’s favor are several “non-cost factors,” such as the ability of geothermal plants to operate 24 hours a day regardless of weather and without voltage swings, making them an appropriate baseload replacement for retiring fossil fuel plants and a complement for variable energy resources. Those advantages could become increasingly important as states adopt or move closer to mandates requiring low or no carbon dioxide emissions from the power sector, the report said.

The bulk of the 60 GW of geothermal capacity, which NREL references from the Department of Energy’s 2019 GeoVision 2019 study, would be the result of technology advances and cost reductions in the deployment of geothermal resources. The study GeoVision study estimates that about 13 GW of the potential 60 GW could come from improvements in the regulatory process.

One example cited in the NREL report is the lack of risk mitigation schemes and federal and state incentives for geothermal district heating.

NREL also noted that geothermal power production is “likely hindered” by its least cost of energy (LCOE), which, although lower than coal and gas peaking plants, is higher than solar and wind power and combined-cycle gas-fired plants.

In recent years, the U.S. geothermal power sector has seen little capacity growth, NREL said. The sector went from 3,627 megawatts (MW) to 3,673 MW from 2015 to 2019. The 186 MW of new capacity that came online in the time frame were mostly expansions and repowerings of existing plants and was offset by the retirement of 11 plants with a combined capacity of 103 MW.

However, since 2019, nine new geothermal power purchase agreements have been signed in four states, including plans for the first two geothermal power plants to be built in California in a decade, NREL noted.

“The newest market report conveys that the geothermal industry is poised to make big leaps into enhanced geothermal systems and the heating and cooling sector,” Kelly Speakes-Backman, acting assistant secretary for energy efficiency and renewable energy at the Department of Energy, said in a statement. “These strides outline the potential for the widespread deployment of this important renewable resource.”

Speakes-Backman was a recent guest on the American Public Power Association’s Public Power Now podcast.

NYPA project uses AI to better understand performance of underwater cable

July 19, 2021

by Peter Maloney
APPA News
July 19, 2021

The New York Power Authority (NYPA) is launching a demonstration project that will use artificial intelligence (AI) as part of the potential upgrade of underwater cable that transports power from Westchester to Long Island.

Working with Eneryield, a Swedish company that provides machine learning algorithms for intelligent energy analytics and electricity flows, NYPA plans to use the technology to identify possible solutions, to detect faults, and help strengthen and upgrade the Long Island Sound Cable, which is being evaluated for long-term repairs.

The project will focus on NYPA’s 23-mile, 693 megawatt (MW) Y49 transmission cable. Historical data will be used from various sources and artificial intelligence/machine learning techniques will be applied to identify small anomalies, deviations and patterns to predict larger imminent disturbances or faults.

The aim of the project is to determine whether the technology can help predict developing problems or incipient failure of buried and underwater cables and improve on unique correlations and data characteristics that can be measured in more conventional analysis techniques.

The Long Island Sound Cable has had faults that have contributed to intermittent outages over the past year. NYPA is working with its local partners, the Long Island Power Authority and its service provider, PSEG Long Island, to implement a long-term strategy for the cable’s future reliability and resiliency.

Potential solutions include replacing segments of the span and possibly expanding the line’s capacity to prepare for an influx of green energy sources. The results of the demonstration project will help inform next steps for the line’s upgrade.

“This is an opportunity to take new technologies that have shown promise in development and put them to the test with real-time data and an active power system,” Alan Ettlinger, senior director of research, technology development and innovation for NYPA, said in a statement. “The use of artificial intelligence in infrastructure inspections can help increase reliability and safety, recognize malfunctioning equipment and identify problems that need repair, therefore mitigating outages for customers.”

The Electric Power Research Institute’s (EPRI) Incubatenergy Labs program recently selected Eneryield as one of 20 startup companies that will conduct accelerated demonstrations of their technologies with utilities and EPRI as part of Incubatenergy Labs’ 2021 cohort.

The 20 startups selected through Incubatenergy program the will spend 16 weeks working with EPRI and electric power utilities around the country on demonstration technology projects intended to accelerate decarbonization, electrification, grid modernization and other electric power industry innovation imperatives. The results will be presented during EPRI’s Incubatenergy Labs Demo Days in mid-October.

EPRI is one of several entities that are exploring the use of artificial intelligence in the electric power industry.

The use of AI to monitor transmission cable performance is only one of several uses NYPA is studying for the technology. In May, NYPA selected C3 IoT to provide a software platform to help the it and the state implement and meet its energy efficiency targets.

In June, the Tennessee Valley Authority teamed up with Oak Ridge National Laboratory and the University of Tennessee System to study the use of AI in a variety of applications, including cybersecurity, digital currency, 5G broadband cellular technology, and other innovations.

Also in June, independent power producer Vistra said it plans to use AI at its Moss Landing energy storage facility in California to help it better predict wholesale power market prices.

Granholm Details How Public Power Can Work With The Department of Energy In Key Areas

July 15, 2021

by Paul Ciampoli
APPA News Director
July 15, 2021

Secretary of Energy Jennifer Granholm on July 14 detailed how the Department of Energy (DOE) and the public power community can work together in a number of areas including research, development and deployment (RD&D) programs, as well as the country’s clean energy transition.

Granholm made her remarks in a Q&A with Colin Hansen, chair of the American Public Power Association Board of Directors, at APPA’s National Conference Virtual Event.

Given the Biden Administration’s push for the power sector to get 100 percent of its electricity from zero-emitting resources, Hansen asked Granholm to detail what DOE plans to do to specifically help public power utilities in this clean energy transition “that will importantly ensure that electricity remains both affordable and reliable.”

“We totally want to partner,” Granholm said.

She noted that in October, DOE will begin a five-year, one-and-a -half-million dollar agreement with APPA “so we can work together on practical strategies to make the grid cleaner and more resilient and more reliable and affordable.”

Granholm also noted the partnership that many APPA members have with DOE’s power marketing administrations “to provide that affordable and reliable power.”

She said that as part of DOE’s new initiative to reduce the cost of grid-scale, long duration energy storage by 90% within the decade, “we’re going to work with stakeholders, including public power utilities, to make sure that the new long duration storage solutions can meet” the needs of public power utilities in an affordable way.

Turning to a different topic, Hansen noted that at the end of last year, the Energy Act of 2020 was signed into law, authorizing billions of dollars in RD&D programs over the next decade. APPA supported the legislation, particularly because DOE RD&D programs would be open to public power.

Hansen asked Granholm to discuss how public power utilities can participate in, and benefit from, RD&D efforts at DOE, particularly smaller public power utilities.

The Secretary of Energy said that DOE has already mobilized $1.5 billion for clean energy deployment and RD&D “just this year in this administration.”

Granholm said that “a lot of this work is happening at the labs and through our efforts with states and utilities including on grid modernization and energy efficiency. We’re also supporting demonstration projects – emerging zero carbon technologies like carbon capture and advanced nuclear.”

She said that passing President Biden’s Build Back Better agenda overall through Congress “would give us so many more resources for all of this work for partnerships with utilities large and small. We want to share the resources, the funding, the innovation, the insights with you to work together to test and deploy these solutions” that public power is looking for.

Meanwhile, Hansen noted that in September 2020, DOE’s Office of Cybersecurity, Energy Security and Emergency Response awarded APPA a grant of $6 million over a three-year period to develop and deploy cyber and cyber-physical threat solutions for public power utilities.

“Through this cooperative agreement, we’re going to continue to work with APPA to develop and to deploy these cyber solutions for public power utilities,” Granholm said.

Hansen, executive director of Kansas Municipal Utilities (KMU) in McPherson, Kansas, was installed as chair of APPA’s Board of Directors during APPA’s National Conference in Orlando, Florida, on June 23.

EPA Identifies Drinking Water Contaminants for Potential Regulation

July 14, 2021

by Paul Ciampoli
APPA News Director
July 14, 2021

In a move that has significant implications for municipalities and water companies that offer potable water service and have National Pollutant Discharge Elimination System (NPDES) permits, the U.S. Environmental Protection Agency (EPA) recently proposed that a group of per- and polyfluoroalkyl substances (PFAS) be included in the latest iteration of its periodic Safe Drinking Water Act list of candidates for future regulations. 

EPA on July 12 announced “Draft Contaminant Candidate List 5” (CCL 5), which provides the latest list of 66 drinking water contaminants that are known or anticipated to occur in public water systems and are not currently subject to EPA drinking water regulations which includes PFAS. As directed by the Safe Drinking Water Act, EPA said its CCL 5 identifies priority contaminants to consider for potential regulation to ensure that public health is protected.

EPA will use the Unregulated Contaminant Monitoring Rule (UCMR) to collect information from potable drinking water systems on the prevalence, occurrence and concentration of PFAS. 

The UCMR requires potable drinking water systems to collect data for contaminants that are suspected to be present in drinking water and do not have health-based standards set under the Safe Drinking Water Act (SDWA).  Once the UCMR goes into effect in 2023, all public water systems serving more than 3300 people plus 800 randomly selected smaller water systems will need to begin testing for 29 PFAS chemicals. 

The immediate impact of UCMR implementation to test for PFAS chemicals is that the turnaround time for PFAS samples is typically 45 days and each water sample generally costs more than $300. 

EPA plans to consult with its Science Advisory Board (SAB) on the draft CCL 5 this fall. The agency will consider public comments and SAB feedback in developing the final CCL 5, which is expected to be published in July 2022. After a final CCL is published, the agency will undertake a separate regulatory determination process to determine whether or not to regulate contaminants from the CCL.

EPA is seeking comment on the draft CCL 5 for 60 days after publication in the Federal Register, which took place on July 12.

For more information, visit: https://www.epa.gov/ccl/contaminant-candidate-list-5-ccl-5.

Developing the CCL is the first step under the Safe Drinking Water Act in potentially regulating drinking water contaminants. The Safe Drinking Water Act requires EPA to publish a list of currently unregulated contaminants that are known or anticipated to occur in public water systems and that may require regulation.

EPA must publish a CCL every five years. The last cycle of CCL was published in November 2016.

The NPDES permit program addresses water pollution by regulating point sources that discharge pollutants to waters of the United States. Created in 1972 by the Clean Water Act, the NPDES permit program is authorized to state governments by EPA to perform many permitting, administrative, and enforcement aspects of the program.

EPA has established a non-enforceable Health Advisory Level for PFAS at 70 parts per trillion.  Should EPA adopt a Maximum Contaminant Level for PFAS chemicals, there will be added costs borne to potable drinking water treatment systems in terms of laboratory testing requirements and treatment. Starting on July 21, 2021, the American Public Power Association will host a four-part webinar series that offers utilities practical guidance on understanding the impact of PFAS to drinking water treatment systems and effective wastewater treatment technologies, risks and liabilities, and how best to communicate PFAS information to consumers.

Additional details about the webinar series are available here.

Department of Energy Sets Goal To Cut Cost Of Grid-Scale, Long Duration Storage By 90%

July 14, 2021

by Paul Ciampoli
APPA News Director
July 14, 2021

U.S. Secretary of Energy Jennifer Granholm on July 14 announced the U.S. Department of Energy (DOE)’s new goal to reduce the cost of grid-scale, long duration energy storage by 90% within the decade.

Long duration energy storage is defined as systems that can store energy for more than 10 hours at a time.

This marks the second target within DOE’s Energy Earthshot Initiative, which aims to accelerate breakthroughs of more abundant, affordable, and reliable clean energy solutions within the decade. Under the first Eearthshot Initiative, DOE launched an effort to reduce the cost of clean hydrogen by 80% to $1 per kilogram in one decade.

The Long Duration Storage Shot will consider all types of technologies, whether electrochemical, mechanical, thermal, chemical carriers, or any combination that has the potential to meet the necessary duration and cost targets for grid flexibility.

Currently, pumped-storage hydropower is the largest source of long duration energy storage on the grid, and lithium ion is the primary source of new energy storage technology deployed on the grid in the United States, providing shorter duration storage capabilities, DOE noted.

DOE said it developed the Long Duration Storage Shot target through its Energy Storage Grand Challenge (ESGC) and stakeholder engagement activities and input from subject matter experts, and will continue concerted outreach to advance the Long Duration Storage Shot and ESGC’s aggressive goals and strategy.

ESGC and the Long Duration Shortage Shot are linked with integrated efforts across the Department’s Offices of Energy Efficiency and Renewable Energy, Electricity, Fossil Energy and Carbon Management, Science, Nuclear Energy, and Technology Transitions, as well as the Advanced Research Projects Agency – Energy.

Maine Governor Vetoes Bill That Would Create Consumer-Owned Utility

July 14, 2021

by Paul Ciampoli
APPA News Director
July 14, 2021

Maine Gov. Janet Mills on July 13 vetoed a bill that called for the creation of a consumer-owned utility in the state called Pine Tree Power.

The consumer-owned entity that would be created under the bill would take over the electric service now provided by investor-owned Central Maine Power (CMP) and Versant Power. CMP and Versant Power (formerly known as Emera Maine), are majority owned by Iberdrola of Spain and Emera of Canada, respectively.

The bill called for placing the question of consumer ownership of Maine’s grid on the ballot in November 2021.

Unless the Legislature is able to override the governor’s veto by two-thirds supermajorities in both the House and the Senate, the question of consumer ownership of Maine’s two investor-owned utilities, CMP and Versant, will not be on this year’s ballot.

The Legislature will reconvene on July 19 to vote on the veto, and on all other vetoes Mills has issued since July 1.

In her veto message, the governor said the performance of the state’s investor-owned utilities in recent years “has been abysmal,” citing “inexcusable billing errors, unacceptable delays in restoration of service, inexplicable confusion over the costs of connecting new solar projects to the grid, substantial rate increases, and now a draft audit report that questions Central Maine Power’s management structure.”

The Maine Public Utilities Commission on July 13 received the results of an independent audit of the management structure of CMP and its affiliated service companies, Avangrid Management Company and Avangrid Services Company. The Commission ordered the audit in January 2020 at the conclusion of an investigation into CMP’s rates.

Mills said that it “may well be that the time has come for the people of the State of Maine to retake control over the [utilities’] assets,” but she raised several outstanding concerns about the substance of the bill.

The Maine Legislature on June 30 voted in favor of the bill, casting a bipartisan 77-68 vote in the House to attach an amendment to the bill that they supported two weeks ago. The Maine Senate voted 18-15 to support the new package.

An amendment introduced June 30 revised the bill to require the Pine Tree Power Company to pay property taxes directly to Maine municipalities, while maintaining its nonprofit status. This replaced previous bill language requiring payments in lieu of taxes.

Maine Rep. Seth Berry, sponsor of L.D. 1708, said the amendment spoke directly to the top two concerns of Mills, and concerns voiced by some municipal leaders. “We are pleased that the revised language won back the support needed to send this to Governor Mills, and hope to win her support for our effort as well,” he said in a statement.

Berry discussed the legislation in a recent episode of the American Public Power Association’s Public Power Now podcast.

Stephanie Clifford, campaign manager for Our Power, a group that supports the creation of a consumer-owned utility in the state, previously said that if Mills vetoed the bill, “we will continue our campaign through a citizens’ initiative.”

She said that petition gathering on such a citizen-initiated referendum would begin this summer and would likely put the question on the ballot in November 2022, the same day that Mills and all legislators are up for re-election.

After the news broke that Mills had vetoed the bill, Our Power tweeted that “we’ll take the proposal to replace CMP/Versant with Maine’s own consumer-owned utility directly to the voters.”