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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.”

APPA Seeks Nominations For Two Openings On Smart Energy Provider Review Panel

July 14, 2021

by APPA News
July 14, 2021

The American Public Power Association (APPA) is accepting nominations through Monday, August 9, 2021 for two open positions on the Smart Energy Provider (SEP) Program Review Panel. 

The SEP program is public power’s evaluation and review of leading practices for utilities based on four criteria: smart energy program planning, energy efficiency and distributed energy resources, environmental and sustainability programs, and customer communication and education.

The SEP Review Panel guides APPA staff in the implementation of the SEP program and provides expert peer review of public power utilities’ applications for SEP recognition.

Two seats are currently available for up to three consecutive two-year terms. Each member of the panel is expected to attend two meetings per year, one in the summer and one in the fall. There will be virtual attendance options for these meetings as well.

The nominated members are invited to shadow the SEP Business meeting on October 24, 2021. The first term of this position will officially begin after the 2021 Customer Connections Conference in October.

Nominations of APPA members with expertise in energy efficiency, distributed energy resources, load management, integrated resource planning, and demand-side management are encouraged. 

To nominate someone, click here to download the nomination form. The completed nomination form and any supplementary materials should be emailed to SEP@PublicPower.org.

Questions should be addressed to APPA SEP Staff at 202-467-2931 or email SEP@PublicPower.org.

More information on the SEP program is available on the SEP website

Real-Time Grid Assessment Is Adequate But Could Be Improved: FERC-NERC Report

July 13, 2021

by Peter Maloney
APPA News
July 13, 2021

Operators of the bulk power system are prepared to manage  assessment of real-time grid operating conditions, but they should develop alternative procedures in the event of data loss failures lasting more than two hours, according to a report issued last week by the staff of the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) and its regional entities.

Real-time assessment requirements in NERC standards mandate that transmission operators and reliability coordinators perform an assessment at least once every 30 minutes to ensure prevention of instability, uncontrolled separation, or cascading outages that could adversely impact the reliability of the interconnection.  The report detailed these requirements and provided further recommendations for real-time assessments of grid operating conditions.

NERC developed the existing standard requirements in the wake of the 2011 Southwest blackout report to ensure that real‐time tools are adequate, operational, and used frequently enough to provide system operators with the situational awareness needed to identify and plan for contingencies and to reliably operate their systems.

Among the primary causes of the 2003 Northeast blackout was the failure to assess and understand the real-time risks to the grid. The current real-time assessment requirements are a direct result of that finding, NERC says.

The real-time assessment review was not a compliance activity. It included on-site discussions with representatives of nine participating reliability coordinators and transmission operators. The purpose of the review was to work with subject matter expert participants and technology leaders in a collegial environment. The underlying intent, according to the report, was that understanding operational challenges enhances regulatory oversight.

Among other findings, the report found that as the penetration of renewable generation and inverter-based resources increases, transmission system operators should be prepared to augment existing tools to facilitate reliable operation planning that includes renewable forecasting.

Among other recommendations, the report said reliability coordinators and transmission operators should:

The review team also found that all participants have processes for identifying problems with quality of individual real-time data points and have procedures for correcting the errors.

However, only a few of the participants have developed metrics to trend aggregate real-time data errors with thresholds identifying when errors are reaching levels that would impair the quality of the real-time assessment, the report found.

TVA to spend $1 billion building 1,500 MW of gas turbines

July 13, 2021

by Peter Maloney
APPA News
July 13, 2021

The Tennessee Valley Authority (TVA) plans to invest $1 billion to build three new gas-fired combustion turbines totaling 1,500 megawatts (MW)

The planned gas turbines are being built at the site of shuttered coal plants in Tuscumbia, Alabama, and Paradise, Kentucky, and will replace combustion turbines scheduled for retirement.

The new plants will bring in about 185 jobs at each location to prepare each site and construct the units, TVA said.

“As we continue to evolve our generation portfolio, natural gas is the right choice at this time because it provides the flexibility and reliability we need to add more solar energy,” Jacinda Woodward, senior vice president of power operations at TVA, said in a statement.

“It’s important to remember that solar power is an intermittent generation source — natural gas delivers reliable electricity even when the sun doesn’t shine,” Woodward said. She added that TVA will continue to consider natural gas an option for replacement generation as it studies the closing of its remaining coal fleet while adding about 10,000 MW of new solar power by 2035.

“Natural gas helps us achieve a 70% reduction in emissions by 2030, 80% by 2035 and we believe it is possible, with new technologies, to achieve net-zero by 2050,” Woodward said.

The plants scheduled for retirement are at TVA’s Allen Reservation on the Mississippi River, five miles southwest of Memphis, Tenn., and at the utility’s Johnsonville Reservation in Tennessee. The plants have a combined capacity of 1,400 MW and have “received little recent investment, are 40 or more years old and require replacement to ensure reliability,” according to TVA.

“Current and retired coal plant sites are prime locations for new gas generation because the electrical infrastructure is already in place,” Woodward said.

The new gas plants will require upgrades of the existing natural gas supplies, as well as connections to TVA’s existing transmission lines, including upgrades to those lines.

While the environmental assessment for the proposed plants was under review and open for comment, TVA noted that the most frequently mentioned comments related to climate impacts, environmental justice, analysis of alternatives, and cumulative impacts.

In its environmental assessment, TVA concluded that the proposed plants would not be “a major federal action significantly affecting the environment and issued a finding of no significant impact.”

TVA currently operates 108 natural gas and fuel oil-fired generators totaling more than 12,000 MW at 17 sites, nine in Tennessee, five in Mississippi, one in Alabama, and two in Kentucky.