FERC Report Finds Advanced Meter, Demand Response Penetration Growing
January 18, 2022
by Peter Maloney
APPA News
January 18, 2022
Utility customer enrollment in both retail demand response and dynamic pricing programs increased from 2018 to 2019 and data suggests that as more advanced meters are deployed utilities will continue to see increasing enrollment levels, according to a new report from the staff of the Federal Energy Regulatory Commission (FERC).
Among the highlights of the report, 2021 Assessment of Demand Response and Advanced Metering, FERC staff found that the number of advanced meters in operation in the United States from 2018 to 2019 increased by about 8 million to 94.8 million, representing a 9 percent annual increase.
The 94.8 million advanced meters in operation represents about 60.3 percent of the 157.2 million meters in the United States, and, despite regional variations, estimated advanced meter penetration rates nationwide for residential, commercial, and industrial customer classes were greater than 50 percent in 2019, according to the report.
In 2019, utilities in the South Atlantic census division, essentially southern seaboard states, reported over 21 million advanced meters in operation, while utilities in the East North Central (Ohio Valley states and Michigan), Pacific, and West South Central (Texas and its three contiguous states to the north and east) census divisions each reported over 14 million advanced meters in operation, the report said.
The total number of advanced meters reported by utilities in the East North Central, East South Central, Pacific, South Atlantic, and West South Central areas represent advanced meter penetration rates greater than 65 percent, FERC staff said.
The report also noted that state regulators continue to support the deployment of advanced meters. Connecticut and New Jersey, for instance, are initiating proceedings and establishing frameworks for advanced metering proposals and proposal analysis.
In the assessment, FERC began using nine census regions instead of North American Electric Reliability Corp. regions to present some data because of changes NERC has made in recent years. For example, the transfer of entities in the Florida Reliability Coordinating Council footprint to the SERC Reliability Corp. To present accurate trends and to provide continuity, FERC presented its findings by census divisions for the last two years.
Demand Response
Demand resource participation in the wholesale markets decreased by about 1,383 MW, or 4 percent, from 2019 to 2020, even though demand response resource totals increased in four of the seven wholesale markets, the report found.
The largest annual difference was in the PJM Interconnection area where there was a 1,270 MW drop, representing a 12.5 percent decline in demand response resources from 2019 to 2020.
Despite the decline in demand resource participation, the percent of peak demand that could be met by demand response resources increased from 6 percent in 2019 to 6.6 percent in 2020 because of lower peak loads, the report found.
Meanwhile, customer enrollment in retail incentive-based demand response programs increased by 1.1 million from 2018 to 2019, a 12 percent increase, and customer enrollment in retail dynamic pricing programs increased by 1.7 million, a 19 percent increase, the report said.
Overall, customer enrollment in incentive-based demand response and dynamic pricing programs increased in six census divisions with utilities in five divisions reporting aggregate annual increases of 20 percent or more.
Utilities in the South Atlantic region reported the greatest absolute increase, with over 669,000 additional customers enrolled while utilities in the West South Central region saw the largest annual increase, 88 percent, in customer enrollment from 2018 to 2019. New England utilities reported the second highest annual increase with a 43 rise in enrollments, the report found.
Not all regions saw increases, however. Utilities in the Pacific region saw 348,000 fewer customers enroll in 2019 compared with 2018 even as individual utilities such as San Diego Gas and Electric and Portland General Electric in Oregon saw enrollments rise.
Even with rising numbers, the report noted that the total number of customers enrolled in retail dynamic pricing and retail demand response programs is still relatively low compared with the total number of retail customers.
Regulatory barriers to customer participation in demand response programs continue to exist. Demand response programs can result in lower energy costs for customers, but “regulatory approval processes required for technologies that unlock the value of demand response and time-based rate programs, like advanced metering, can slow the development and implementation of new programs,” FERC staff wrote in the report.
In addition, many regional transmission organizations (RTOs) and independent system operators (ISOs) “limit the ability of demand flexibility to participate at the wholesale level as demand response because demand response is often defined as a reduction in expected consumption,” the report said.
“While some RTOs/ISOs incorporate demand response and demand-side resources into planning and resource adequacy processes, the full suite of demand flexibility capabilities are not currently accounted for in utility, state, and RTO/ISO planning processes,” the report said.
The FERC assessment report is the 16th in a series of reports the commission issues each year as required by the Energy Policy Act of 2005.
N.Y. Energy Sector GHGs Fall As Building, Transportation Sector Emissions Rise
January 18, 2022
by Peter Maloney
APPA News
January 18, 2022
Greenhouse gas emissions (GHG) from the industrial and energy sectors have fallen in New York State, but transportation and building emissions have risen, according to a new report by the state’s Department of Environmental Conservation (DEC).
Overall, the 2021 Statewide GHG Emissions Report found that 2019 GHG emissions in the state were 6 percent below 1990 levels and 17 percent below 2005 levels.
The report was the first issued by the state and will be produced annually in compliance with the Climate Leadership and Community Protection Act (CLCPA) that commits the state to achieving net zero GHG emissions by 2050.
“This annual report shows that while New York State has reduced emissions from several sectors over the last three decades, emissions from some sectors, including transportation, have increased, revealing that enormous challenges remain in our ongoing work to meet our emission-reduction targets,” Basil Seggos, DEC commissioner and co-chair of the Climate Action Council, said in a statement.
The report found a 46 percent reduction in emissions from electric power generation since 1990 and a 34 percent reduction in industrial sector emissions. Emissions from the transportation and building sectors, however, both increased by 16 percent since 1990, although emissions from both sectors have declined since 2005.
The report also found that while carbon dioxide (CO2) emissions declined 15 percent from 1990 to 2019, hydrofluorocarbons and methane emissions increased during the same period.
In 2019, the report found statewide gross emissions were 379.43 million metric tons of carbon dioxide equivalent (mmt CO2e). Carbon dioxide and methane comprised the largest portion of emissions, or 58 percent and 35 percent, respectively.
Using the United Nations’ Intergovernmental Panel on Climate Change (IPCC) guidelines, the energy sector was the largest source of emissions at 76 percent, primarily from fuel combustion and fugitive emissions from imported fossil fuels.
Using sectors that reflect the New York State Climate Action Council Draft Scoping Plan, the largest source of emissions in the state is buildings at 32 percent and transportation at 28 percent. In addition, about 8 percent of 2019 emissions were removed, primarily using CO2 sequestration in forests.
Those same guidelines showed a 46 percent decrease in electric sector emissions and a 34 percent decrease in industrial emissions that were offset by a 16 percent increases in both the buildings and transportation sectors. Emissions from the agricultural and waste sectors also increased.
Under Climate Action Council guidelines, emissions from energy fuels are assigned to the sector where the fuels are used such as transportation or electricity generation. Similarly, products that contain hydrofluorocarbons, such as air-conditioning equipment, were assigned to the transportation or buildings sectors.
JEA Reduces Carbon Emissions With Closure Of Plant Scherer Coal-Fired Unit
January 18, 2022
by Paul Ciampoli
APPA News Director
January 18, 2022
Florida public power utility JEA kicked off 2022 with a reduced emissions footprint as a result of the closure of Plant Scherer’s Unit 4, in Juliette, Ga.
JEA has replaced coal-fired electric power from Plant Scherer with natural gas through a power purchase agreement with investor-owned Florida Power & Light (FPL). JEA and FPL have jointly owned Plant Scherer, Unit 4, since 1991. Unit 4, operated by Georgia Power, ceased operations on Dec. 31, 2021.
Plant Scherer is the largest coal-fired power facility in the U.S. with four power generating units. The plant’s 900-megawatt class generating units burned Powder River Basin Coal. JEA owns 23.64% of Unit 4, and FPL controls the remaining 76.36%
By replacing power from Plant Scherer with natural gas, JEA has lowered operating costs, reduced operating risks and reduced CO2 emissions by approximately 1.3 million tons per year, it noted, adding that it continues to diversify its electric generation portfolio with the addition of renewable energy resources, including natural gas, solar and biogas.
JEA has reduced its carbon emissions by 53 percent since 2007 with the closing of St. Johns River Power Park coal-fired plant and the decommissioning of Plant Scherer.
JEA this year is launching its integrated resource plan, which will lay out its future electric generation mix plans and strategic direction for the next two decades.
Fitch Cites Silicon Valley Power’s Strong Financial Performance In Affirming Rating On Bonds
January 18, 2022
by Paul Ciampoli
APPA News Director
January 18, 2022
Fitch Ratings recently affirmed the “AA-“ rating on bonds issued by Silicon Valley Power (SVP), which is the operating public power utility for the City of Santa Clara, Calif.
The rating was affirmed for $48.975 million refunding revenue bonds, series 2013A and 2018A and the rating outlook is stable, Fitch noted.
“The affirmation of the ‘AA-‘ ratings reflects SVP’s strong financial performance over the past three years, resulting in lower net leverage,” Fitch said.
SVP’s financial profile “exhibits some variability in operating income as a result of hydroelectric availability, but is supported by robust liquidity levels,” the rating agency said.
It also said that the rating reflects the utility’s low operating cost burden associated with a primarily natural gas, hydroelectric and renewable generation portfolio.
SVP is an enterprise fund of the city of Santa Clara, providing service to approximately 59,200 customer accounts within the city’s boundaries.
The city of Santa Clara “is the heart of Silicon Valley and includes an affluent service territory with a considerable concentration of high-tech industries and strong load growth,” Fitch pointed out.
SVP continues to experience strong customer and load growth, with much of the growth resulting from increased data center activity at technology companies, it said.
“Rating concerns related to customer and industry concentration are partially offset by the diversity of business activities represented by the customer base and the demonstrated stability in demand over the past decade,” Fitch said.
The retail electric utility is fully integrated with direct and joint ownership of generation, transmission and distribution facilities. Power supply is provided primarily by SVP’s locally owned natural gas-fired generation plant and purchased power allocations from the Northern California Power Agency and Western Area Power Administration that include natural-gas, hydroelectric and geothermal resources. SVP supplements these resources with increasing renewable purchases.
Fitch considers the electric system to be a related entity of the City of Santa Clara (not rated by Fitch) for rating purposes, given the city’s oversight of the system, including the authority to establish rates and budget of the electric system.
The rating on the electric system bonds is not currently constrained by the credit quality of the City of Santa Clara, the rating agency said.
New Mexico Utility Regulators Consider Petition On Public Power Study At Meeting
January 13, 2022
by Paul Ciampoli
APPA News Director
January 13, 2022
New Mexico utility regulators at a Jan. 12 meeting considered a petition that asked them to launch a study that would evaluate shifting the state’s electric sector to public power.
At the New Mexico Public Regulatory Commission (PRC), the commissioners heard from State Sen. Carrie Hamblen and Mariel Nanasi, Executive Director of the New Mexico New Energy Economy as part of their discussion about the petition, which was filed by a group of New Mexico lawmakers.
The lawmakers said in their petition that they “believe that it is probable that public ownership of the electrical utilities that serve New Mexico would benefit New Mexico’s ratepayers, New Mexico’s businesses, and New Mexico’s state, local and tribal governments.”
At the PRC meeting, Sen. Hamblen said that the value of the study would be to “determine the costs, benefits and pathways to public power and to evaluate whether implementation of public power will protect the public interest, reduce and stabilize electricity rates, create revenue generation for the state and result in the deployment of 100 percent renewables plus storage, as well as enhance local economic benefits.”
Hamblen said that “if we are to thoroughly understand the alternatives to the current structure of our energy systems and service providers, we need the advice of technical experts. We also need to feel comfortable in seeing what other options there are and, really, whether or not they’re good for our state.”
She noted that the American Public Power Association has determined that public power customers pay on average 11 percent less than investor-owned utility customers. Further, public power customers “receive more reliable service and are more likely to benefit from renewable power sources,” Hamblen went on to say.
“Most importantly for New Mexico, it also keeps our money in our communities,” she said. “Publicly owned utilities can reinvest profits from energy sales into local jobs, lower energy costs for low-income customers and invest in local community projects and causes.”
Hamblen noted that the petition “points to two possible models that can be studied – a state-owned and operated electric power authority with municipal and tribal local control over generation or a community choice system where investor-owned utilities maintain transmission and distribution, with the option for municipal and tribal control over the generation.”
Hamblen said that her colleagues in the New Mexico House and Senate “feel that the PRC is not only the appropriate agency to house the study, but also has the most expertise when it comes to providing data on our various utilities.” The PRC “would be the custodian of the study and we are not asking you to take a position on the study findings. You have the technical expertise and if there are questions to be asked, you can either provide the answers or get that information from the utilities,” she said.
“We know that you will not be implementing public power. We recognize that that is the purview of the legislature,” she said. “We recognize that there are many factors to be explored” including the impact on workers, the costs of a publicly owned utility, how municipalities and tribal entities will be affected “and much more and that’s why, as legislators, there’s already been exploration about who is going to do the study and who is going to pay for it. We don’t expect the PRC to pay for it.”
Hamblen said that “the joint petitioners and legislators will be seeking that private money to be housed at the Santa Fe Community Foundation.” Moreover, the PRC would not be responsible for determining the best consultants and agencies to perform the study.
Nanasi said that “we’re hoping that this study will be done” in 2022.
PRC Commissioner Stephen Fischmann said he thinks such a study is worth doing. He noted that a lot of public power utilities are “doing some of the most innovative work,” mentioning specifically the Los Angeles Department of Water and Power and its work on hydrogen, Texas public power utility Austin Energy, which “embraced solar very early” and Texas public power utility CPS Energy.
And, within New Mexico, the community of Farmington “loves its municipal public electric utility. It has very low rates.”
The Commissioners ultimately decided not to take action on the petition at the meeting.
APPA Seeks Nominations For 2022-2023 Board of Directors
January 13, 2022
by Paul Ciampoli
APPA News Director
January 13, 2022
The American Public Power Association (APPA) is seeking nominations for APPA’s 2022-2023 Board of Directors.
The nomination form can be found here to nominate individuals and nominations are due no later than February 12, 2022.The call for nominations covers Regions 5, 7, 9, and 10.
The APPA Nominating Committee will meet virtually on Tuesday, February 22, 2022, to consider nominations for new Board members. The Committee’s recommendations for new Board members will be presented to APPA’s membership at the annual business meeting held in June during APPA’s National Conference.
Directors are normally elected for three-year terms and are eligible to serve two consecutive terms. Any director who has served five or more years consecutively is not eligible for re-election until a period of one year has elapsed.
Contact Cartina Parks-Williams at CParks-Williams@publicpower.org for assistance or additional information.
Kansas Power Pool’s Mark Chesney To Retire This Month
January 13, 2022
by Paul Ciampoli
APPA News Director
January 13, 2022
Kansas Power Pool (KPP) CEO and General Manager Mark Chesney, who began his work at KPP more than nine years ago, is set to retire at the end of January. He will be succeeded by Colin Hansen, current Executive Director of Kansas Municipal Utilities and American Public Power Association (APPA) Board Chairman.
He started his career in public power with the Grand River Dam Authority in his native Oklahoma. Working 10 years at GRDA, his first duties were economic development where he was a member of, and led, three commissions devoted to development in northeast Oklahoma.
Later, he led GRDA staff in industrial key account management, purchase power contract negotiation/administration as well as media services management. Eventually, as Assistant General Manager of Energy Marketing and Development, he managed market and transmission operations personnel at GRDA’s energy control center.
In the year 2000 Mark joined the staff at the Utah Municipal Power Agency as their Operations Manager. His tenure there included supervising personnel in the scheduling, trading and dispatching of energy. Among his other duties were new power supply screening, the management of the agency’s transmission-dependent relationship with PacifiCorp and the hydro allocation entitlements from the Colorado River Storage Projects of the Western Area Power Administration (WAPA).
Returning to Oklahoma in 2010, Chesney served just over two years as the General Manager of the Tahlequah Public Works Authority.
Since late 2012, he has served in his current position with KPP, a joint action agency comprised of 24 electric utilities in Kansas. His tenure has been marked by increases in the KPP resource portfolio, improved cash reserves and liquidity and an upgrade in the KPP bond rating. Achieving member city contract uniformity was also a notable KPP milestone.
As the end of his professional career began to approach, Mark was elected in 2018 to the Board of Directors of APPA. Last summer, at APPA’s national conference, he received the James D. Donovan Individual Achievement Award.
Biden Administration To Hold Its First Offshore Wind Lease Sale Next Month
January 12, 2022
by Paul Ciampoli
APPA News Director
January 12, 2022
Secretary of the Interior Deb Haaland on Jan. 12 announced that the Bureau of Ocean Energy Management (BOEM) will hold a wind energy auction in February for more than 480,000 acres offshore New York and New Jersey, in the area known as the New York Bight.
This will be the first offshore wind lease sale under the Biden-Harris administration.
The Feb. 23 auction will allow offshore wind developers to bid on six lease areas — the most areas ever offered in a single auction — as described in BOEM’s Final Sale Notice. Leases offered in this sale could result in 5.6 to 7 gigawatts of offshore wind energy.
The White House’s goal to install 30 gigawatts of offshore wind by 2030 is complemented by state offshore wind policies and actions throughout the Northeast and Mid-Atlantic, Interior noted in a news release.
Collectively, New York and New Jersey have set the nation’s largest regional offshore wind target of installing over 16 GW of offshore wind by 2035.
According to Interior, the New York Bight offshore wind auction will include several innovative lease stipulations designed to promote the development of a robust domestic U.S. supply chain for offshore wind and enhance engagement with Tribes, the commercial fishing industry, other ocean users, and underserved communities. The stipulations will also advance flexibility in transmission planning.
The Sale Notice also requires lessees to identify Tribes, underserved communities and other ocean users who could be affected by offshore wind development.
More information about the auction, lease stipulations, list of qualified bidders for the auction and Interior’s collaboration with New York and New Jersey can be found on BOEM’s website.
NREL Report Assesses Value In Managed EV Charging Strategies
January 12, 2022
by Peter Maloney
APPA News
January 12, 2022
Managed electric vehicle charging offers “significant potential benefits for the grid,” such as demand side flexibility, according to a new report from the National Renewable Energy Laboratory (NREL).
The NREL researchers conducted a literature review of research papers on the potential value of electric vehicle charging to better understand how electric vehicles and the electric grid can work together as the electric and transportation sectors become more intertwined.
The simplest form of electric vehicle managed charging—sometimes called smart charging – is time-of-use pricing that offers lower electricity rates to charge an electric vehicle during off-peak periods. More sophisticated managed charging plans control charging based on a user’s travel needs and grid conditions. In the most sophisticated managed charging systems, electric vehicles can act as temporary electricity suppliers by sharing power back to the grid.
The report, published in Energy & Environmental Science, summarizes findings from hundreds of studies considering multiple value streams for the power system, enablement costs, and perspectives of different stakeholders, including utilities, electric vehicle owners, charging station operators, and rate payers.
“Managed charging can be a tremendous resource for the grid but there are trade-offs to solutions at different levels of commercial readiness,” Matteo Muratori, NREL analyst and principal investigator of the study, said in a statement. “Some solutions offer a wider range of grid services and value streams but require increasingly complex communication and control technology and demands on users, which come with a cost.”
Among the benefits, the NREL researchers identified decreased emissions, improved reliability, support for large-scale deployment of variable generation, and lower power system costs. “Some studies show that EV managed charging could provide thousands of dollars of value per EV every year,” the researchers said.
Although the power system will likely require upgrades to handle higher levels of electric vehicle charging, managed charging has the potential to improve system efficiency and lower average retail electricity rates for all consumers, not just electric vehicle owners, the researchers found. Managed charging is particularly valuable in systems with high levels of variable renewables to provide flexibility to match supply and demand, they said. In contrast, power system cost savings from managed charging is lower in systems with other sources of flexibility, they added.
The strategy used to deploy electric vehicle charging stations can change the benefits available to the grid. If electric vehicle managed charging is based solely on minimizing owner costs with no consideration of the grid, “it could negatively impact system cost and operation,” the NREL researchers said.
In addition, the benefits of managed charging for distribution systems are more difficult to nail down, the researchers found. “Distribution system issues are location and system-specific, so it’s very hard to generalize insights,” Muratori said.
Overall, managed charging can noticeably reduce distribution system peak loads and congestion across the board, but more modeling and analysis is needed in collaboration with utilities, the researchers said. They also warned that the enablement and implementation costs in the report are “highly uncertain due to limited market implementations and a lack of scale.”
Many questions about the potential value of electric vehicle managed charging remain to be answered, the NREL researchers said. Among other things, they recommended a complete benefit-cost assessment that considers the entire extent of value streams for the power system, enablement costs, and the perspectives of all stakeholders.
Connecticut Municipal Electric Energy Cooperative Transfers Plant Ownership
January 12, 2022
by Paul Ciampoli
APPA News Director
January 12, 2022
The Connecticut Municipal Electric Energy Cooperative (CMEEC) recently transferred ownership of its Alfred L. Pierce 84-megawatt electric generating facility located in Wallingford, Conn., to MPH AL Pierce LLC.
MPH AL Pierce LLC is a Delaware limited liability company that is indirectly owned by affiliates of Hull Street Energy (HSE), a private equity firm.
CMEEC CEO Dave Meisinger noted that since its repowering in 2007, the Pierce plant has been a valuable project for CMEEC and its members, but added that the continued operation of the plant was no longer projected to provide the same wholesale rate stability and overall benefits that CMEEC’s members have come to expect.
“The sale of the Pierce plant is an important step in the alignment of CMEEC’s mission to add economic value to the communities we serve while thoughtfully addressing the impacts of climate change,” he said.
“We are confident that HSE will operate the plant in a manner that will contribute to the reliability of the New England electric grid as our wholesale market structure continues to evolve in response to regional decarbonization goals.”
The parties had previously announced the signing of the asset purchase agreement on October 8, 2021.
CMEEC is a political subdivision of the State of Connecticut created in 1976.
It is a non-profit municipal joint action electric supply agency that provides the power supply requirements, at wholesale, of six municipal electric utilities with retail electric service territories in Connecticut as well as for other customers who purchase power at wholesale.
Its municipal electric utility members are Bozrah Light & Power, Jewett City Department of Public Utilities, Groton Utilities, Norwich Public Utilities, South Norwalk Electric and Water, and The Third Taxing District of Norwalk Electric Division.