APPA-Funded Study Provides Strategy For Optimal Renewable Power Bids
January 20, 2022
by Peter Maloney
APPA News
January 20, 2022
A new American Public Power Association-funded study has brought small- and medium-size utilities one step closer to confidently offering and purchasing renewable energy products on wholesale power markets.
In many wholesale power markets, utilities with a real time production shortage from cleared day-ahead bids must purchase products in the real-time market to make up the shortage. It’s no surprise, then, that wind and solar resources are not currently eligible to provide ancillary services in many electricity markets: their intermittency and the uncertainty of forecasts surrounding these products leads to expensive shortages for utilities.
This is true in the Southwest Power Pool (SPP), which PhD candidate Anne Stratman has researched as part of her studies in electrical engineering at the University of Nebraska-Lincoln’s Power and Energy Systems Lab. Stratman’s current research focus is refining a model that utility operators with renewable energy resources in their portfolios can use to participate more fully in wholesale power markets. Her recent project, Providing System Reserves with Renewable Resources in the Southwest Power Pool Market, offers a glimpse into a future where renewable-based energy systems can provide system reserves using wind and solar resources. This work was partially funded by the American Public Power Association’s Demonstration of Energy & Efficiency Developments (DEED) program.
As a basis for her research, Stratman pulled from Southwest Power Pool and National Renewable Energy Laboratory databases to gather historical data for day-ahead energy and reserve prices, real-time prices, and wind and solar power production. Data collection centered on a location near Beatrice, NE, an area within Nebraska Public Power District (NPPD)’s service territory. Roman Estrada of NPPD offered a utility perspective to Stratman’s research as her DEED project sponsor.
“Through discussions with my NPPD sponsor, I gained valuable insights into current industry practices and challenges faced by small to medium utilities. These discussions were helpful in bridging the gap between academic theory and industry practice and ensuring the model would be useful to utilities,” said Stratman.
Stratman used Beatrice, NE-area price and production datasets to develop a stochastic optimization model for utilities with wind and solar resources that could calculate curves for bidding into markets for different products: namely, energy, spinning reserves, up regulation, and down regulation. Stochastic optimization was used as a low-cost method to consider many different forecast scenarios, adjust for uncertainty, and formulate an optimal bidding strategy in all possible scenarios.
The resulting model suggested that the best approach for wind and solar resources produced in the region would be to offer, on average, about 5 percent of forecasted power output on the day-ahead market and 95 percent on the real-time market. The average product distribution for wind power, in the day-ahead and real-time markets combined, was 84 percent energy, 0.5 percent spinning reserves, 3.5 percent up regulation, and 12 percent down regulation. For solar power, the average product distribution was 91 percent energy, less than 1 percent spinning reserves, 3 percent up regulation, and 6 percent down regulation, Stratman’s report said.
Additionally, Stratman reviewed case studies and found that by offering several types of products, some with much lower real-time prices than others, a utility would likely be able to avoid real-time penalties by offering less expensive products when forecast uncertainty is high.
“Based on the project results and my dissertation research up to this point, I’ve observed that offering reserve products can allow utilities with highly uncertain generation resources to hedge against the risk of large real-time deviation penalties, compared to only participating in the energy market. Usually, it’s only necessary to offer small quantities of reserve products to reduce risk significantly. However, the tradeoff between profit and the need for reliable reserve commitments should also be considered. Hopefully, this project provides a steppingstone towards greater use of wind and solar resources in reserve markets as forecasting methods improve,” said Stratman.
In the future, Stratman plans to write a conference paper about the model developed in the project that would use a forecasting model to generate prices and wind and solar power scenarios, instead of using historical data as scenarios. There is much less variation in scenarios generated using forecasting models than in scenarios that use historical data, meaning that day-ahead bids would not exceed forecasts, the report said.
DEED members interested in experimenting with Stratman’s model are in luck: as part of her research, she developed a simple MATLAB code and a user guide for use by small and medium utilities with wind and solar resources. This software is applicable for utilities participating in any of the organized independent or regional wholesale markets. The software is available to members of APPA’s R&D community via the DEED Project Library.
Non-DEED members interested in learning more might like to stop by the DEED booth at the American Public Power Association’s Engineering & Operations Conference, where a research poster (and perhaps the researcher herself!) will be available to answer follow-up questions. Additional details about the DEED program are available here.
Energy Storage Could Support Majority Renewable Future: NREL Study
January 20, 2022
by Peter Maloney
APPA News
January 20, 2022
Energy storage, particularly diurnal storage, can play an important role in providing resource adequacy in future scenarios where renewable energy is the dominant form of generation, according to a new report from the National Renewable Energy Laboratory (NREL).
The study, Grid Operational Impacts of Widespread Storage Deployment, is the sixth and latest in NREL’s Storage Futures Study, a series of studies on the role of energy storage in maintaining a resilient and flexible electrical grid through 2050.
Past NREL studies in the series had shown the potential for between 213 gigawatts (GW) and 932 GW of energy storage by 2050 and, even in the most conservative scenario, in excess of 125 GW.
In the new study, NREL used 213 GW as a reference case and the most likely mid-range for energy storage installations. The study also modeled around a scenario in which 74 percent of electric output would be generated by wind and solar power by 2050.
“We really wanted to look at the effects of higher levels of deployment,” Jennie Jorgenson, principal investigator of the study, said.
Starting with its Regional Energy Deployment System (ReEDS) model that shows least-cost scenarios for energy storage under a range of cost and performance assumptions, NREL took the next step by testing that model to see how energy storage would perform under on an hourly basis.
“Overall, we find that the high storage (and often high variable generation) power system scenarios envisioned in ReEDS successfully operate with no unserved energy and low reserve violations, showing no concerns about hourly load balancing through the end of 2050,” the researchers wrote in the study. “Unserved” energy in the report refers to dropped load.
“We once again find that the potential future energy system with large quantities of energy storage could successfully balance load 24/7,” Jorgenson said in a statement. “On top of that,” she said, “we find power systems with high levels of energy storage operate more efficiently by storing otherwise unused renewable energy to displace costly generation from other sources.”
The study found the charging and discharge cycles of energy storage are well aligned with the diurnal cycles of solar power. Wind power, on the other hand, is less well aligned with daily cycles and often experiences periods of overgeneration that can last many hours or days, which is much longer than the storage durations in the study. Energy storage can play a key role in utilizing energy from both solar and wind power, but the synergies with solar power are more consistent, the researchers found.
The study also found that energy storage can increase the efficiency and lower the emissions of a power system by using wind or solar overgeneration to displace coal and natural gas-fired generation.
Energy storage also, more often than not, encourages higher utilization of transmission assets, the researchers found, but cautioned that further study would be needed to understand the interaction of storage and transmission assets.
“Collectively, the results of this and previous Storage Futures Study analysis show the growing opportunity for diurnal storage (that is, storage with up to 12 hours of duration) to play an important role in future power systems,” the researchers wrote.
Greater deployment of diurnal storage can increase efficiency of operations by reducing overgeneration, decreasing generator starts and emissions, and increasing utilization of the transmission system, they said.
Energy storage can also play “an important role in providing capacity during the top net load hours. Future work could examine the role of longer-duration storage resources, especially under highly decarbonized grid conditions, such as those approaching 100% clean energy,” the researchers said.
NREL is planning a free webinar on its new study on Jan. 25. There will also likely be a final synthesis report on NREL’s energy storage series in the next month or so, Jorgenson said.
APPA Members Encouraged To Apply For Sue Kelly Community Service Award
January 19, 2022
by Vanessa Nikolic
APPA News
January 19, 2022
Member utilities of the American Public Power Association (APPA) are encouraged to apply for the Sue Kelly Community Service Award. The deadline for nominations is Jan. 31, 2022.
APPA’s Sue Kelly Community Service Award recognizes “good neighbor” activities that demonstrate the commitment of the utility and its employees to the community. Any APPA member utility that has not received the award in the past five years is eligible.
Nominees should have achievement or sustained performance showing commitment by the utility and its employees to enhancing the quality of life in the community through activities that: address a community need or improve the community’s social, cultural, educational, or economic environment; and provide an opportunity for employee involvement.
Award winners are selected by a board committee of APPA. Recipients will be recognized at APPA’s National Conference in June.
The 2021 Sue Kelly Community Service Award recipients are EPB of Chattanooga, Tennessee, North Carolina public power utility Fayetteville PWC, Wisconsin’s Kaukauna Utilities (KU), Washington State’s Mason County Public Utility District (PUD) 1, and the City of Philippi in West Virginia.
Not long after the COVID-19 pandemic began, EPB joined a local school district and other community partners to launch a program that provided high-speed fiber optic internet services to every economically disadvantaged K-12 student in the county at no charge. As a result, the program was made available to more than 28,000 students.
KU and Mason County PUD 1 focused on providing pandemic relief in its communities. KU donated $30,000 to area non-profits that help community members in need with rent or mortgage payments and other expenses. Mason County PUD 1 implemented a COVID-19 response program to safeguard employee health, customer health, and the continuity of utility services for its customers by suspending all disconnections, fees, and rate increases, offering long-term payment plans for any customer that kept in communication with them.
The City of Philippi’s Municipal Electric Department supported its community’s overall economic growth by taking part in various beautification projects like lining its historic downtown’s buildings with lights.
Fayetteville PWC partnered with the city’s downtown district to bring an interactive public art installation to light up the area after the city reopened following the COVID-19 shutdowns.
“It’s an honor to be recognized by APPA for the activities that we have been committed to for so many years- giving back to our community,” Fayetteville PWC Communications/Community Relations Officer Carolyn Justice-Hinson said. “We have continued to find ways to support our community in powerful ways despite COVID limiting many in-person service projects.”
Justice-Hinson said Fayetteville PWC encourages its staff to volunteer by looking for community service opportunities that fit its employees’ interests and abilities. The public power utility promotes and organizes many service events such as the ‘Field of Honor’ flag setup and takedown for Veterans Day and a community cleanup coordinated in conjunction with APPA’s Day of Giving.
Additional details about the award are available here.
Tennessee Valley Authority Solicitation Seeks Swine Renewable Energy Credits
January 18, 2022
by Paul Ciampoli
APPA News Director
January 18, 2022
The Tennessee Valley Authority (TVA) is seeking offers for up to 2,000 swine renewable energy credits (RECs) that meet the North Carolina Renewable Energy and Energy Efficiency Portfolio Standard.
Offers must be submitted through the TVA website by Feb. 15, 2022 and TVA is seeking RECs for Compliance Year 2021.
Swine RECs are associated with electricity generated by swine-waste fueled electric generating facilities properly registered with the state of North Carolina, TVA said.
TVA said it is investing in swine RECs “to support innovative solutions for cleaner energy to promote economic development opportunities in North Carolina.”
It noted that in fiscal year 2021, TVA’s economic development efforts supported record-breaking job creation — nearly 81,000 jobs and more than $8.8 billion in capital investment attracted to its seven-state service region.
Currently, TVA has over 8,000 megawatts of renewable energy in its portfolio.
TVA’s request for offers is posted at www.tva.com/information/doing-business-with-tva.
MEAG Power Formally Joins Southeast Energy Exchange Market
January 18, 2022
by Paul Ciampoli
APPA News Director
January 18, 2022
The Municipal Electric Authority of Georgia (MEAG Power), a nonprofit, statewide generation and transmission organization, has joined the Southeast Energy Exchange Market (SEEM) effective Jan. 13, 2022.
The new SEEM platform will facilitate sub-hourly, bilateral trading, allowing participants to buy and sell power close to the time the energy is consumed, utilizing available unreserved transmission. Participation in SEEM is open to other entities that meet the appropriate requirements.
Other founding members of SEEM include Associated Electric Cooperative, Dalton Utilities, Dominion Energy South Carolina, Duke Energy Carolinas, Duke Energy Progress, Georgia System Operations Corporation, Georgia Transmission Corporation, LG&E and KU Energy, N.C. Municipal Power Agency No. 1, NCEMC, Oglethorpe Power Corp., PowerSouth, Santee Cooper, Southern Company and TVA.
Santee Cooper, South Carolina’s state-owned electric and water utility, joined SEEM effective Jan. 4, 2022.
The founding members represent nearly 20 entities in parts of 11 states with more than 160,000 megawatts (MW) (summer capacity; winter capacity is nearly 180,000 MW) across two time zones. These companies serve the energy needs of more than 32 million retail customers.
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.