APPA’s Schryver details rise in municipalization interest, resources offered by APPA
May 24, 2021
by Paul Ciampoli
APPA News Director
May 24, 2021
There has been an increase in the number of communities exploring the public power option, a trend that has been driven by a number of factors including reliability, the desire for renewable energy options and increased economic development, said Ursula Schryver, Vice President, Strategic Member Engagement and Education, at the American Public Power Association (APPA) during a recent hearing held by Maine state lawmakers.
Schryver, who made her comments at a May 20 hearing held by the Maine Legislature’s Energy, Utilities, and Technology Committee, also detailed the resources that APPA offers when it comes to municipalization.
The Maine committee hearing focused on a bill, LD 1708, which would create a consumer owned utility that would take over the electric service now provided by Central Maine Power and Versant Power. Central Maine Power Company and Versant Power (formerly known as Emera Maine), are majority owned by Iberdrola of Spain and Emera of Canada, respectively.
In late April, a bipartisan group of legislators in Maine announced plans to introduce the legislation. Together, the two investor-owned utilities in Maine serve 96.2 percent of the state’s residential load and have 963,187 residential customers, according to state regulators. The remaining residential load is served by public power utilities – or consumer-owned utilities, as they are known in Maine – and electric cooperatives.
“Our new bill, ‘An Act to Create the Pine Tree Power Company,’ will allow us to control our own money and our own energy destiny — to advance fast and fairly toward our own clean energy and connectivity future,” Democratic Rep. Seth Berry, sponsor of the bill and House Chair of the Energy, Utilities and Technology Committee, said in a statement last month.
At the hearing, Schryver noted that her comments were neither for or against the legislation “primarily because APPA doesn’t weigh in on decisions made by individual communities.” APPA, she noted, serves as a resource and APPA believes that every community needs to make a decision that is right for itself.
In terms of municipalization, “we believe it’s important that communities have all the information on the benefits of public power, the process, the impacts to the community, to make an informed decision for their community or their region,” she told the state lawmakers.
“We can serve as a resource from a national perspective including municipalization trends, the process, hurdles we typically see related to municipalization efforts and obviously talk about public power and successful public power examples,” Schryver said at the hearing.
“Over the last several years we have seen an increase in the number of communities exploring the public power option,” she said, noting that interest has actually been very consistent over the past several decades. “Dozens of communities contact APPA for information on public power and on the municipalization process every year,” Schryver said.
The reasons differ, she noted. “In recent years it has really been driven by the desire for renewable energy options, more environmentally friendly options or increased economic development,” she said. Rates and reliability are often common driving factors, Schryver said. “There’s often interest after a storm when the incumbent utility responds poorly,” the APPA official said.
In terms of the number of new public power utilities that have been formed, she said that 88 have formed since 1973 and 20 new public power utilities have formed in the last 20 years, Schryver told the state lawmakers. “Several of these were greenfield developments where a new utility was created in the service territory of an investor-owned utility.”
Schryver said that while there are a lot of ongoing discussions, changes in utility ownership are rare. “Often, once these discussions begin, the incumbent utility fights the effort with expensive PR campaigns, with legal battles and often they will offer concessions to encourage the community to end the initiative, which, in some cases, may be in the best interest of the community,” she said. “Once again, that’s a local decision.”
APPA offers a variety of resources related to municipalization including the Public Power for Your Community guidebook and case studies on municipalization. Additional information is available here.
Parties voice support for legislation
In written testimony for the hearing, Stephanie Clifford, Campaign Manager for Our Power, said that the Pine Tree Power Company “will be transformational for our state because it will put us in control of our energy future.
A consumer-owned utility “operates for the benefit of its ratepayers, that’s you and me. It is run locally by Maine people, with its profits being reinvested in our communities, instead of into the pockets of foreign investors and foreign governments,” she said.
The Solar Energy Association of Maine (SEAM) also voiced support for the bill.
Steve Weems, Executive Director of SEAM, said in written testimony that establishing the Pine Tree Power Company offers a superior alternative to investor-owned utilities. This is due to the structure of this proposed statewide consumer-owned utility, he said.
“First, Pine Tree Power (PTP) would be a not-for-profit corporation, controlled by an elected board of seven elected Maine directors,” which offers a number of fundamentally important positive distinctions from the investor-owned utility model, Weems said.
Among other things, he said that PTP’s municipal not-for-profit legal structure would provide PTP “with access to tax-exempt revenue bonds. Access to tax-exempt revenue bonds would reduce PTP’s cost of capital to one-half or less than the capital used by IOUs. This is why PTP would save electric ratepayers $5-10 billion dollars over the next 30 years.”
Program uses network of residential storage batteries to help balance New England grid
May 22, 2021
by Paul Ciampoli
APPA News Director
May 22, 2021
A new program from Vermont-based Green Mountain Power (GMP) marks the first time that stored energy in a network of residential batteries is being used to help keep the regional grid balanced, GMP said on May 13.
GMP’s new frequency regulation pilot program allows customers to share stored energy with regional grid operator ISO New England (ISO-NE) to keep a steady, regulated flow of energy on the grid at all times, a critical function for regional system safety and reliability for customers, GMP said.
It noted that ISO-NE is continually calling on qualified regional energy producers to increase or decrease output to help maintain that important balanced flow of power on the grid at all times. Typically, this cycling on and off of energy is done by ISO-NE with fossil fuel generators through the regulation market, a wholesale energy market that also pays participants for their consistent, quick, and accurate responses to grid needs, which can shift minute-to-minute.
Using their network of Powerwall batteries and Tesla Autobidder software, GMP is the first utility to perform this key grid service in the wholesale power market with stored energy distributed from customers’ homes. The project is also benefitting all GMP customers through reduced power supply costs, according to GMP. It creates a new value stream for all GMP customers in addition to the ongoing benefits of GMP’s earlier home energy storage programs, GMP said.
GMP successfully entered the regulation market with this network of residential power sources after three months of testing with ISO-NE, and partnerships with ISO-NE, Tesla and Customized Energy Solutions (CES), a software solutions company. Tesla coordinates the distributed batteries to respond to signals from ISO-NE and aggregates critical data about the response, while CES provides the key integrations between Tesla and ISO-NE.
A total of 200 GMP customers are currently enrolled in the program and a prerequisite is that they already have two Powerwall batteries through a GMP program.
GMP plans to expand this pilot program in the future. Customers sharing energy through the program are paid $13.50 per month on their energy statements. This includes a share for their program participation and for the increased use of their batteries, which can charge and discharge rapidly for periods of time each month.
GMP takes steps to ensure that customers have backup power available if weather is predicted to cause outages.
In 2017, GMP was the first utility to partner with Tesla, and launched the first Powerwall pilot program.
GMP is now the first utility with tariffed home energy storage programs for customers. These programs provide participating customers with backup power in residential batteries in exchange for sharing some of that stored energy to reduce peak demand on the grid.
There are about 3,000 Powerwalls installed in customers’ homes, and GMP’s network of stored energy, including Powerwalls, car chargers, and utility-scale batteries, helped reduce costs for customers by more than $3 million in 2020 through peak reduction, according to GMP.
GMP serves approximately 266,000 residential and business customers in Vermont.
OPPD Board names Javier Fernandez as the utility’s next President and CEO
May 21, 2021
by Paul Ciampoli
APPA News Director
May 21, 2021
The Omaha Public Power District (OPPD) Board of Directors on May 20 named OPPD Vice President and Chief Financial Officer Javier Fernandez as the utility’s next President and Chief Executive Officer.
Timothy Burke announced in March that he will retire at the beginning of July.
Fernandez will assume the role July 1. His selection comes after a stakeholder outreach effort in which the utility asked employees, customers, and community leaders what they would like to see in our next CEO. The board asked for this input during its monthly meeting in March, and surveys were submitted at OPPDCommunityConnect.com. Comments were also received via OPPD.com. Directors received feedback from more than 1,000 stakeholders.
During a special board meeting held April 28, directors announced they had selected Fernandez as the sole finalist of five internal applicants to move forward in their selection process. OPPD held a virtual public meet and greet event May 10, to allow the public an opportunity to get to know him better, OPPD said.
“Fernandez has been a steady hand for OPPD, both in terms of financial guidance and navigating times of crisis,” OPPD said. He helped lead the utility’s response to historic flooding in 2019, when the utility’s business continuity plan was activated. He has been doing so, again, throughout the COVID-19 pandemic, OPPD noted.
Fernandez, 46, joined the utility in June 2017. He came to OPPD from the Bonneville Power Administration. He had been with the federal power marketing administration since 2012, most recently serving as executive vice president and chief financial officer.
Previously, he served as senior vice president of Fixed Income Capital Markets for D.A. Davidson & Company and vice president of Public Finance for Seattle-Northwest Securities Corporation, where he performed public finance banking and financial advisory services to municipal jurisdictions, primarily in Oregon.
Fernandez holds a bachelor’s degree in Economics from Instituto Tecnológico Autónomo de México (ITAM) in Mexico City, a master’s degree in Business Administration from Yale University, a Utility Management Certificate from Willamette University, and a Utility Executive Certificate from the University of Idaho.
He currently serves on the Federal Reserve Bank of Kansas City Board of Directors for the bank’s Omaha branch. He is one of three directors appointed to serve who work outside of the banking industry. He also serves on the boards of directors for Habitat for Humanity and Bellevue University.
Co-locating solar and storage can pay off, Lawrence Berkeley study says
May 21, 2021
by Peter Maloney
APPA News
May 21, 2021
Coupling battery energy storage with renewable energy projects is more economically attractive than the independent siting of batteries and renewable resources, according to a new study from Lawrence Berkeley National Laboratory.
The study, Are coupled renewable-battery power plants more valuable than independently sited installations?, found that the value of adding a 4-hour battery sized to 50 percent of renewable-plant nameplate capacity is $10 per megawatt hour(/MWh) on average across all Independent system operators (ISOs). The study found the value of batteries and renewables deployed independently to be $22.5/MWh, indicating a $12.5/MWh “penalty” for co-locating a project.
The study attributed the penalty to the greater flexibility in siting and operation. For example, batteries co-located with solar projects are eligible for a federal Investment Tax Credit (ITC) but are penalized if they are not charged by those solar panels.
However, the co-location penalty is tempered by potential cost savings of around $15/MWh in the form of construction cost savings and use of the ITC for co-located battery projects, which “outweighs our estimated coupling penalties,” the authors said, “making coupled project development more attractive than independent siting of battery and [intermittent renewable] technologies on average.”
The authors also emphasized the importance of regional variations in determining the value of renewable and battery storage projects. California, for instance, is one of the most attractive locations for co-location. There, the value of adding storage to a solar project averages $15/MWh, the study found.
In California, batteries can partially offset the decline in the value of solar power that results from high solar penetration. “As other regions increasingly install solar, they may demonstrate greater interest in solar-battery projects as well,” the study’s authors said.
Regional variations in prices and regulations also affect the value of potential coupling penalties, suggesting that “the tradeoff between coupling penalties and savings will vary by situation,” the authors said. Therefore, “roles exist for independent and coupled projects from a system optimization perspective.”
There is also reason to believe that “real-world coupling penalties” will tend to be lower than the default-case penalties in the study, the authors said. Developers’ choices in project design, such as grid charging, can reduce the coupling penalty by about $5/MWh, they said.
In the study, the authors set out to address the fact that prior research on the value and cost savings of resource coupling did not consider the geographic constraints of co-location.
So, they studied how pricing volatility differences between nodes within electricity markets impact the system value of coupled renewable-battery projects compared with independently sited renewable and battery installations. The study used wholesale power market prices from 2012 to 2019 across the seven main ISOs.
The study did not address system values not currently priced in wholesale markets, such as the benefits of mitigating dynamic stability issues in weak grids, but the authors noted “these can be another important reason to site storage near renewables.”
The authors also noted that as storage technologies continue to develop, many questions will remain, such as how values will change under high levels of penetration of both solar and storage resources. They also noted that although ancillary service markets currently play a small role in wholesale power markets, they could become increasingly important as renewable resources continue to proliferate.
In current markets, developers can mitigate the “coupling penalty” by considering “alternative approaches to integrating battery storage,” the authors said. “This result implies that renewable-battery power plants will play an increasing role in electricity systems if they can be built for $2/MWh to $13/MWh less than independent projects of comparable size.”
Preparing to be resilient in hurricane season
May 21, 2021
by Kenneth Stinson
APPA News
May 21, 2021
When Hurricane Laura swept through in August 2020, our town was devastated. Laura is tied for being the strongest hurricane on record to make landfall in Louisiana — a more powerful storm than Hurricane Katrina — and hit right on our community in the southwest corner of Louisiana.
In addition to all the debris and destruction of homes, businesses, and our local distribution system, about 12 miles of transmission lines that fed ours and surrounding communities were lying on the ground after Laura passed through. Our entire system was out.
Initial estimates predicted that it would take two months for the transmission to come back up. Fortunately, we were able to get most people back on in what I would consider record time – given the extent of the damage – about two-thirds were back within two and a half weeks, and a full restoration of power to everyone that could take it a week after that.
The event hit home the importance of preparedness planning, and some key traits about what it means to be resilient.
Always planning
Given our location, we take steps to prepare for hurricane season every year.
Since the 2005 season, which included Hurricanes Rita and Katrina, we have held a yearly staff meeting to kick off the season and make sure we have everything lined up that we need.
Sometimes, when a number of years go by without needing to enact a significant storm response, policies can start to get a little more relaxed. And every storm is different and comes with its own nuances.
There are some things we do every year – such as lining up supplies – in advance of the season. We always buy food and plenty of water and Gatorade so that we know employees will have enough to eat and to stay hydrated while working on restoration. We all know that the closer we get to a predicted storm, the tougher it can get to procure these items. So if we see a possible storm coming, even if it’s still far out, we order a pallet of water – and even if the storm doesn’t come to us, we’ll use it anyways year-round.
Aside from the strength of the storm, Laura also struck us in the middle of the COVID-19 pandemic, which presented some added and interesting challenges.
In the past, when we had a predicted storm approaching, we’d be sure to have employees lined up to work throughout the restoration. Last year, we also had to plan out how to house employees and any visiting mutual aid crews given everything that was closed for the extra safety precautions. As it happened, in the aftermath of Laura, I slept on an air mattress in my office.
Another big area of preparation is making sure we have all the necessary contracts and paperwork in place to be ready to get the help we might need and to follow the appropriate rules and processes for reimbursement from the Federal Emergency Management Agency.
We hired a consulting company to monitor our contracts and manage interactions with FEMA. For us, it made sense to hire a consultant because if you don’t do this all the time, then you don’t appreciate how FEMA might want everything done – how information should be presented, which forms you need. These interactions, and the documentation you need to keep, can be very long-term. With Hurricane Rita, we had FEMA coming back with questions or needing details as much as 12 years after the storm. As we were going through an administration change July 2021, we didn’t want to add another burden to the new administration.
When we knew Hurricane Laura was coming, one thing we knew we’d need was to have a debris contract in place. Having the debris contract in place in advance, issued following FEMA’s contract process and rules, helps expedite the clearing for the trees and other debris that create a lot of problems in restoration. With Laura, we had to clear almost 153,000 cubic yards of debris.
Planning is also about doing the important work in blue-sky times. During this “off” time, we look at repairing and replacing poles. About five years ago, we changed some distribution lines, and those didn’t have any problem during the storms. If they had been wooden poles, they would have added to our immediate repair needs following Laura.
Being networked
A major element in preparedness planning and resilience is the relationships you have.
Even if you think you are an island, geographically or otherwise, it is important to stay on good terms with anyone and any association you can – you never know who will make the difference in getting you the help you need.
This includes at the local, state, and national levels. When it comes to our electric system, we have the Louisiana Energy and Power Authority – or LEPA – a joint action agency, and then we have all the other electric companies in our region who we might call on for mutual aid. And then there’s our local emergency operations center. Nationally, being connected to the American Public Power Association through the national Mutual Aid Network also helped immensely in getting through to other national-level entities about our specific situation and needs.
Through these relationships, we were able to elevate our concerns about getting transmission reconnected – and relay some alternative ideas for what could work for our town – through the Electricity Subsector Coordinating Council, via APPA.
The storm’s path, intensity, and timing during the pandemic created added difficulties. Because it was a transmission-level issue, our efforts in the early days felt a lot like “Groundhog Day” – it felt like nothing was really changing in our morning debrief.
It took a week and a half before we started seeing progress, and having these relationships made that waiting a whole lot more bearable. The calls from APPA, LEPA, and daily morning meetings with Greg Labbe from Lafayette Utility Systems reminded me that we hadn’t been forgotten.
In the thick of it, it could be tough to get a straight answer on why we weren’t getting the resources we needed. We spent about a week trying to get a large generator, and the holdup came down to who needed to make the request – which was supposed to come from the state, not the city.
Vinton is one of six cities in the parish, and we have an executive policy group – which includes mayors, our sheriff, and a president of the Police Jury – that meets on all kinds of things. Before and after Laura, we came together to talk about our needs. This connection and model works really well in that it allows us to speak with one voice to the EOC instead of firing off independent requests and updates.
These various relationships also helped us connect and better communicate with Entergy – who was working on restoring the transmission system – on arranging for transformers and in connecting to our substation in Vinton to feed off of another transmission line.
Being part of the mutual aid network really helped us, too. We have had contracts in place in 2005, and we had LUS on standby for Hurricane Ike in 2007, but Laura was the first time we actually enacted mutual aid since then.
LUS came to our aid and were truly heroes throughout the aftermath. Since no local hotels were available, their teams went home every night – driving 90 miles every morning and night to do the work. They picked up quickly, and after a day or so, our crews didn’t have to ride along with LUS crews to figure out where and how to help. Since they do this a lot, they were also able to bring other public power mutual aid crews in from Florida and Georgia, as necessary.
To show our thanks, we had a parade in town as they drove to go home, with maybe 300 people on the streets cheering them on as they left. We also symbolically named the location where they put in the new transformer the Greg Labbe substation in recognition of his effort to resolve that issue.
Building connections
Laura also showed us the importance of being able to be connected to your community.
We encouraged people to have generators handy, but fuel was tough to find for a while after the storm and they cost a lot to run.
In advance of the storm, we urged people with special needs to leave town and stay gone until we knew the power could be back, if they were able, so that they wouldn’t face any medical issues.
As we look ahead, we are looking at building a social media presence and considering other ways to ensure our community can receive information from a central, trusted place. If your city doesn’t already have information avenues for communication for people to sign up, I encourage you to explore your options. Just like it was nice to hear from our connections at the state and national levels, it would be helpful for people to sign up so that we can push information to them and let them know what is happening.
NOAA predicts another active Atlantic hurricane season
May 21, 2021
by Paul Ciampoli
APPA News Director
May 21, 2021
The National Oceanic and Atmospheric Administration’s (NOAA) Climate Prediction Center is forecasting another above-normal Atlantic hurricane season. Forecasters predict a 60% chance of an above-normal season, a 30% chance of a near-normal season, and a 10% chance of a below-normal season. However, experts do not anticipate the historic level of storm activity seen in 2020, NOAA said on May 20.
For 2021, a likely range of 13 to 20 named storms (winds of 39 mph or higher), of which 6 to 10 could become hurricanes (winds of 74 mph or higher), including 3 to 5 major hurricanes (category 3, 4 or 5; with winds of 111 mph or higher) is expected. NOAA provides these ranges with a 70% confidence. The Atlantic hurricane season extends from June 1 through November 30.
In April, NOAA updated the statistics used to determine when hurricane seasons are above-, near-, or below-average relative to the latest climate record. Based on this update an average hurricane season produces 14 named storms, of which 7 become hurricanes, including 3 major hurricanes.
Last year’s record-breaking season “serves as a reminder to all residents in coastal regions or areas prone to inland flooding from rainfall to be prepared for the 2021 hurricane season,” NOAA said.
The American Public Power Association (APPA) offers a wide range of resources to its members related to hurricane and storms. Those resources include an All-Hazards Guidebook and a Restoration Best Practices Guidebook. APPA members can access disaster planning and response resources — including the public power Mutual Aid Network.
Moody’s affirms rating assigned to Guam Power Authority bonds, changes outlook to stable
May 21, 2021
by APPA News
May 21, 2021
Moody’s Investors Service on May 13 affirmed the Baa2 rating assigned to the Guam Power Authority’s (GPA) senior revenue bonds and changed the outlook to stable from negative.
The affirmation of the Baa2 rating and outlook change to stable follows Moody’s rating action on the Government of Guam’s general obligation bonds rating which was affirmed at Ba1 with a stable outlook on May 4, 2021, GPA noted in a news release.
Moody’s also stated GPA’s Baa2 rating reflects its strong position as the sole provider of electricity to residential customers on the island of Guam and to the US military in the report.
“We welcome this positive affirmation and improved rating of GPA’s credit-worthiness, which is good news for all ratepayers,” said GPA General Manager John M. Benavente, P.E., in a statement.
“As Moody’s has noted, there are many concurrent challenges facing GPA today. We will continue our work across all utility areas, and with governing leadership and bodies to bring the energy solutions for Guam forward, so GPA remains financially strong,” he said. “This affirmation of bond rating will translate to optimal interest rates, as GPA heads to the bond market to refinance and lower its borrowed costs,” Benavente concluded.
In honor of Asian American and Pacific Islander (API) Heritage Month – commemorated each May – the American Public Power Association’s Public Power Current newsletter recently spotlighted the leadership roles our API colleagues have at public power utilities across the United States and at our U.S. territories in the Western Pacific. We kicked off our coverage by sharing updates from Guam.
Benavente is a member of APPA’s Board of Directors.
Report lays out DOE’s vision for grid-interactive efficient buildings
May 20, 2021
by Peter Maloney
APPA News
May 20, 2021
Lawrence Berkeley National Laboratory and the Brattle Group have released a report laying out a path to accomplish the Department of Energy’s (DOE) goal of tripling the energy efficiency of buildings by 2030.
A National Roadmap for Grid-Interactive Efficient Buildings defines technology attributes, integration considerations, and barriers to achieving the full potential, adoption and deployment of grid-interactive efficient buildings (GEBs).
“Most of our buildings stand to benefit enormously from smart, connected technologies,” Kelly Speakes-Backman, acting assistant secretary for energy efficiency and renewable energy at the DOE, said in a statement. “Grid-interactive efficient buildings are designed to avoid the high costs and disruptions associated with peak demand and grid stress. Through clean, on-site power generation and cutting-edge efficiency measures, we can massively reduce the carbon footprint of the buildings sector.”
Combining smart technologies and distributed energy resources with energy efficient buildings, grid-interactive efficient buildings can provide comfort and convenience for building occupants, sell services to the power grid, and cut costs and pollution, the report’s authors said.
The report identifies grid-interactive building technologies such as efficient lighting and appliances that reduce electricity demand, load shedding applications that allow buildings to reduce demand during peak periods, load shifting software, batteries or other devices that allow a building to maintain grid frequency or to control voltage, and power generating sources such as rooftop solar panels.
The report found that over the next two decades, grid-interactive efficient buildings could deliver between $100 and $200 billion in savings to the U.S. power system and cut carbon dioxide emissions by 80 million tons per year by 2030, or 6 percent of total power sector CO2 emissions.
The DOE has scheduled a webinar on the Grid-interactive efficient building roadmap for May 27. News and events about the GEB initiative is available here.
The General Services Administration recently published a complementary blueprint for practical guidance and tools to integrate GEB technologies into federal energy savings performance contracts and has committed to 100 percent renewable energy for all federal buildings by 2025.
Legislation amends tax credit proposal to include public power utilities
May 20, 2021
by Paul Ciampoli
APPA News Director
May 20, 2021
Rep. Earl Blumenauer, D-Ore., has amended and reintroduced legislation from the 116th Congress to allow entities with little to no tax liability to still take advantage of energy-related investment tax credits (ITC) and production tax credits (PTC).
The bill in the 116th Congress, which ended on Jan. 3, 2021, had allowed for the transfer of such tax credits to other project partners.
The Renewable Energy Incentive Act introduced on May 13 would instead allow for the direct payment of energy-related ITC and PTCs as refundable tax credits. The bill has also been modified to include public power utilities as eligible entities.
In a May 13 letter to Blumenauer, Joy Ditto, President and CEO of the American Public Power Association, expressed thanks to the lawmaker “for working to ensure that the Renewable Energy Investment Act will allow all electric utilities, including public power utilities, to benefit from incentives intended to encourage critical energy investments needed to transition to cleaner generating technologies. This will make these incentives fairer and more effective.”
Ditto noted that federal tax expenditures are the primary tool Congress uses to incentivize energy-related investments. However, such incentives do not work for tax-exempt entities, such as public power utilities. “That means public power utilities are deterred from owning such facilities as a direct result of federal policy — and explains why 80 percent of the nation’s (non-hydropower) renewable energy generating capacity is owned by merchant generators,” she wrote.
The Renewable Energy Investment Act “is designed to address this inequity by allowing for the direct payment of energy production and investment tax credits to any entity that owns the project. This would remove the financial disincentive for public power utilities to own such facilities, which are needed to transition to cleaner generating technologies and address climate change, and would allow the full value of these credits to pay for additional investment or be passed on to our 49 million customers,” Ditto said.
Rochelle Municipal Utilities in Illinois breaks ground on new substation
May 19, 2021
by Peter Maloney
APPA News
May 18, 2021
The City of Rochelle and Rochelle Municipal Utilities in Illinois have broken ground for a $13.8 million substation to serve new industrial growth.
The substation will provide 34.5 kilovolt (kV) and 13.8 kV service to support growth in the city’s southern corridor and increase reliability for nearby industries and create the ability for businesses to have redundant electrical feeds.
The City of Rochelle purchased just over 16 acres for the construction of a new substation in 2019.
The substation will also introduce a new voltage class so the city can provide electricity to larger users. In another first, the substation project was split into two yards with the distribution yard owned and operated by Rochelle Municipal Utilities and the transmission yard owned and operated by investor-owned Commonwealth Edison.
Last June, the City of Rochelle sold its transmission assets to Commonwealth Edison. The transaction included about 20 miles of 138-kV lines and associated facilities at the utility’s No. 2 substation.
Commonwealth Edison already had the personnel and equipment needed to maintain and operate the assets as its transmission system surrounds the Rochelle Municipal Utilities’ facilities, allowing Commonwealth Edison to reduce Rochelle’s annual operating costs. Rochelle Municipal Utilities owned and operated the transmission lines since August 1, 2015.
“For a community of our size to be home to three electrical substations is unheard of,” Mayor John Bearrows said in a statement. “The investment our community is making in reliable power for residential, commercial and industrial customers is key to our future growth.”
“Funding project of this magnitude is only possible with the foresight of our Mayor, Council and Staff,” City Manager Jeff Fiegenschuh said in a statement. “Our financial management is top notch and as a result, we can provide the infrastructure to attract development and create jobs.”
Rochelle, about 80 miles West of Chicago, has a population of about 10,000 people and is known as the Hub City because several transportation routes, including two major railroads, pass through the city.