Garden City, Kansas, Buys T&D Facilities, Marking Final Major Step For Power System Revamp
January 27, 2022
by Paul Ciampoli
APPA News Director
January 27, 2022
Garden City, Kansas, recently purchased transmission and distribution facilities from a rural electric cooperative, marking the final major step that the city has taken as part of revamping the city’s electric system.
Garden City’s public power utility was established in 1914 and currently serves 11,500 meters. The utility has a Platinum Reliable Public Power Provider rating from the American Public Power Association.
Before January 2014, Garden City was a full-requirement customer of the local electric cooperative for power supply and had been for over 30 years.
However, on January 1, 2014, Garden City began receiving all of its power supply needs from the Kansas Municipal Energy Agency (KMEA), which included the installation of 27 megawatts of natural gas generation at the Jameson Energy Center located in Garden City.
The move to KMEA has saved the city millions of dollars per year in power supply expenses. But the city was still paying the local electric cooperative a local access charge of $500,000 per year for 115-kV transmission access.
In 2017 and 2018, Garden City made plans to construct transmission lines and substations for access to the 115-kV transmission system, additional capacity, and better reliability.
In the spring of 2019, the local electric cooperative offered to sell portions of its system that would provide the city access to the 115-kV transmission system at a lesser cost than building new which would have created some stranded investments for the cooperative.
The city had offered to purchase some of the facilities years before, but those offers were not accepted.
Garden City ultimately agreed to purchase four substations and 1.5 miles (99 distribution poles) of distribution lines. Two of the four substations provided direct access to the 115-kV transmission system.
The city installed larger substation class transformers and upgraded them to include electronic equipment breakers /relays and connected it all to its SCADA system.
The city closed on this project at the end of 2021, and now has direct access, additional capacity and better reliability that it has sought since 2014 and no longer needs to pay the $500,000 local access charge per year.
Reading Municipal Light Department Launches Renewable Choice Program
January 27, 2022
by Paul Ciampoli
APPA News Director
January 27, 2022
The Reading Municipal Light Department (RMLD) in Massachusetts recently announced the upcoming launch of its renewable choice opt-in program that will allow customers to support additional renewable energy resources above and beyond RMLD’s annual non-carbon energy targets.
Funds from the renewable choice program will be used to retire additional New England Power Pool Generation Information System compliant renewable certificates, specifically Mass Class 1 certificates.
The program launches February 1, 2022 for residential customers and will be available to commercial and industrial customers this spring.
Customers can choose to contribute at one of three levels to bring their monthly electricity usage to 50%, 75%, or 100% renewable/non-carbon. The renewable choice charge will be based on the participating customer’s monthly kilowatt hour (kWh) usage and will be added as a line item on the customer’s monthly electric bill.
A one-year commitment is required, and customers must be current with their bill to sign up.
Additional information about the program is available here: https://www.rmld.com/home/pages/renewable-choice.
The page also features a calculator which allows customers to input their monthly kWh usage to see how much their monthly renewable choice charge would be for all three available participation percentage levels.
Established in 1894, RMLD is a municipal electric utility serving over 70,000 residents in the towns of Reading, North Reading, Wilmington, and Lynnfield Center. RMLD has over 30,000 meter connections within its service territory.
SMUD Unveils First Utility-Scale Storage Battery Project
January 26, 2022
by Paul Ciampoli
APPA News Director
January 26, 2022
Officials from California’s Sacramento Municipal Utility District (SMUD) on Jan. 24 were joined by regional leaders for a ribbon-cutting of SMUD’s first utility-scale storage battery project.
With the ribbon cutting, the public power utility unveiled six large-scale lithium-ion battery storage units at the Hedge Solar Farm in south Sacramento, a pilot project that will demonstrate the feasibility of utility-scale battery storage.
The large-scale lithium-ion battery system is a step forward in SMUD’s vision to add 1,100 megawatts (MW) of battery storage over the next decade, a keystone to the utility’s 2030 Zero Carbon Plan.
Hedge Solar Farm batteries will provide 4 MW of electricity and 8 megawatt-hours of storage. The six battery containers are 20 feet long, weigh 52,000 pounds each, and house 3,840 interconnected battery cells.
This is the largest battery installation in the greater Sacramento area and the first of its kind for a publicly owned utility in California, SMUD said.
The following officials attended the ribbon cutting:
SMUD CEO and General Manager Paul Lau
Rep. Doris Matsui, D-Calif.
SMUD Board of Directors Vice President Heidi Sanborn
Sacramento Mayor Darrel Steinberg
Sacramento Councilman Eric Guerra
California Assemblymember Kevin McCarty
California Assemblymember Ken Cooley
Matthew Nelson of Electrify America
John Roeser of Mitsubishi
Platte River Power Authority To Join Market Operated By Southwest Power Pool
January 26, 2022
by Paul Ciampoli
APPA News Director
January 26, 2022
Colorado’s Platte River Power Authority, Xcel Energy-Colorado and Black Hills Colorado Electric on Jan. 25 announced plans today to join the Western Energy Imbalance Service (WEIS) Market, operated by the Southwest Power Pool (SPP).
Platte River, based in Fort Collins, and the two investor-owned utilities expect to join the WEIS in April 2023 and will continue to study long-term solutions for joining or developing an organized wholesale market.
An energy imbalance market is a real-time market in which energy generation from multiple power providers is dispatched at the lowest possible cost to reliably serve the combined customer demand of the region.
“Joining the WEIS will expand the benefits we gained from the joint dispatch agreement (JDA) on behalf of our owner communities,” said Jason Frisbie, general manager and CEO of Platte River, in a statement. “We’ve created excellent partnerships through the JDA that currently provide great value to our customers. Moving into an energy imbalance market brings Platte River one step closer to a noncarbon energy future.”
Xcel Energy-Colorado currently operates under a JDA that enables sharing generation between Platte River, Black Hills Colorado Electric and public power utility Colorado Springs Utilities within its Balancing Authority Area.
The group explored participation in the Western Energy Imbalance Market operated by the California Independent System Operator as well as the WEIS operated by SPP.
Xcel Energy took a step back from joining the Western Energy Imbalance Market last year after one of its energy partners joined the WEIS.
After further analysis, the group decided the best interim option was to move into the WEIS due to geographic diversity and existing interconnections. The utilities’ participation in the WEIS will replace the JDA and is expected to bring additional production cost savings to customers.
The three organizations remain committed to evaluating a longer term and broader regional market structure that will ensure system reliability and improve the integration of wind and solar energy on the system.
In October, they announced participation in the Western Markets Exploratory Group (WMEG) and are committed to working with the WMEG to evaluate different market options that reduce costs, increase reliability, and help promote their strategies to create a carbon free electricity system.
Participants in the WMEG will consider market structures that expand on energy imbalance markets and will evaluate broader market designs for the western region, including a staged approach to new market services, to see if those designs can enhance their ability to provide clean, reliable and low-cost energy service to their customers.
The agreement to join the WEIS still requires approval through appropriate regulatory processes.
USDA Launches $10 Million Program For Rural Renewables Projects
January 26, 2022
by Peter Maloney
APPA News
January 26, 2022
The U.S. Department of Agriculture (USDA) is making up to $10 million available to help residents of rural towns develop community renewable energy projects.
The funds, available through the new Rural Energy Pilot Program, can be used to deploy community-scale renewable energy technologies and innovations to reduce climate pollution and increase resilience to the impacts of climate change.
The technologies can include solar, wind, geothermal, micro-hydroelectric and biomass/bioenergy projects. Up to 20 percent of awarded funds may also be used for community energy planning, capacity building, technical assistance, energy efficiency and weatherization.
As part of the pilot program, the USDA is offering priority points to projects that advance key priorities under the Biden-Harris administration to help communities recover from the COVID-19 pandemic, advance equity and combat climate change. The points will increase the likelihood of funding for projects seeking to address the identified rural challenges.
The USDA said details on a planned informational webinar will be posted on the Rural Energy Pilot Program webpage.
GM Plan For More Than $7 Billion In EV Investments Includes Battery Cell Plant In Lansing
January 26, 2022
by Paul Ciampoli
APPA News Director
January 26, 2022
General Motors Co. on Jan. 25 announced an investment of more than $7 billion in four Michigan manufacturing sites including construction of a new battery cell plant in the public power community of Lansing, Mich., as well as two Lansing-area vehicle assembly plants to upgrade their production capabilities for near-term products.
This is the single largest investment announcement in GM history.
New Ultium Cells Battery Cell Plant At Lansing Site
GM and LG Energy Solution, via their Ultium Cells joint venture, are investing $2.6 billion to build Ultium Cells’ third U.S. battery cell manufacturing plant. This investment is expected to create more than 1,700 new Ultium Cells jobs when the plant is fully operational.
Site preparations will begin this summer and battery cell production is scheduled to begin in late 2024. Ultium Cells Lansing will supply battery cells to Orion Assembly and other GM assembly plants.
The Ultium Cells Lansing site represents GM’s third Ultium Cells battery cell manufacturing site in the U.S., following two Ultium Cells battery cell manufacturing plants being constructed in Ohio and Tennessee.
In addition to the EV-related investments in Michigan, GM is investing more than $510 million in its two Lansing-area vehicle assembly plants to upgrade their production capabilities for near-term products:
- Lansing Delta Township Assembly: Investment is for production of the next-generation Chevrolet Traverse and Buick Enclave.
- Lansing Grand River Assembly: Investment is for plant upgrades.
Vertically integrating battery assembly and converting existing assembly plants are at the core of GM’s strategy for scaling EV production in North America, the company said. GM projects it will convert 50 percent of its North American assembly capacity to EV production by 2030.
“The Lansing Board of Water & Light is thrilled to provide the energy to power GM’s new battery plant in Delta Township,” Dick Peffley, General Manager of Lansing Board of Water and Light (BWL), said in a statement.
“As GM reinvents the auto industry, BWL is proud that we’ll continue providing GM’s utility services, just as we’ve done for more than 100 years,” he said.
“The BWL’s unique position as a publicly owned, hometown utility provided the opportunity to collaborate with General Motors on this transformational project, which will provide unprecedented economic opportunity and growth to the greater Lansing area,” Peffley said. “I want to recognize the talented BWL workforce and commend our state, regional and local leadership that contributed to making this once in a generation opportunity a reality.”
Orion Assembly For Production Of Chevrolet Silverado EV And Electric GMC Sierra
GM is also investing $4 billion to convert the Orion facility to produce electric trucks using the GM-developed Ultium Platform, which gives the company the flexibility to build vehicles for every customer and segment.
This investment is expected to create more than 2,350 new jobs at Orion and retain approximately 1,000 current jobs when the plant is fully operational. GM estimates the new jobs at Orion will be filled by a combination of GM transferees and new hires.
Electric truck production, including the Chevrolet Silverado EV and electric GMC Sierra, will begin at Orion in 2024. The Orion investment will drive significant facility and capacity expansion at the site, including new body and paint shops and new general assembly and battery pack assembly areas, GM said.
Production of the Chevrolet Bolt EV and EUV will continue during the plant’s conversion. Site work will begin immediately.
BPA, Western Utilities Propose New Plan For Major Transmission Line
January 25, 2022
by Paul Ciampoli
APPA News Director
January 25, 2022
The Bonneville Power Administration (BPA), Idaho Power and PacifiCorp have reached a non-binding agreement that clarifies and updates roles and responsibilities for the Boardman to Hemingway (B2H) transmission line, a 500-kilovolt, 290-mile transmission line that would deliver 1,000 megawatts of power in each direction between the Pacific Northwest and Mountain west.
Under the agreement, Idaho Power and PacifiCorp, both of which are investor-owned utilities, will jointly own the B2H transmission line, with PacifiCorp owning 55% and Idaho Power owning 45%.
Idaho Power will acquire an ownership interest in PacifiCorp transmission lines and other equipment between eastern Idaho and the Four Corners Substation in northwest New Mexico.
BPA will transfer its ownership interest in B2H to Idaho Power and will not participate in construction or have any ownership interest in the transmission line project.
Facilities currently used by PacifiCorp to serve BPA’s customers in and around southeast Idaho will be transferred to Idaho Power.
BPA will acquire transmission service over Idaho Power’s transmission system, including the newly constructed B2H, to reliably and cost-effectively serve public utility customers in Idaho, Wyoming and Montana.
Under the agreement, PacifiCorp will acquire Idaho Power transmission assets across southern Idaho that, combined with its majority stake in Boardman-Hemingway, will increase its contiguous power transfer capability between its Western and Eastern systems, and will acquire additional transmission service from BPA to enable it to serve its growing customer base in central Oregon.
With the non-binding term sheet developed, the three organizations will move into a negotiation phase to finalize the agreements and seek regulatory approval.
BPA issued a letter to its regional stakeholders and customers that outlines the proposal, describes the background and explains the process for engaging with BPA on this topic. The letter is available here.
The term sheet and background information about B2H is available at the project website.
B2H is expected to come online in 2026.
Supreme Court Agrees To Consider Case Involving Clean Water Act
January 25, 2022
by Paul Ciampoli
APPA News Director
January 25, 2022
The U.S. Supreme Court on Jan. 25 agreed to consider a case that involves the scope of the Clean Water Act (CWA) and, more specifically, whether an appeals court set forth the proper test for determining whether wetlands are “waters of the United States” (WOTUS) under the CWA.
The Supreme Court granted a petition to review Sackett v. EPA. In that case, the U.S. Court of Appeals for the Ninth Circuit held that then-Justice Anthony Kennedy’s “significant nexus” test from Rapanos v. United States and not the Rapanos plurality’s “relatively permanent waters” standard, determines whether wetlands are subject to CWA regulation.
The court’s review is likely to have significant implications for the Environmental Protection Agency (EPA) and Army Corps of Engineers’ interpretation of the scope of CWA jurisdiction over WOTUS, including the agencies’ current WOTUS rulemaking.
The case will likely be heard during the court’s October term, with a final decision likely in late 2022 or early 2023.
In late 2021, EPA and the U.S. Department of the Army proposed to reestablish the pre-2015 definition of WOTUS. The proposed rule is updated to reflect U.S. Supreme Court precedent, the agencies said.
The American Public Power Association (APPA) in September 2021 submitted comments in response to a request for recommendations to revise and refine the regulatory definition of WOTUS. In those comments, APPA advocated that a new definition must draw clear jurisdictional lines, provide needed predictability for the regulated community, and be consistent with the Clean Water Act and Supreme Court precedent.
It is uncertain at this point whether – and if so how – the Supreme Court’s review may affect the timing or substance of the agencies’ current WOTUS rulemaking.
“The court’s decision may be highly instructive on the issues at the heart of the pending WOTUS rulemaking and could raise serious questions about the approach in the agencies’ proposed rule,” said Carolyn Slaughter, Director, Environmental Policy, at APPA.
APPA Offers A Number Of Recommendations To DOE On Energy Supply Chain Issues
January 24, 2022
by Paul Ciampoli
APPA News Director
January 24, 2022
The American Public Power Association (APPA) and the Large Public Power Council (LPPC) recently provided comments including recommendations to the Department of Energy (DOE) in response to a request for information (RFI) that DOE issued on energy sector supply chain issues.
Among other things, APPA and LPPC said that DOE should utilize a risk-based framework for supply chain security and further recommended that DOE study domestic and international supply of both distribution and bulk electric system transformers and the components needed to manufacture these transformers.
Background
DOE was instructed to issue a report on supply chains for the energy sector industrial base in Executive Order (EO) 14017, “America’s Supply Chains,” issued last February. DOE will use the information gathered from the RFI to compile its report to the White House by February 24, 2022, as directed by the EO.
DOE sought input from stakeholders on “approaches and actions needed to build resilient supply chains for the energy sector,” with a focus on 14 categories.
While most, if not all, of the categories are of at least some relevance to public power and the electric industry as a whole, APPA decided to focus its comments on this subset of categories most directly affecting public power currently: Electric Grid – Transformers and HVDC; Carbon Capture, Storage and Transportation Materials; and Cybersecurity and Digital Components.
Cybersecurity and Digital Components
APPA and LPPC noted that public power utilities “take very seriously their responsibility to maintain a secure and reliable electric grid.”
The electric utility sector has a mandatory and enforceable federal regulatory regime in place for reliability, including cybersecurity. Under this standards regime, utilities are responsible for assessing the cybersecurity of vendors and manufacturers of digital components.
According to the two trade groups, public power utilities have found that not all vendors and manufacturers of digital components feel compelled to respond to utilities as they seek to conduct these vendor assessments.
“Public power utilities believe the responsibility for demonstrating the cybersecurity of their supply chain for all equipment, components, and subcomponents used for critical electric infrastructure should rest with the vendors and manufacturers.”
For this reason, APPA and LPPC recommended that, with regards to the electric utility sector supply chain, DOE should:
- Use a risk-based framework for supply chain security;
- Directly engage with the vendors and manufacturers of digital components;
- Issue specific and prospective directives where necessary; and
- Factor in cost and availability.
Electric Grid – Transformers/HVDC
APPA provided comments on the supply chain constraints affecting distribution transformers to DOE’s Office of Energy Efficiency and Renewable Energy in December 2021 in response to the proposed rule, “Energy Conservation Program: Energy Conservation Standards for Distribution Transformers.”
In those comments, APPA primarily raised concerns with the domestic supply of distribution transformers.
“While APPA and LPPC recognize that the questions in this inquiry are about new large power transformers (LPT) and high voltage direct current technology (HVDC) initiatives, the same supply chain constraints identified in APPA’s earlier comments will impact the successful implementation of any LPT and HVDC initiatives,” the trade groups told DOE.
“As APPA communicated to DOE in its prior comments for both bulk power system and distribution system transformers, the supply chain for steel will significantly impact future transformer production and supply. Moreover, any efficiency standard for transformers will greatly impact transformer supply.”
Of immediate concern to public power utilities is how limitations on distribution transformer supply would play out in response to extreme weather events across the U.S., LPPC and APPA said.
“If an extreme weather event were to disable a significant number of distribution transformers, supply chain constraints could severely limit the availability of replacement devices, jeopardizing utilities’ ability to restore or maintain reliable electric service. Even if distribution transformers are available, supply and demand imbalance may result in significant price increases that would ultimately be borne by electric consumers. Importantly, these same concerns could eventually impact Bulk Power System (BPS) transformers.”
APPA and LPPC are concerned that this current supply shortage may last several years and exacerbate the current slowdown of domestic and international transformer deliveries. The minimum impact of this constraint is a significant increase in transformer prices, they said.
“However, the worst-case scenario could be a rationing of transformers that could slow down local economies and impede new construction and infrastructure investments.”
APPA and LPPC recommended that DOE study domestic and international supply of both distribution and bulk electric system transformers and the components needed to manufacturer these transformers “so that any well-intentioned LPT and HVDC supply chain initiatives do not result in transmission-level transformers competing for the same resources needed to restart the domestic supply chain for distribution transformers.”
More broadly, the electricity sector is dependent on numerous supply components, fuel, and technology for the generation, transmission, distribution, and consumption of electricity, the comments noted.
This would include entities involved with the following:
- Raw Materials: various metals (steel, aluminum, copper) and fossil fuel products.
- Manufacturing: manufacturers of generators/parts, motors/pumps, transformers (power/distribution), electric switching equipment, conductor, control cable, fiber optics, metering equipment, etc.
- Transportation: (ports, rail, roads, and vehicles) movement of the raw materials and finished products to their final destination.
- Skilled Workforce: (laborers, drivers, lineworkers, etc.) to make the final product that is then skillfully installed to build the U.S. modern electricity network.
“A slow down or disruption in any part of this supply system may have an adverse impact on the delivery of safe, reliable, and cost-effective electricity,” APPA and LPPC said.
Carbon Capture, Storage and Transportation Materials
Meanwhile, the groups noted that a broad portfolio of technologies is needed to achieve deep carbon dioxide (CO2) emissions reductions practically and cost-effectively. Energy efficiency and renewable resources are needed for such emissions reductions, but other technologies and strategies have a major role to play as well.
Carbon capture, utilization, and storage (CCUS) technologies are critical for putting energy systems on a sustainable path, they said.
“Despite the importance of CCUS for achieving the clean energy transition, deployment has been slow to take off — there are only around 20 commercial CCUS operations worldwide. But momentum is building. Plans for more than 30 commercial CCUS facilities have been announced in recent years, and despite the COVID‑19 pandemic, in 2020, governments and industry committed more than $4.5 billion to CCUS.”
APPA and LPPC said that CCUS could play an important role in proposed plans to reduce greenhouse gas (GHG) emissions from the U.S. power sector.
“The trend of increasing penetration of variable renewable power into the energy grid is clear. However, concerns for the rate at which variable renewable sources can be installed and the reliability of the grid caution for the continued need for reliable fossil power. CCUS could enable fossil power to fill this role while limiting CO2 emissions or supporting a clean energy standard.”
APPA and LPPC said that successful use of CCUS to remove significant CO2 from the national inventory requires not only reliable and effective capture technology, but an entire “value chain” of activities.
The key steps in this value chain are CO2 compression, transport, disposition in a safe and ideally useful manner, and analytical and monitoring techniques. The creation and maintenance of a successful supply-chain to support these activities is equally important to CO2 capture for CCUS, the groups told DOE.
CO2 compression will require large compression equipment and large diameter steel pipe. APPA and LPPC recommended that DOE survey the compression equipment manufactures to assess current and future capacity.
They noted that the transport of CO2 via pipelines is the principal means by which CO2 is, and will continue to be, distributed for enhanced oil recovery or deep saline geologic injection.
A significant expansion of the existing pipeline network is projected to be necessary to support CO2 emission reductions, based on an analysis by the National Energy Technology Laboratory, petroleum industry, and Great Plains Institute.
“Further the availably of domestically supplied steel needed to construct pipelines remains an issue not only for the power sector but for other industrial processes and equipment.”
California Utilities Sign MOU To Collaborate On EV Charging Build-out
January 24, 2022
by Peter Maloney
APPA News
January 24, 2022
A group of California public power and investor-owned utilities on Jan. 20 signed a memorandum of understanding (MOU) in support of a California Regional Charging Network.
The MOU encourages cooperation and leadership among the California utilities to build a regional network of electric vehicle charging stations in support of California’s goals to electrify its transportation sector.
The MOU was signed by the Los Angeles Department of Water & Power, Northern California Power Agency, Pacific Gas & Electric, Sacramento Municipal Utility District, San Diego Gas & Electric Company, and Southern California Edison, with other utilities expected to soon join the group.
The MOU calls for the utilities to work together to identify key locations for electric vehicle charging infrastructure in support of regional travel across the state, identify those locations that minimize grid impacts and customer costs, and define charging infrastructure characteristics that lead to more user-friendly car and truck charging.
It specifically identifies the need to support and engage with local and diverse communities along the regional corridors and emphasizes equity and community inclusion, as part of the participating utilities core values.
The MOU also lays out ground rules for the proposed cooperative efforts, but does not call for the creation of any legally binding rights or obligations. The parties to the MOU may consider creating an informal steering committee to foster the principles of the MOU. Each party to the MOU will be responsible for their own costs, and all data shared by the parties will be treated as public record subject. The MOU has a term of three years, unless terminated earlier.
The MOU grew out of the parties’ commitment to California’s zero-emission mobility goals in California Gov. Gavin Newsom’s Executive Order N-79-20 that calls for 100 percent of sales of new cars and drayage trucks to be zero-emission by 2035 and all on-road cars and trucks are to be zero-emissions by 2045.