APPA Survey of Members Shows Distribution Transformer Production Not Meeting Demand
October 12, 2022
by Paul Ciampoli
APPA News Director
October 12, 2022
An American Public Power Association (APPA) survey of its members shows that production of distribution transformers is not meeting current demand, “as evident in the significantly growing lead times, lack of stock in yards and the high number of project deferrals,” APPA said.
In August 2022, APPA surveyed its members about distribution transformer supply and demand. The survey “highlights the expanded nature of this problem subsequent to the results of two previous surveys we have done on this matter, beginning in November 2021,” APPA said.
The data from the survey informed the Department of Energy and the Electric Subsector Coordinating Council (ESCC) of the severity of the supply chain distribution transformer shortage across the entire electric sector.
Ninety-five public power utilities serving a total of 6,719,596 meters responded to the survey.
Along with its finding that production is not meeting current demand, another key takeaway from the survey is that demand has grown consistently in the past and will continue to rise in the future.
Because demand is out pacing supply, many public power utilities are at a high risk of stocking out on transformers in 2022 or following one storm.
Between 2019 and 2020, demand across all voltage classes for distribution transformers rose 3.6% for public power survey respondents. During this period, the lead time to procure distribution transformers averaged two to three months. Economic forecasts anticipate that the calculated annual growth rate for distribution transformers in North America will continue to increase and be 9.1% for 2022-2030.
Between 2020 and 2022, the number of distribution transformers purchased remained largely steady. However, beginning in 2021 and continuing into 2022, the number of distribution transformers available for purchase no longer meets the demand. Evidence for this imbalance can be seen in the significantly increasing lead times and the deferral of projects, APPA stated.
Meanwhile, between 2020 and 2022, average lead times to procure distribution transformers for all voltage classes rose 429% for public power respondents — from about two to three months pre-2021 to about 12 months in 2022. Some utilities reported being quoted lead times of more than three years.
APPA reported that many utilities are deferring or canceling infrastructure projects because they are unable to procure the additional distribution transformers required for these projects. Among public power utilities, one in five projects were deferred or canceled.
Most responding utilities reported low or near zero emergency stock, which is often used to recover post-disaster or to do infrastructure maintenance. Some public power utilities reported being within weeks of hitting the bottom of their distribution transformer stocks. In the event of a catastrophic hurricane or other natural disaster, the industry risks stocking out much sooner, APPA pointed out.
APPA continues to work through the ESCC and other forums to discuss the problems and identify solutions that the federal government can act upon to alleviate the supply chain shortages, specifically with regards to distribution transformers.
APPA has taken a number of actions to address ongoing supply chain challenges. APPA recently rolled out an additional feature to its eReliability Tracker that is available to all public power utilities and allows for voluntary equipment sharing by matching systems with the same distribution voltages. APPA also recently finalized a new supply chain issue brief. APPA members can download the issue brief here.
In May, APPA sent a letter to Secretary Granholm at the Department of Energy asking that they consider a temporary waiver of efficiency standards in distribution transformers that may lead to an increase in supply. That request was declined in August. In a speech in June at APPA’s National Conference in Nashville, Tenn., APPA President and CEO Joy Ditto urged member utilities to share their supply chain challenges with APPA so that the trade group can relay details on these challenges to federal partners and discuss how critical burdens on the sector can be alleviated.
In May, APPA convened a supply chain summit that included participation from public power utility officials who discussed their supply chain challenges and mitigation strategies.
Company Looks to Extend Operation of 2,400-MW Texas Nuclear Power Plant
October 8, 2022
by Paul Ciampoli
APPA News Director
October 8, 2022
Vistra Corp. on Oct. 3 announced that it is seeking to extend the operation of Luminant’s Comanche Peak Nuclear Power Plant in Texas through 2053, an additional 20 years beyond its original licenses.
Luminant is a subsidiary of Vistra.
The company has officially submitted its application for license renewal with the Nuclear Regulatory Commission. The two-unit nuclear plant has a capacity of 2,400 megawatts.
The current licenses for units 1 and 2 extend through 2030 and 2033, respectively. The company is applying to renew the licenses through 2050 and 2053, respectively.
DOE Releases Opportunities for Nearly $5 Billion in Carbon Capture Technologies
October 8, 2022
by Peter Maloney
APPA News
October 8, 2022
The Department of Energy (DOE) recently announced nearly $4.9 billion in funding opportunities that aim to demonstrate and deploy carbon capture systems, as well as carbon dioxide transport and storage infrastructure.
The funding, which derives from the Bipartisan Infrastructure Law, is designed to support three programs.
The Carbon Storage Assurance Facility Enterprise (CarbonSAFE) initiative, which is being managed by the DOE’s Office of Fossil Energy and Carbon Management (FECM), provides up to $2.25 billion to support the development of new and expanded large-scale, commercial carbon dioxide (CO2) storage projects with capacities to store 50 or more million metric tons of CO2, along with associated CO2 transport infrastructure. Projects should focus on detailed site characterization, permitting, and construction stages of project development under CarbonSAFE.
The Carbon Capture Demonstration Projects Program, being managed by the DOE’s Office of Clean Energy Demonstrations (OCED) in partnership with FECM, will provide up to $2.54 billion to develop six integrated carbon capture, transport, and storage demonstration projects that can be replicated and deployed at fossil energy power plants and major industrial sources of CO2, such as cement, pulp and paper, iron and steel, and certain types of chemical production facilities. The funding opportunity announcement (FOA) provides up to $189 million for up to 20 integrated front-end engineering design studies, with a second FOA expected later this year to support detailed design, construction, and operation of carbon capture projects, as well as transport and storage of the captured CO2.
The Carbon Dioxide Transport Engineering and Design initiative, being managed by FECM, will provide up to $100 million to design regional CO2 pipeline networks to safely transport captured CO2 from key sources to centralized locations. Projects should focus on carbon transport costs, transport network configurations, and technical and commercial considerations that support broad efforts to develop and deploy carbon capture, conversion, and storage at commercial scale.
DOE FOAs require that applicants submit Community Benefits Plans detailing their commitments to community and labor engagement, quality job creation, diversity and equity, and implementation of the Biden administration’s Justice40 Initiative.
Oak Ridge Lab Report Helps Hydropower Operators Prepare for Climate Change
October 8, 2022
by Paul Ciampoli
APPA News Director
October 8, 2022
A new report from the Department of Energy’s Oak Ridge National Laboratory (ORNL) aims to provide hydropower operators data that will better enable them to plan for changing climate conditions.
The data collected and analyzed in the report can aid operators in shifting operational schedules and seasonal water use as part of an overall mitigation strategy in the face of changing climate conditions and reduced water availability, the report’s authors said.
Among other findings, the report projects that earlier-than-expected snowmelt season in the western United States is likely to impact water runoff, resulting in less water for hydropower generation in the summer months, just as energy demand grows. In addition, Increased evaporation because of rising temperatures is also putting a strain on water needed for flood control, navigation, municipal water supplies and industrial and agricultural use.
The report also found that, except for part of summer and fall, there is a persistent increase in projected precipitation, especially in the winter, resulting in a net annual precipitation increase of up to 8 percent.
On a seasonal basis, the report found that winter and spring runoff are generally projected to increase across the conterminous United States while summer runoff is projected to decrease for many parts of the country, especially in the West and the South, resulting in a shift in the timing and seasonality of the water availability.
That effect may be magnified in the Southwest and Southeast because hydropower reservoirs in those regions have less storage capacity than federal hydropower reservoirs under the control of the Bonneville Power Administration and the Western Area Power Administration, the report found.
As a result, on a seasonal basis, most models project increasing hydropower generation in winter and spring, and decreasing generation in summer and fall caused by earlier snowmelt and changing runoff, the report said.
The combination of declining winter heating load and increasing hydropower generation suggests that federal hydropower surpluses are likely during the winter months, the reports’ authors said. Thus, they said, the ability to shift water from winter to summer months and to maximize the revenue from winter surpluses to compensate for potential increased power purchase requirements in the summer will be valuable for all power marketing administrations.
The ORNL researchers used downscaled global climate projections to simulate future hydrologic conditions at 132 federal hydropower facilities across the United States to compile the report.
In order to provide more hydropower stakeholders with the tools and data to plan for climate change impacts, the Department of Energy said it is extending its research to non-federal hydropower facilities, whose operators may not have the resources to study and address these challenges.
PNNL Report Says Hydropower Can Still Perform During Extreme Droughts
October 8, 2022
by Peter Maloney
APPA News
October 8, 2022
Even during the severe droughts of the last two decades, hydropower has sustained 80 percent of average power generation levels, according to a report by researchers at the Pacific Northwest National Laboratory (PNNL).
“That’s a noticeable dip — but it’s still a lot of renewable energy,” Sean Turner, water resources modeler at PNNL and main author of the report, said in a statement.
The megadrought in the Southwest is the driest and longest in the last 1,200 years, depleting water reservoir levels to critically low levels over the past 22 years and has raised concerns among policymakers and system planners over the reliability of the electric grid.
Droughts particularly affect hydroelectric power dams, as well as some thermoelectric power plants that require large amounts of water for cooling. But drought rarely impairs hydroelectric power across all regions of the Western United States simultaneously.
In the last 20 years, there has not been a drought that has affected all major hydropower generation regions at once, the report said, noting that current river flows and reservoir levels in California and the Southwest are low due to ongoing drought, which affects hydropower generation in those regions, but the lion’s share of hydropower generation in the West is dispatched to the grid from the Northern Cascades and Columbia River Basin, in Washington, Oregon, Idaho, and British Columbia.
“The current drought is severe but it’s nowhere close to being the worst hydropower generation year for the West and water resource conditions are actually above average right now in the Northwest,” Turner said.
The report combined 20 years’ of annual power generation data from more than 600 hydroelectric power plants with historical precipitation data from eight hydropower climate regions of the Western United States and used the data to extrapolate hydropower generation as far back as 1900.
The findings were published in a retrospective report funded by the Water Power Technologies Office within the Department of Energy’s (DOE’s) Office of Energy Efficiency and Renewable Energy.
Meanwhile, another PNNL researcher is investigating how well hydropower dams perform during heat waves and exceptional load demand. PNNL power systems modeler Konstantinos Oikonomou that a heat wave can actually create favorable conditions for hydropower plants.
Rapid snowpack melt during a heat wave can help reservoirs fill with water, which can allow hydropower plants to meet increased load demand, Oikonomou said.
To further test their results, PNNL hydrologists and power system modelers simulated the effect of compound heat waves and droughts on the power grid and found that regional interconnections are critical to manage extreme events.
Oikonomou’s research is now focused on creating a new framework for simulating grid behavior under extreme weather conditions, such as compounding droughts and heat waves, and under occurrences like faulty transmission lines.
“This information will help power plant operators and system planners explore mitigation strategies to fortify the grid against outages,” Oikonomou said.
Broad Portfolio Approach Needed to Reach Affordable, Reliable Clean Energy: EPRI
October 8, 2022
by Peter Maloney
APPA News
October 8, 2022
A broad portfolio of clean energy technologies will be required to reach an affordable and reliable clean-energy transition, according to new research by the Electric Power Research Institute (EPRI).
The Low-Carbon Resources Initiative (LCRI) report, by EPRI and GTI Energy, modeled three scenarios to evaluate alternative technology strategies for achieving economy-wide net-zero emissions of carbon dioxide (CO2).
The All Options scenario assumes a full portfolio of clean energy technologies is available, including renewables, nuclear, fossil and bioenergy with carbon capture and storage, electricity storage, hydrogen and hydrogen-derived fuels, and biofuels.
The Higher Fuel Cost scenario assumes all technologies are available, but with higher costs for gas, oil, bioenergy, and CO2 transport and storage.
The Limited Options scenario assumes geologic storage of CO2 is not available and bioenergy supply is limited, but all other technologies are available.
Power Generation
Among the key findings, the LCRI report found that electric generating capacity would grow substantially, from 1,650 gigawatts (GW) to 4,860 GW, a 160 percent to 480 percent increase over current resources.
Across all scenarios, total wind and solar through 2050 ranged from roughly 600 GW to 3,500 GW, compared with 273 GW today, with the high end driven by electricity supporting hydrogen production.
Total clean firm capacity to balance the increase in intermittent resources also would grow, anywhere 1,140 GW to 1,446 GW, including a combination of natural gas, nuclear, hydrogen, hydro, geothermal, bioenergy, and electric storage technologies.
Nuclear Capacity
In all scenarios, the report’s authors found that existing nuclear would provide essential firm capacity in a net-zero energy system. In the Limited Options scenario, in which carbon capture and storage is restricted, new advanced nuclear technologies, such as small modular reactors, would provide around 60 GW of generating capacity as a carbon-free baseload option by 2050. Also, continued expansion and modernization of transmission and distribution network would be essential to support increased integration of renewables, electrification, and flexible demand-side resources. In all scenarios, they said, transmission and distribution investments would increase over time.
Natural Gas
Natural gas infrastructure would also play a crucial role in all scenarios in providing firm capacity for a transitioning power sector and for delivering low-carbon fuel to industry and buildings, particularly in colder climates, the report said. The composition of delivered gas varied by scenario and could include a blend of fossil, renewable and synthetic natural gas, and hydrogen, the report said.
With available options for carbon capture and storage, negative emissions, and blending, annual natural gas consumption could remain at levels similar to today, even in a net-zero energy future, the report said.
With higher natural gas prices, pipeline gas consumption would decline to about half of today’s level. In the Limited Options scenario, without carbon capture and storage, renewable and synthetic natural gas could substitute for fossil gas and pipeline gas consumption would decrease to around 17 percent of current levels.
The report found that carbon capture and storage technologies would be “pivotal” for the new natural gas plants that would be needed to provide up to 33 percent of clean firm capacity and, potentially, a significant portion of hydrogen and ammonia production.
Hydrogen
The report also projects the use of hydrogen as a low CO2 fuel will increase whether through fuel cell vehicles, blending with the natural gas supply to support needs in buildings, or through direct use for process heating in industries. And in a scenario in which carbon capture and storage is limited, hydrogen use will “expand significantly.” Bioenergy could also emerge as another key decarbonization resource, providing low-CO2 alternatives to petroleum-based fuels.
Energy Efficiency
The report’s modelling shows that adoption of efficient electrification technologies and structural shifts to less energy-intensive activities across the economy will combine to reduce final energy 25 percent to 38 percent by 2050 compared with current levels, even with 80 percent GDP growth compared with 2020. Final energy refers to energy consumed at the point of end use.
The modeling shows that “reductions in energy consumption enable emissions reductions throughout energy value chains and across the transportation, buildings, and industrial sectors through technological improvement and switching to more efficient energy carriers and technologies,” the report’s authors said. Many of those changes are cost effective and are assumed to occur even in the absence of an explicit decarbonization target, they added.
Overall, “optionality enables affordability,” the authors concluded. “Achieving economy-wide net-zero CO2 emissions while maintaining reliable delivery of energy and energy services across the economy will require a broad set of low-carbon technologies,” they wrote, adding that a flexible approach to CO2 reduction would allow each sector and region “to follow their own decarbonization path while minimizing overall costs.”
“Imposing greater limitations on resource and technology options could significantly increase the overall cost to achieve net-zero emissions,” the report’s authors said.
FMEA Executive Director Amy Zubaly Details Key Role of Mutual Aid in Response to Hurricane Ian
October 8, 2022
by Paul Ciampoli
APPA News Director
October 8, 2022
In a recent Q&A with Public Power Current, Amy Zubaly, Executive Director of the Florida Municipal Electric Association (FMEA), details how mutual aid planning laid a solid foundation for the speedy restoration of power in the state in the wake of Hurricane Ian, which hit Florida in late September.
As of 9 p.m. Tuesday, October 4, nearly 100 percent of the more than 1.5 million Florida public power customers across the state are receiving electricity. A small number of customers are unable to accept electricity due to excessive damage, damages to their homes, or significant flooding. Utilities will continue to work diligently to restore power to these remaining customers, FMEA said.
“Mutual aid planning for Hurricane Ian began on Friday, September 23, when there was a high probability of the storm hitting Florida as a strong hurricane later the following week,” Zubaly noted.
“At that point the storm track was shifting between a landfall in the Tampa area or in North Florida along the Big Bend region. Already knowing that requests for mutual aid from Florida public power utilities would soon start coming in, FMEA reached out to other state and regional public power mutual aid coordinators asking them to begin gathering over the weekend the numbers of crews they could provide for mutual aid assistance,” she said in response to questions from Public Power Current.
In addition, FMEA asked the American Public Power Association (APPA) to hold a mutual aid call on the following Monday, September 26 with the other state and regional public power mutual aid coordinators, Zubaly said.
By Monday morning, September 26, FMEA had already begun assigning available mutual aid resources to those Florida public power utilities that requested crews for prestaging or for post-storm arrival.
“Florida was still anticipating landfall somewhere along the Tampa Bay area or north. By the end of the day Monday, already hundreds of public power mutual aid resources were being requested and assigned to requesting utilities – some for prestaging and some for arrival post-storm, which at that point was most likely for a Friday or Saturday arrival,” Zubaly said.
However, by Tuesday afternoon, the track of Ian had shifted a little further east. This resulted in an anticipated landfall somewhere further south along the southwest coast of Florida, with landfall much earlier than originally anticipated, and changing projected impacts to Florida public power.
Many crews that were scheduled to depart and/or arrive later in the week were asked to change to an earlier arrival date, and to prestage outside of Florida to wait until the storm passed through and conditions were safe to travel, Zubaly said.
Hurricane Ian ultimately made landfall on the afternoon of Wednesday, September 28 in southwest Florida as a strong a powerful Category 4 hurricane. “The changing track also resulted in changing mutual aid needs. Once the storm passed through Florida and FMEA members were able to make damage assessments, mutual aid crews were immediately shifted around based on needs in areas of impact,” Zubaly noted.
Ian left more than 2.6 million customers in Florida in the dark, with more than 212,000 of them from 23 of Florida’s 33 public power utilities. Ultimately more than 750 lineworkers from 150 public power utilities in 22 states were committed to Florida public power utilities.
“Within 24 hours post landfall, while Ian was still unleashing its wrath in some areas of the state, public power had restored more than 57% of those customers initially experiencing outages; in 48 hours post landfall, nearly 80% of our customers were restored; and in 72 hours post landfall, more than 90% of those customers that had experienced outages were restored,” she said.
Supply Chain
Zubaly also addressed the question of whether supply chain challenges have been a factor in terms of completing power restoration in the state.
“Supply chain needs continue to be a challenge, but we had what we needed after Hurricane Ian to turn the lights back on for our customers,” she said.
Florida utilities “prepare year-round for hurricanes – the season begins June 1 and lasts until November 30. Part of that preparation involves maintaining a storm stock of electric grid supplies and materials that are typically used during hurricane restoration. Utilities still maintain their normal operating stock, but in addition, also increase supplies for their separate storm reserve.”
While electric grid supply chain constraints “have made it challenging to increase our storm reserve supplies to typical levels and maintaining our normal operating supplies, we were prepared as a whole to be able to restore power if hit with one large-scale hurricane. However, supply chain challenges still exist. If Florida, or even another area in the southeast, gets hit with another major hurricane this season, obtaining needed supplies will be even more challenging.”
In addition, destruction in certain areas of the state “was so expansive — and the need to restore expeditiously so acute — that the most impacted utilities were supplied stock from other in-state utilities, further depleting in-state stocks among all Florida electric utilities,” Zubaly noted.
“And while we were able to restore power to our customers with supplies we had on hand, supplies for our normal operations, including new development, are dwindling rapidly. Suppliers and manufacturers prioritized transformers and other supplies needed for immediate hurricane restoration, but that has put additional delays on manufacturing of normal operating supplies,” she said.
Salt River Project Extends Contract for Biomass Power
October 7, 2022
by Paul Ciampoli
APPA News Director
October 7, 2022
Arizona public power utility Salt River Project (SRP) has approved a contract to continue purchasing renewable energy from a biomass plant in the state that will provide baseload power while helping to cut the risk of devastating forest wildfires in northern Arizona.
The 10.5-year purchase power agreement with Novo BioPower will use wood chips from strategic forest thinning efforts in the SRP watersheds focusing on the East Clear Creek watershed projects and including the White Mountain Apache Tribal lands.
The SRP capacity output of the plant will support approximately 80,000 acres of strategic forest thinning over the next 10 years while providing renewable power for customers.
In a news release, the utility said that the forested lands of northern Arizona have been hit by devastating wildfires and are primed for more infernos like those that have impacted Arizona, California, and Colorado. Many forested lands in northern Arizona have thousands of trees per acre and suffered from extreme drought, which can fuel large wildfires with catastrophic impacts.
“To decrease the risks of forest wildfires, partnerships like this enable thinning projects to be conducted across the SRP watersheds, restoring forests and watersheds to more natural conditions and avoiding wildfires devastating impacts on the natural ecosystem, rural communities and the Valley’s water supply. These partnerships are critical for the success of forest thinning projects throughout the state.” said Elvy Barton, SRP Forest Health Management Principal.
SRP is working with the U.S. Forest Service and other entities on a number of strategic forest thinning projects that will help mitigate the forest wildfire threat and provide fuel for the renewable power plant.
So far, more than 5,700 acres of trees are being thinned and about 16,000 acres are planned in the next four years.
“Finding economically positive uses for the huge volume of biomass on the National Forests is a major barrier to overcome in order to ensure the long-term protection of critical watersheds in northern Arizona. The Novo BioPower provides the only existing market for low-grade biomass material,” SRP said.
Among SRP’s sustainability goals are a pledge to help thin 500,000 acres on the SRP watersheds by 2035 and an expanded pledge to add 2,025 MW of new utility-scale solar energy to SRP’s renewable portfolio by 2025.
Hannibal Board of Public Works Seeks Solar Plus Battery Storage Proposals
October 7, 2022
by Paul Ciampoli
APPA News Director
October 7, 2022
Missouri public power utility Hannibal Board of Public Works (HBPW) is seeking proposals for a 7 megawatt (MW) solar project paired with a 3 MW, 12 MWh battery energy storage system located behind their wholesale meter with the primary use case of meeting Midcontinent Independent System Operator capacity requirements.
HBPW will accept proposals from any electric utility, independent power producer, solar/storage developer, or electric power marketer that can deliver the project described in the request for proposals, which was issued on Oct. 4.
HBPW seeks proposals from respondents to enter into a mutually agreeable 20-to-25-year third party power purchase agreements.
HBPW will allow flexibility in the term length on the storage part of the project, requesting a term length of at least 15 years. HBPW is not seeking turnkey EPC ownership and is only requesting PPA options.
Bids are due December 15, 2022, and the contacts for the RFP at GDS Associations are: Kyle Haemig, kyle.haemig@gdsassociates.com and Justin Hey, justin.hey@gdsassociates.com.
Florida’s Cane Island Power Park Named Top Power Plant
October 7, 2022
by Paul Ciampoli
APPA News Director
October 7, 2022
Florida’s Cane Island Power Park has received a Top Plant Award from POWER magazine for its continued success in providing affordable, reliable and clean power.
The power generating facility is one of five natural gas-fired power plants in the world to be recognized and the only one located in Florida.
Cane Island Power Park, located in Intercession City, Fla., is jointly owned by Florida Municipal Power Agency (FMPA) and Kissimmee Utility Authority (KUA). Units 1, 2 and 3 are a 50/50 split between the two utilities, and Unit 4 is wholly owned by FMPA. KUA manages the day-to-day operations of the plant.
The award recognizes top performing power plants that have distinguished themselves as industry leaders through equipment enhancements, innovative design and successful operations.
The plant received the award for its excellent operating record in 2021, which plays an essential role in providing customers with affordable, reliable power. This was especially true when Hurricane Ian hit Central Florida as a Category 4 storm on Sept. 28.
Cane Island operated throughout the storm and supplied electricity to customers who were able to take power.
“We rely on Cane Island to generate nearly half of our energy,” said Jacob Williams, FMPA General Manager and CEO. “The facility’s operating performance during Hurricane Ian shows just how reliable the units are.”
Cane Island Power Park includes two baseload units, one intermediate load unit and a peaking unit. The two baseload units were available approximately 95% of the time in 2021 to provide electricity for 24 Florida cities served by FMPA. The industry average for similar units is 85%.
In Spring 2022, Cane Island Unit 3 completed a major maintenance and upgrade, its first performance upgrade since it came online in 2001. Maintenance work was conducted to replace and repair major components to ensure continued reliable service over the next decade. The upgrades also increased the unit’s output by 12 megawatts.
“We are extremely honored to receive this award in recognition of the reliability, maintenance and operation of our Cane Island Power Plant,” said KUA President and General Manager Brian Horton. “This award is a true testament to our 42 staff members who do an excellent job operating the facility.”