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TVA Board of Directors approves move to establish series of decarbonization milestones

May 10, 2021

by Paul Ciampoli
APPA News Director
May 10, 2021

The Tennessee Valley Authority’s (TVA) Board of Directors on May 6 approved a resolution that endorses a document establishing a series of decarbonization milestones over the next three decades for TVA.

At its quarterly business meeting, the TVA board approved a resolution endorsing TVA’s Strategic Intent and Guiding Principles.

TVA said that by 2030, it will focus on growing its current 63% carbon reduction to 70% by:

Specific plans to achieve this milestone, including any decisions affecting existing or new facilities, will be developed over the coming months and will include detailed environmental assessments that will seek public input before any actions are taken, TVA said.

TVA said it has a path to an 80% reduction by 2035 with up to 10,000 MW of solar capacity online and continued investment in extending the lives of its current nuclear and hydro fleets, as well as the integrated systems needed to support the energy system of the future, while moving toward an aspirational goal of net-zero carbon emissions by 2050.

TVA noted that since 2005, it has reduced carbon emissions by 63% primarily through the creation of a diverse generation portfolio, which includes adding 1,600 MW of new nuclear capacity, an additional 1,600 MW of wind and solar capacity, retiring 8,600 MW of coal capacity that was at the end of its useful life by the end of 2023 and investing more than $400 million to promote energy efficiency.

Chelan County PUD unveils new hydropower contract with Puget Sound Energy

May 4, 2021

by Paul Ciampoli
APPA News Director
May 4, 2021

Washington State’s Chelan County Public Utility District and Puget Sound Energy (PSE) on April 27 unveiled a new contract for hydropower from two PUD hydro projects on the Columbia River.

The five-year contract supplies PSE with 5% of the output from the PUD’s Rock Island and Rocky Reach hydropower projects from 2022 through 2026.

The contract complements an existing contract between the two utilities, while generating revenue for the PUD to provide continued rate stability for its customers, Chelan said.

PSE secured the contract following a competitive bidding process in the first quarter of 2021.

Chelan noted that the contract will bolster PSE’s supply of carbon-free energy, in line with the goal of becoming a “Beyond Net Zero Carbon” energy company by 2045, while also supporting Washington state’s Clean Energy Transformation Act goals.

Chelan PUD in March said that it is evaluating its strategies to sell carbon-free, surplus power as long-term energy output contracts expire over the next decade.

Chelan PUD General Manager Steve Wright on March 15 presented a plan that would support more economic growth locally, while also allowing the PUD to capitalize on favorable market conditions, the PUD said.

New Jersey utility regulators approve certificates to support nuclear plants

April 29, 2021

by Paul Ciampoli
APPA News Director
April 29, 2021

The New Jersey Board of Public Utilities (NJBPU) on April 27 approved three-year zero emission certificates (ZECs) for the Hope Creek, Salem One and Salem Two nuclear power plants in the state.

The NJBPU said that the certificates ensure that the plants, which supply the state with over 90 percent of in-state generation and 37.5 percent of its overall in-state energy supply, will remain operational.

Operated by PSEG Nuclear, a subsidiary of investor-owned Public Service Enterprise Group, Salem is located along with Hope Creek Generating Station on a 740-acre site in Salem County, N.J.

PSEG owns 57% of Salem, while Exelon Corporation owns the remaining 43%.  Hope Creek is entirely owned by PSEG.

The collection of funds to pay for the credits the NJBPU approved on April 27 will begin immediately and will amount to approximately $100 million in annual subsidies for each plant for three years, at the rate of $0.004 per kilowatt hour.

At the end of three years, the board will reevaluate the program and if more money is collected than needed, those funds will be returned to ratepayers, the NJBPU noted in a news release.

In addition, if the companies receive funding via other state or federal subsidies in the future, those funds will be reconciled against the ZECs and returned to ratepayers, it said.

The NJBPU in November 2019 approved a ZEC program and application process for nuclear power plants.

The creation of the ZEC program was a requirement of legislation signed by New Jersey Gov. Phil Murphy in May 2018. Murphy signed a bill (S-2313) that created a ZEC program to support nuclear generation in the state — the 2,468-MW Salem plant and the 1,240-MW Hope Creek facility.

The application process for the second three-year ZEC eligibility period opened in August 2020. In October 2020, the NJBPU received applications for the Hope Creek, Salem One, and Salem Two plants. NJBPU Staff evaluated the applications for eligibility and ranked the applications.

As part of the evaluation process, the Board published a redacted version of all applications on its website, held public meetings and an evidentiary hearing, opened a public comment period, and provided an independent market monitor and New Jersey Division of Rate Counsel access to confidential financial information in order to assess each application. The public also had access to a redacted analysis completed by Levitan, a consulting firm.

Prior to this, the NJBPU held a public stakeholder input process in July 2020 on the ZEC application form, which was revised from the version used in 2018 during the first three-year eligibility period.

Idaho Falls Power, with Idaho National Lab, tests small hydro’s black start capabilities

April 28, 2021

by Peter Maloney
APPA News
April 28, 2021

Idaho National Laboratory (INL), working with public power utility Idaho Falls Power, has completed a series of tests designed to assess how small hydropower plants can provide startup power during outages.

The city of Idaho Falls, Idaho, owns five, small run-of-river hydro plants on the Snake River that, combined, can provide enough power to meet about one-third of the city’s power needs.

After a December 2013 outage left 3,500 residents without power in subzero weather for hours, the public power utility began to explore options that would make the city’s power system more resilient in such an emergency.

Even though Idaho Falls has its own generating plants, they are all low head, low pressure hydro plants. “We assumed the plants would be able to start up on their own in an emergency, but assuming is not knowing,” Ben Jenkins, systems engineer at Idaho Falls Power, said.

In 2016, Idaho Falls and INL began investigating the ability of its generators to start up on their own, known as black start capability, and their ability to island or operate independently of the surrounding grid.

In December 2017, the utility tested its assumptions and found that as it started adding load to its generators, they would become unstable at about 30 or 35 percent of rated capacity. The test found the limits of the utility’s system. “There was plenty of water, but low head machines need the grid to keep them stable,” Jenkins said.

Idaho Falls Power began looking for ways to fix the problem and enlisted the aid of INL, which is based in Idaho Falls and is an Idaho Falls Power customer.

“The INL folks were looking at the larger picture, the larger grid, and we were looking at the local picture,” Jenkins said. “Our needs dovetailed nicely.”

For its part, INL tested the use of ultracapacitors, which can store and discharge large amounts of energy very quickly, to provide pseudo inertia to the generating plants.

The tests demonstrated that “small hydropower plants like Idaho Falls’, combined with integrated energy storage technologies, may prove to be as nimble as natural gas when it comes to load following,” Thomas Mosier, INL’s energy systems group lead, said in a statement.

Idaho Falls Power tested two operational changes. Working with equipment provider American Governor, the utility tested variations in the gates and blade pitch of its hydro plants to find the most efficient and stable configurations.

Idaho Falls Power also tried bringing multiple plants online simultaneously, running nine tests, each with different combinations of operating parameters. “In effect, we were simulating a large plant,” Jenkins said.

“The one big thing we learned, we didn’t even know we were looking for,” Jenkins said. “If all the load is on one plant, it is unstable, but if you bring them all up simultaneously, they overperformed. We got more out of the combined plants than out of each plant individually.”

“We were pleasantly surprised; operational control can make a huge difference,” Jenkins said. If Idaho Fall Power lost power from the grid, it could implement the operational changes and restart its generators and gradually add load and operate in islanded mode.

Operational changes can also be implemented with minimal costs.

The test results have also prompted Idaho Falls Power to look at another form of energy storage, batteries. They can provide “multiple values,” Jenkins said, citing their ability to provide services such as peak shaving in addition to providing generation stability.

Idaho Falls Power is in conversation with INL about batteries, Jenkins said, and, with battery prices coming down, they could become more attractive. “What was financially unattainable two years ago is now becoming viable,” he said. “There could be value we can look at.”

With the testing portion of the collaboration concluding, there is going to be a lot of evaluation of the next few months, Jenkins said. The data collected in the tests will be fed into INL’s digital real time simulators, which can offer insight into how grids will act and react under different conditions. Then, two reports will likely be generated, one simple and another more detailed.

“We are very happy with what we learned from this, and if the information ca be used by other small utilities, all the better,” Jenkins said. “We feel we are part of a bigger involvement. It helps Idaho Falls, but it could have a much broader impact on the national grid.”

NCPA is exploring a hydrogen production facility with help from a DEED grant

April 13, 2021

by Peter Maloney
APPA News
April 13, 2021

The Northern California Power Agency (NCPA) is exploring the possibility of building a “green” hydrogen project, thanks in part, to the support of a Demonstration of Energy & Efficiency Developments (DEED) grant from the American Public Power Association.

The aim of the proposed project would be to build a hydrogen production and storage facility that could use over-generation associated with renewable energy resources to produce green hydrogen via electrolysis.

“We have been looking at the emerging technologies that can provide storage for renewable generation and hydrogen seems to check all the boxes,” Joel Ledesma, assistant general manager, generation services, at NCPA, said. “Producing hydrogen is not new but producing it at scale for the electric power grid is what is emerging.” The state of California, and the whole nation, is struggling with storage and generation that can be used to phase out fossil fuel generation, he added.

NCPA has evaluated other storage technologies but has found that lithium-ion battery storage is expensive for long term storage, pumped hydro storage is capital intensive and heavily regulated, and flywheel storage is difficult to scale up to meet commercial needs. NCPA has also evaluated technologies such as flow batteries, thermal salt storage, and compressed air energy storage and thus far deemed them not beneficial to its objectives.

NCPA would store the hydrogen produced at an electrolyzer and then blend with natural gas to be used as fuel at its Lodi Energy Center (LEC), a fast-start 300-megawatt (MW) combined-cycle plant the joint action agency uses to provide power during times of high demand.

NCPA’s current generation portfolio includes geothermal, hydropower, and natural gas-fired power plants with about half of the portfolio being emission free.

NCPA commissioned Black & Veatch to study the feasibility of a hydrogen production and storage facility. About half of the $96,600 study cost was covered by the DEED grant, which ran from December 2020 to February 2021.

Based on preliminary analysis and input from the turbine equipment manufacturer, NCPA believes its Lodi plant could co-fire up to 45 percent of hydrogen by volume.

“The blended fuel would provide about a 20 percent reduction in emissions from the Lodi plant and would be a step toward transitioning the facility to be fueled 100 percent by hydrogen,” Scott Tomashefsky, regulatory affairs manager at NCPA, said.

NCPA is considering siting the electrolysis facility near the Lodi plant, which would provide the dual benefit of being able to provide hydrogen for the transportation sector as well as using it for power generation. “To make hydrogen viable for the electric grid, it needs to be produced at a large scale,” so adding transportation could help make the project economics work, Ledesma said.

Among the primary conclusions of the study were that producing hydrogen using water electrolysis is technically feasible using commercially available technology and several vendors with commercial experience are available.

But even though there are several electrolyzer facilities operating around the world, the hydrogen energy storage facilities on the scale considered in the study are a relatively new phenomenon. The study also found that capital costs for hydrogen production and storage equipment is high and that electricity pricing contributes significantly to overall levelized costs. Nonetheless, projected pricing through the life of such a facility would appear to be “reasonable,” according to the DEED report.

In the study, Black & Veatch said it sees the potential for levelized cost of energy (LCOE) parity for a hydrogen facility that is used for co-firing a generator, as long as capital costs are reduced as much as possible, recovery and sales of oxygen from the facility are pursued, and renewable energy credit (REC) revenues can be shared with the renewable energy providers.

“Hydrogen may be feasible and practicable with the right incentives,” Ledesma said. The areas that need more study or follow-up, according to the DEED report, include:

The study marks another step toward our goal of eventually being able to fire the Lodi plant entirely with hydrogen, Ledesma said. NCPA plans to present the idea to its governing commission in order to adopt it as an emerging technology to track.

“California is seriously looking at whether natural gas remains in the future configuration of the power grid.” Tomashefsky said. “This study provides more context and helps move the conversation forward on what to do with the existing natural gas infrastructure.”

The study also does double duty, Ledesma said. It not only provides NCPA with valuable input as it negotiates a future with lower carbon dioxide emissions, but it helps inform other utilities and the public as a whole, so “we look at it as a dual benefit.”

APPA will host a webinar related to the project on May 4, 2021 from 2:00 pm to 3:00 pm EDT.

Additional details about the webinar are available here and DEED members can access the full project report here.

More than 374,000 MW of new generation capacity under development in U.S., APPA reports

April 7, 2021

by Paul Ciampoli
APPA News Director
April 7, 2021

More than 374,000 megawatts of new generation capacity is under development in the U.S., with 100,047 MW that is under construction or permitted and 274,309 MW that is proposed or pending application, according to a new report from the American Public Power Association (APPA).

The report, “America’s Electricity Generation Capacity: 2021 Update,” notes that the overall capacity mix continues to shift toward natural gas, solar, and wind.

Over the past five years, these three resources have been the dominant sources of new generating capacity in the U.S. Wind and solar especially are the primary sources for new capacity brought online over the past year and slated for development over the next several years.  

Solar accounts for 36% of the new generating capacity under construction or permitted, and wind and natural gas account for most of the remaining capacity in these categories, the report said.

Natural gas, solar, and wind projects account for nearly 97% of all capacity under construction.

Of the capacity slated to begin operating in 2021, 97% will be fueled by these three resources, with wind and solar accounting for more than 79% of new capacity.

“Not only are the shares of wind and solar generating capacity increasing, but the total aggregate capacity is steadily increasing,” the report said.

New wind capacity topped 10,000 MW in 2020 for the first time and when combined with solar capacity, these sources are expected to exceed 30,000 MW in additions in 2021.

“While some of this spate of activity can be attributed to expiring tax credits, it also reflects a general shift towards emissions-free generation,” the report said.

The report also offers information on retirements and planned retirements, cancellations, and capacity added over the past several years.

As has been the trend in the past few years, coal-fired resources account for more than half of planned retirements announced in the next few years.

“It is difficult to predict with precision the total amount of capacity that will be brought online further in the future, but the sheer amount of capacity at earlier stages of development suggest that wind and solar capacity will continue to significantly increase, buttressed by a steady amount of new natural gas capacity,” the report said.

To download the report, click here.

Grant County PUD, Energy Northwest sign MOU for advanced nuclear project

April 5, 2021

by Peter Maloney
APPA News
April 5, 2021

The Grant County Public Utility District in Washington State with Energy Northwest and X-energy have signed a memorandum of understanding for the development of an advanced nuclear reactor demonstration project.

The partners agreed to collaborate and share resources to evaluate the goal of siting, building, and operating an X-energy Xe-100 advanced nuclear power plant at an existing Energy Northwest site north of Richland, Wash. The plant would have four 80-megawatt (MW) units and is scheduled to begin construction in 2024 and come online in 2027.

Under the TRi Energy Partnership, the parties agreed to evaluate each step of the project and identify the best approach to licensing, permitting, construction, operation, and ownership.

“This partnership signifies our strong interest in advanced nuclear energy as one of the best, lowest-cost options to reliably serve Grant County’s growing communities and support their continued economic growth,” Kevin Nordt, CEO of Grant County PUD, said in a statement. “The electricity generated by a Xe-100, and other advanced nuclear energy technologies, will be invaluable to our future carbon-free grid.”

Energy Northwest, a public power joint operating agency, is providing the project site and would operate the completed plant. Energy Northwest is also considering an ownership option down the road, Jason Herbert, director of government affairs at Energy Northwest, said.

Under the state’s Clean Energy Transformation Act, utilities in Washington have to serve retail load with 100 percent carbon dioxide free resources by 2045, so many are phasing out natural gas generation and looking for resources to fill in gaps when solar wind or hydro resources are not available. “That is what got us going down this path,” Herbert said.

Grant County PUD could also take an ownership stake in the project. “We haven’t gotten to that point yet, but it is a possibility,” Chuck Allen, public affairs supervisor at the PUD, said. “There are a lot of ways this could end up.”

Grant County PUD could also be the offtaker for the electrical output of the nuclear plant. Emphasizing that the project is still in the early stages of development and that the PUD is just at the “starting line” in the development process, Allen said the utility sees X-energy’s technology as “promising technology and a promising way to generate carbon free energy to meet firm load.” The advanced nuclear plant would be able to provide both baseload and load following power.

The PUD anticipates it will have retail load in excess of its peak capacity by 2026, “so we will have to do something,” Allen said, noting that the utility is in a “unique position” because its demand is growing so rapidly. Grant County PUD’s integrated resource plan is predicting 4.9 percent load growth through 2030.

“As we move forward with our partners, we need to be sure this project makes sense for our customers and for our county,” Allen said. “Right now, we think it could,” he said, though he noted that the utility still has more due diligence to do.

X-energy is providing the technology design concept for the small nuclear reactor, as well as the fuel design. Unlike most operating nuclear reactors, which use some form of water cooling system, the Xe-100 design uses helium as a coolant. The design also uses X-energy’s proprietary tri-structural isotropic (TRISO) fuel design that mixes and encases the uranium fuel with graphite and ceramic. X-energy claims that its fuel cannot melt down and that the fuel itself is the containment vessel, replacing the need for what has typically been one of the most expensive components of a traditional nuclear plant.

X-energy’s next step in its development process is building a fuel manufacturing facility.

The company has a pilot plant in Oak Ridge, Tenn., but is looking for a new commercial site. X-energy filed an application for a new site with the Nuclear Regulatory Commission in August and is “beginning to work with regulatory agencies on environmental applications,” Carol Lane, head of governmental relations at X-energy, said.

In October 2020, the Department of Energy, through its Advanced Reactor Demonstration Program, awarded X-energy $80 million in initial funding for the Washington project.

On March 1, X-energy signed an approximately $2.5 billion cooperative agreement with the Advanced Reactor Demonstration Program under which the DOE will invest about $1.23 billion and X-energy will have to raise a similar amount through private sources.

The Northwest public power utilities are not the first to pursue an advanced small modular reactor.

In January, Utah Associated Municipal Power Systems (UAMPS) and NuScale Power signed agreements to facilitate the development of the Carbon Free Power Project that would deploy NuScale’s small modular reactors design at the Idaho National Laboratory. Energy Northwest has the option to operate the SMR plant.

TVA, University of Tennessee sign MOU on advance nuclear reactor demonstration

In April 2020, it was disclosed that the University of Tennessee and the Tennessee Valley Authority had signed a memorandum of understanding to evaluate the development of a new generation of cost-effective, advanced nuclear reactors, such as small modular reactors, at TVA’s 935-acre Clinch River Nuclear Site in Roane County.

Douglas County PUD Commissioners break ground on renewable hydrogen facility

March 13, 2021

by Paul Ciampoli
APPA News Director
March 13, 2021

Douglas County PUD Commissioners Aaron Viebrock, Molly Simpson and Ronald E Skagen recently moved the first shovels of dirt at the soon to be built renewable hydrogen production facility near Baker Flats, East Wenatchee.

The 5-megawatt pilot project will provide flexibility to Washington State-based Douglas PUD operations at their Wells Hydroelectric Project.

​Generation requests can be sent to the hydrogen electrolyzer to reduce the mechanical adjustments necessary at the Wells Hydroelectric Project to balance the grid, Douglas PUD noted. This will reduce the maintenance necessary on the turbine units and associated equipment.

This project has been in the works for several years with the first hurdle cleared with the passage of S.B. 5588 in 2019 authorizing PUDs to produce and sell renewable hydrogen and a $250,000 planning grant.

Site excavation started this month with anticipated delivery of the electrolyzer in July.

Connections of piping, electrical and water will follow with production of renewable hydrogen starting late this year. 

Click here for a video of the groundbreaking event.

Siemens Energy, Intermountain Power Agency partner on hydrogen energy storage system study

March 3, 2021

by Paul Ciampoli
APPA News Director
March 3, 2021

Siemens Energy has teamed up with Intermountain Power Agency to perform a conceptual design study on integrating a hydrogen energy storage system into an advanced class combined cycle power plant, Siemens Energy said on March 1.

 The project has been awarded a $200,000 grant from the U.S. Department of Energy, one of four funding awards received by Siemens Energy in late 2020 to advance hydrogen applications in the U.S. power generation sector. 

The study is set to begin in March at the 840-MW Intermountain Generating Station in Delta, Utah. The goal of this study is to analyze the overall efficiency and reliability of CO2-free power supply involving large-scale production and storage of hydrogen.

In addition, the study will analyze aspects of integrating the system into an existing power plant and transmission grid, such as the interaction with subsystems, sizing and costs.

“The study will be designed around Siemens Energy’s Silyzer technology, which uses electrolysis to generate hydrogen.  The scope of our research will include hydrogen compression, storage and intelligent plant controls,” said Tim Holt, executive board member at Siemens Energy, in a statement.

The Intermountain Generating Station is transitioning from coal to natural gas, with plans to integrate 30% hydrogen fuel at start-up in 2025 and 100% hydrogen by 2045. The project is to provide 840 MW of electricity to customers in Utah and Southern California.

“By switching from coal to a mixture of natural gas and hydrogen we can reduce carbon emissions by more than 75%,” said Dan Eldredge, general manager of Intermountain Power Agency, in a statement. “We are committed to being a leader in the transition to a clean energy future while taking advantage of the significant energy infrastructure already in place at the Intermountain Power Project. This study will help pave the way for the successful transition to net-zero carbon power generation.”

Hydropower grew faster in the last 10 years than other forms of storage

February 12, 2021

by Peter Maloney
APPA News
February 12, 2021

Over the past decade, pumped hydropower storage (PHS) capacity grew by almost as much as all other forms of energy storage in the United States combined, which were mostly battery storage installations, according to a recently released Department of Energy (DOE) report.

Pumped hydropower storage capacity increased by 1,400 megawatts (MW) from 2010 to 2019, the report noted. Almost all of the growth came from upgrades to six existing PHS plants: Castaic in California, Northfield Mountain in Massachusetts, Muddy Run in Pennsylvania, and Bad Creek, Fairfield, and Jocassee in South Carolina.

Since 2010 a total of $7.8 billion has been invested in pumped hydropower storage refurbishments and upgrade with almost $2 billion of the total investment for projects initiated between 2017 and 2019.

All other utility-scale energy storage projects deployed by the end of 2019, mostly battery storage projects, had a combined power capacity of 1.6 GW and energy storage capacity of 1.75 GWh.

In all, there are 43 pumped hydropower storage plants in the U.S. with total power capacity of 21.9 gigawatts (GW) and estimated energy storage capacity of 553 gigawatt hours (GWh), which accounted for 93% of utility-scale storage power capacity (GW) and more than 99% of electrical energy storage (GWh), according to the DOE report.

Looking forward, pumped hydropower storage appears poised to continue its upward trajectory. The pumped hydropower storage project development pipeline doubled in the past five years, according to the report. At the end of 2019, there were 67 pumped hydropower storage projects, representing 52 GW, under development, ranging in size from 5 MW to 4,000 MW. Geographic interest in pumped hydropower storage has expanded with new projects being explored in New York, Ohio, Oklahoma, Pennsylvania, Virginia, and Wyoming.

Overall, hydropower capacity saw a net growth of 431 MW between 2017 and 2019, mostly from capacity increases at existing facilities, new hydropower in conduits and canals, and by powering non-powered dams. At the end of 2019, U.S. hydropower totaled 80.25 GW, accounting for 6.7% of the country’s installed generation capacity.

In 2019, hydropower generated 274 terawatt hours (TWh), representing 6.6% of U.S. electricity generation and 38% of electricity from renewables.

The most recent U.S. Hydropower Market Report is the third edition and covers the years 2017 through 2019. The previous editions were published in 2015 and 2018. The report combines data from public and commercial sources, as well as research findings from other Department of Energy research and development projects.