Lakeland Electric Installing Gas-Fired Generator To Replace Retired Coal Unit
September 25, 2021
by Peter Maloney
APPA News
September 25, 2021
Lakeland Electric is building a 120 megawatt (MW) natural gas-fired generator on land owned by the Florida city to replace a recently retired, coal-fired plant.
The reciprocating internal combustion engine (RICE) is being supplied by MAN Energy Solutions, which will install the machine on the brownfield site. MAN has committed to a fast-track delivery of the equipment by July 2022.
The engine uses a heat recovery system designed to support the plant’s stand-by operation and “perfectly matches Lakeland Electric’s stated commitment to safely provide its customers with affordable, highly dependable, and sustainable electric services,” Wayne Jones, chief sales officer at MAN Energy Solutions, said in a statement.
The new engine has an efficiency rating of more than 50 percent, even at partial loads, and will contribute to Lakeland Electric’s commitment to improve the carbon dioxide footprint of its power generation fleet, Jones said. MAN will maintain the plant under a service agreement for the next 10 years.
In December, Lakeland Electric announced plans to close Unit 3 of its McIntosh coal-fired plant, which it owned with the Orlando Utilities Commission, which has a 40 percent stake.
Lakeland Electric found that the coal generator was requiring increasingly expensive repairs while showing declining efficiency and unreliable performance. In addition, the large inventory of coal required to run the unit burdened the public power utility with a multi-million dollar risk should the unit fail.
At the time, Lakeland Electric said it would use its other natural-gas, diesel, and solar power generation capacity along with demand management, interruptible load, and power purchase agreements until replacement capacity could be built.
As part of its NextGen plan, Lakeland Electric plans to add five natural gas-fired internal combustion engines and increase its solar power and battery storage capacity by 2024.
The new natural gas generators will be more efficient and better able to manage the capacity fluctuations of solar power, Lakeland said, putting it on track to reduce its carbon dioxide emissions by 67 percent since 2001.
Project in S.C. Will Add Renewable Natural Gas To Public Power Utility’s System
September 25, 2021
by Peter Maloney
APPA News
September 25, 2021
The Greenwood Commissioners of Public Works in South Carolina is participating in a project that will create renewable natural gas for use in the public power utility’s gas distribution system.
Construction of the project at the Twin Chimneys Landfill site in Honea Path, South Carolina, began earlier this month. It is being built by Enerdyne Power Systems based in Charlotte, North Carolina.
Enerdyne Power Systems is part of The Landfill Group, which works in partnership with LS Power, a development, investment and operating company focused on the power and energy sectors.
The project will use landfill gas, a byproduct of decomposing waste, that will be collected at the Twin Chimneys site and converted into renewable natural gas that will be injected into the natural gas system owned and operated by the Greenwood Commissioners of Public Works.
When in commercial operation, expected by fourth-quarter 2022, the Twin Chimneys Power Producers (TCPP) project is expected to initially produce approximately 1,200 million metric British thermal units (MMBtu) of renewable natural gas per day.
Eventually, the project is expected to be capable of producing about 3,000 MMBtu per day.
All development, construction and operations of the project will be managed by other Landfill Group companies.
“We are excited to be a part of this first in the state project for a local gas company to receive processed landfill gas directly into its system for distribution to customers,” Jeff Meredith, general manager of Greenwood Commissioners of Public Works, said in a statement. “This project has truly been a collaborative effort between Greenville County, TCPP and Greenwood [Commissioners of Public Works] to make a positive impact on the environment and provide value to the customers we serve.”
The environmental benefits of the Twin Chimneys project are equivalent to reducing carbon dioxide (CO2) emissions by more than 28 million gallons of gasoline, according to Environmental Protection Agency (EPA) analysis, LS Power said in a statement.
Currently there is not a standard definition of renewable natural gas (RNG), according to the EPA, which developed it as a term of art for its voluntary RNG projects.
Biogas, such as landfill gas, has a methane content of between 45 and 65 percent and must be converted to renewable natural gas through a series of steps, including removing moisture, CO2, trace contaminants, and reducing nitrogen and oxygen content, to bring the methane content up to 90 percent or greater. Typically, renewable natural gas injected into a natural gas pipeline has a methane content between 96 and 98 percent, according to the EPA.
The benefits of using renewable natural gas include reducing greenhouse gas emissions, improving local air quality, boosting the local economy, and promoting fuel diversity, the EPA says.
“This project represents a major economic investment in Greenville County that will result in a significant reduction in CO2 emissions,” Michael Frixen, sustainability coordinator for the City of Greenville, said in a statement. He noted that Greenville is developing a new sustainability plan that will identify strategies to reduce the city’s CO2 emissions and overall environmental footprint.
EIA Sees Industrial Sector Natural Gas Consumption Rising Throughout 2021
September 25, 2021
by Paul Ciampoli
APPA News Director
September 25, 2021
The U.S. Energy Information Administration (EIA) expects industrial sector natural gas consumption in the U.S. to rise throughout 2021 and to exceed pre-pandemic 2019 levels.
The projection is based on EIA’s September Short-Term Energy Outlook, EIA said on Sept. 24.
“We forecast the growth to continue into 2022, and natural gas delivered to industrial consumers will average 23.8 billion cubic feet per day (Bcf/d) that year. If realized, this amount would be near the current record high for annual industrial natural gas consumption set in the early 1970s,” EIA said.
It noted that many industrial processes have limited or no alternatives to natural gas for use as both fuel and feedstock, making industrial natural gas consumption relatively insensitive to short-term price fluctuations. “Some value-added industrial products such as ammonia, methanol, and hydrogen that are produced from natural gas remain economically competitive even when natural gas prices are relatively high,” it said.
U.S. industrial natural gas consumption averaged 22.9 Bcf/d in the first half of 2021, according to EIA’s Natural Gas Monthly.
Natural gas consumption fell in the U.S. industrial sector during 2020 when a drop off in U.S. economic activity led to a decline in output among industries that consume natural gas, such as the metals, petroleum and coal products, paper, and chemicals industries.
EIA said in its latest Short-Term Energy Outlook that it expects natural gas consumption in the U.S. industrial sector to average 23.5 Bcf/d in the second half of this year and 23.2 Bcf/d for 2021.
If realized, this amount of industrial natural gas consumption would exceed the 2019 average of 23.1 Bcf/d and mark the most U.S. industrial natural gas consumption since 1997.
Study Finds Hydrogen Peakers Beat Batteries, But Not Gas Peakers
September 3, 2021
by Peter Maloney
APPA News
September 3, 2021
Hydrogen fuel could be a more economical solution to the intermittency of renewable energy resources than lithium-ion batteries, but it is not an economic match to natural gas-fired peaking plants at current market prices, according to a new report from researchers at the MIT Energy Initiative (MITEI).
Hydrogen is attracting a lot of interest as an alternative fuel for power peaking power plants. Several public power utilities, particularly on the West Coast, are exploring hydrogen as an alternative to natural gas and are looking at projects to produce so-called green hydrogen by using renewable resources to power electrolyzers that produce the gas from water. Utilities ranging from the Los Angeles Department of Water and Power and the Northern California Power Agency to the Douglas County PUD and the Nebraska Public Power District have embarked on hydrogen pilot projects.
While there has been a rapid rise in the deployment of lithium-ion batteries to aid in the integration of intermittent resources such as wind and solar power, batteries are sized to produce power for hours at a time and are best used to address daily imbalances between electric supply and demand, the authors of the report in Applied Energy said. (The online version of the article was published in July; the print version is due out in October.)
The report’s authors, Drake Hernandez and Emre Gencer, used a least cost of energy (LCOE) approach to analyze the economics of meeting seasonal energy imbalances, comparing hydrogen-fired gas turbines (HFGT) and lithium-ion battery systems (LI).
They found that the LCOE associated with meeting seasonal energy imbalances is $2,400 per megawatt hour (MWh) using a hydrogen-fired gas turbine and $3,000/MWh using a lithium-ion battery system. If a gas turbine is fired with “blue” hydrogen, that is, hydrogen produced by reforming natural gas, the average LCOE decreases to $1,560/MWh. On average, reforming hydrogen rather than electrolytic hydrogen turned out to be the cheapest option for replacing peaking plants, the report found.
Nonetheless, “the power prices required to justify investment in an HFGT to replace a natural gas-fired gas turbine are considerably higher than those seen in the market today,” the authors said.
“Our study’s essential takeaway is that hydrogen-fired power generation can be the more economical option when compared to lithium-ion batteries—even today, when the costs of hydrogen production, transmission, and storage are very high,” Hernandez said in a statement.
The study also looked at the economics of retrofitting natural gas plants to burn hydrogen, as opposed to building entirely new facilities, and found the price for converting a fossil fuel plant to burn hydrogen is high and such conversions likely would not take place until more sectors of the economy embrace hydrogen, either as a transportation fuel or for varied manufacturing and industrial purposes.
The authors also noted that “enormous investments” would be necessary to expand hydrogen production facilities to meet grid-scale needs. “With any of the climate solutions proposed today, we will need a carbon tax or carbon pricing; otherwise, nobody will switch to new technologies,” Gencer said in a statement.
The study looked at all peaking plants in California, using 2019 as the base year. The researchers looked at the costs of running natural gas-fired peakers, defined as plants operating 15 percent of the year to make up for intermittent energy resources. They also determined the amount of carbon dioxide released by those plants and the expense of abating those emissions.
The American Public Power Association recently issued a report that offers a perspective on where the emerging hydrogen market is in the U.S. and globally, what is driving the growing interest in hydrogen and what obstacles are preventing hydrogen technology from being able to scale-up.
Salt River Project To Expand Gas-Fired Plant to Integrate More Renewables, Boost Reliability
August 25, 2021
APPA News
August 25, 2021
Arizona public power utility Salt River Project (SRP) is seeking board approval to expand its Coolidge Generating Station, a quick-start natural gas power plant located in Arizona’s Southeast Valley.
The expansion will help SRP integrate more renewable energy resources into the power grid and allow SRP to provide reliable power to its rapidly growing customer base during times of peak electricity demand, including some of the hottest days in Arizona’s summer season, it noted in an Aug. 24 news release.
The Phoenix metropolitan area is experiencing population growth more than three times the national average and SRP is projecting significantly increased, near-term residential and commercial energy needs. This demand is rising especially as large industrial customers develop new and existing local operations.
If approved by the SRP Board, the expansion of the Coolidge Generating Station would add 820 megawatts (MW) of capacity produced by 16 natural gas turbines capable of ramping up to full production within 10 minutes.
“With the West facing power capacity constraints and lacking available power generation during peak energy usage periods, the proposed expansion of Coolidge Generating Station will help SRP reliably and safely serve energy at times of highest demand,” SRP said.
It will also steadily facilitate the addition of more renewable energy resources like solar and wind which can produce intermittent and varying power output. Added natural gas turbines will provide SRP customers quick-start, dependable energy that is available when renewable resources have fluctuations in output or are not producing power, and when battery systems are charging.
Because the proposed new gas turbines at Coolidge Generating Station can start quickly and will run in times of peak demand or when there is reduced renewable output, the added natural gas generation would not impact SRP’s ability to meet its sustainability goals, the utility noted.
SRP has committed to reducing carbon intensity by more than 65 percent in 2035 and by 90 percent in 2050 from 2005 levels. SRP’s sustainability commitments also include an increased pledge to add 2,025 MW of utility-scale solar energy by 2025. In addition, SRP plans to add 1,600 megawatt-hours of battery storage by 2023.
Moody’s Says Hydrogen’s Potential As Power Sector Fuel Is Enormous
August 23, 2021
by Paul Ciampoli
APPA News Director
August 23, 2021
Hydrogen’s potential as a fuel in the power sector and the broader economy is enormous, although electric and gas utilities are unlikely to be the primary demand growth driver of the hydrogen market over the next decade, Moody’s Investors Service says in a new report.
“Hydrogen’s growth potential rests in large part on its green appeal – specifically, its potential role in decarbonizing the economy, particularly the transportation, industrial, gas and power sectors,” the rating agency said in the Aug. 11, 2021 report.
Moody’s said that while hydrogen has enormous potential in power and heating applications, electric and gas utilities are unlikely to be the primary demand growth driver of the hydrogen market over the next decade, either in the U.S. or globally.
“In addition to high costs, there are significant efficiency losses associated with its production, which can range anywhere from around 30% to over 70% based on the technology used, making its production more expensive than the electricity or natural gas used to produce it. However, hydrogen is likely to play an important role in US efforts to eliminate carbon emissions from the power sector by 2035,” the report said.
While the U.S. consumes more than 11 million metric tons of hydrogen per year, its use is practically nonexistent in the power sector, Moody’s said.
At the same time, Moody’s said that hydrogen’s potential as a fuel in the power sector and the broader economy is huge.
The report notes that the National Renewable Energy Laboratory (NREL) expects U.S. demand for hydrogen to surge two- to fourfold by 2050, to around 1% to 14% of energy demand. Over the same period, the Department of Energy (DOE) estimates that the hydrogen economy could grow to $750 billion in annual revenue from an estimated $17.5 billion today.
Most of this demand growth is likely to come from the transportation sector, followed by industrial uses (refining, chemical, iron and steel and other), with building heat and power and power generation expected to account for around 19% of the demand by 2050, according to a report coordinated by the Fuel Cell and Hydrogen Energy Association, the rating agency went on to note.
Moody’s points out that hydrogen can already be blended with natural gas for use as a fuel for power generation, albeit with some limitations. Power equipment manufacturers are developing a new generation of gas turbines that can run on 100% hydrogen and there are several pilot projects and at least two larger power plants being developed in the U.S. that will initially burn blends of hydrogen and natural gas, before transitioning to 100% hydrogen, Moody’s said.
“Hydrogen can also be used as an energy carrier for long-term seasonal storage, reducing the need to curtail excess renewable energy production or using nuclear power and providing dispatch flexibility to the grid to help manage peak demand,” the report said.
Moody’s also said that national and state policies and regulations could help increase hydrogen use. It noted that DOE this year unveiled $160 million in federal funding for projects to develop technologies for the production, transport, storage and use of hydrogen. “Wider implementation of carbon instruments, such as allowances and taxes, could help make hydrogen more cost-competitive,” the report said.
Federal and state incentives are also available for the development of carbon capture, utilization and storage technology, an essential component in the production of “blue” hydrogen, which is produced from natural gas, according to Moody’s.
The American Public Power Association (APPA) recently issued a report that provides a perspective on where the emerging hydrogen market is in the U.S. and globally, what is driving the growing interest in hydrogen and what obstacles are preventing hydrogen technology from being able to scale-up.
In a recent blog, Patricia Taylor, Senior Manager, Regulatory Policy and Business Programs at APPA, notes that there are different motivations for the interest in hydrogen in the energy sector these days.
OUC Board Approves Possible Purchase of Plant To Enable Large-Scale Solar Production
August 16, 2021
by Paul Ciampoli
APPA News Director
August 16, 2021
The Orlando Utilities Commission’s (OUC) Board on August 10 approved a proposal that will allow OUC’s general manager and CEO to enter into an agreement to purchase the Osceola Generating Station, an idle 20-year-old 510-megawatt (MW) single-cycle natural gas-fired power plant located in Osceola County, Fla.
OUC noted that it was approached in May 2021 with an opportunity that would enable large-scale solar farms, mitigating the intermittency of solar power, which is the utility’s most viable source of renewable energy. The move also allows OUC to retire its oldest coal-fired power plant, Stanton Unit 1 located in East Orange County, Fla., at the utility’s Stanton Energy Center. In addition, the purchase further provides the utility an extra layer of resiliency because the Osceola site includes emergency backup fuel.
OUC said that the nearly $100 million deal to purchase and upgrade the inactive plant from Genova, a Texas-based private ownership group, will not change OUC’s commitment to its Electric Integrated Resource Plan (EIRP), the utility’s 30-year energy roadmap, to move away from all coal-fired generation by 2027. However, it would allow OUC to retire Unit 1, built in 1987, as opposed to the conversion to natural gas OUC previously announced in its EIRP in 2020.
The Osceola plant is comprised of three separate turbines – peakers that can turn on and off quickly, as opposed to the larger, older Stanton Unit 1 turbine that requires more fuel and takes many hours to turn on. The Osceola site can power up in just minutes.
OUC said it remains committed to meeting the EIRP’s objectives, which includes increasing solar energy and other renewable resources for electric generation and reducing carbon dioxide emissions by 50% by 2030 and 75% in 2040 before reaching net zero emissions by 2050.
OUC is aggressively increasing its reliance on solar energy, with plans to boost capacity to 270.5 megawatts by 2024.
Meanwhile, the utility is exploring back-up storage solutions and the use of other clean energy assets in addition to investing in electrification programs that would result in further carbon dioxide reductions and cleaner air for the community, it said.
Federal Legislation Calls For Nuclear Power Purchase Agreement Program
August 10, 2021
by Paul Ciampoli
APPA News Director
August 10, 2021
Reps. Elaine Luria, D-Va., and Dan Newhouse, R-Wash., introduced legislation that establishes an up to 40-year-long nuclear power purchase agreement program at the Department of Energy (DOE) and directs the Secretary of Energy to enter into one or more agreements to purchase nuclear power from reactors licensed after January 2020.
The bill, H.R.4834, also requires the Secretary of Energy to enter into one national security-related nuclear power purchase agreement prior to 2026 to provide reliable and resilient power in remote off-grid and emergency scenarios.
Luria and Newhouse were joined by Reps. Anthony Gonzalez, R-Ohio, and Scott Peters, D-Calif., in sponsoring the bill, which was introduced in late July.
The Nuclear Power Purchase Agreements Act has been endorsed by the U.S. Chamber of Commerce, Clear Path, the U.S. Nuclear Industry Council, the American Nuclear Society, the Nuclear Energy Institute, NuScale Power and the Nuclear Innovation Alliance.
In May 2021, NuScale Power and Washington State’s Grant County Public Utility District on announced the signing of a memorandum of understanding to evaluate the deployment of NuScale’s small modular reactor (SMR) technology in Central Washington State.
In January, Utah Associated Municipal Power Systems and NuScale Power signed agreements to facilitate the development of the Carbon Free Power Project that would deploy NuScale’s SMR design at the Idaho National Laboratory. Energy Northwest has the option to operate the SMR plant.
Northwest Power Pool Releases Details Of Proposed Resource Adequacy Program
August 9, 2021
by Peter Maloney
APPA News
August 9, 2021
The Northwest Power Pool (NWPP) and participating member utilities have released a design of a proposed resource adequacy (RA) program.
The report details elements of the program, including a “forward showing” program and an operational program, as well as a proposed governance framework. The report also provides details on how stakeholders affected by the program can participate.
The release of the report clears the way for the next phase of NWPP’s proposed resource adequacy effort. NWPP is preparing to launch the next phase in which a forward showing program will provide informational, non-binding resource adequacy requirements for the winter of 2022. NWPP said it would accept participation agreements for the next stage of the program beginning Aug. 16 and running through Sept. 30, which will serve as a beta test for the proposed program design.
The integrated regional power system is in transition, NWPP said in the report. The impending retirement of several thermal generators within and outside the region, which includes the Western U.S. and Canada, mixed with increasing variable energy resources, has led to questions about whether the region will continue to have an adequate supply of electricity during critical hours, according to the report.
In the past four years, several studies have identified an urgent and immediate challenge to the regional electricity system’s ability to provide reliable electric service during high demand conditions.
“These developments threaten to upset the balance of loads and resources within the region and, if not properly addressed, will increase the risk of supply disruptions during winter and summer, increase financial risk for utility customers, and hinder the ability of the system to meet environmental goals and legal requirements,” the report said.
The resource adequacy effort began early in 2019 when the NWPP and a coalition of NWPP members initiated the program. The contemplated resource adequacy program “seeks to enhance and increase reliability for the footprint while maintaining existing responsibilities for reliable operations and observing existing frameworks for planning, purchasing, and delivering energy,” the report said.
“We believe the resource adequacy program will provide multiple benefits to the region as well as participants, including reliability, cost savings and improved visibility and coordination,” Frank Afranji, NWPP president, said in a statement.
There are many forms of resource adequacy – capacity, energy and flexibility – but NWPP’s program focuses on creating a capacity resource adequacy program. Additional adequacy programs may also be necessary following the implementation of the capacity program, the report said. “If additional programs are desired, a similarly discrete decision and implementation process would need to be undertaken to design and implement such programs,” the report said.
The report also noted that the proposed resource adequacy program does not replace or supplant the resource planning processes used by states or provinces or the regulatory requirements of the Federal Energy Regulatory Commission (FERC), North America Electric Reliability Corporation, or the Western Electricity Coordinating Council, but is designed to supplement and complement those processes and requirements.
The resource adequacy program design and implementation will have two components: a forward showing program and an operational program. The forward showing program is designed to ensure that the NWPP footprint has enough demonstrated capacity, well in advance of required performance, to meet the established reliability metrics. It establishes regional metrics for the NWPP footprint, the qualified capacity contribution and effective load-carrying capability of various resources, as well as deliverability expectations, and determines the periods for demonstrating adequacy.
The operational program seeks to achieve a balance between planning while providing flexibility in order to protect customers from unreasonable costs. It creates a framework to provide participants with pre-arranged access to capacity resources in the program footprint during times when a participant is experiencing an extreme event.
Under the current proposal, NWPP would become a public utility as defined by the Federal Power Act.
NWPP would also need to meet independence requirements established by FERC so that the power pool would have financial independence from individual participants in order to ensure there is no undue discrimination for the NWPP.
NWPP members include a number of public power entities.
TVA to spend $1 billion building 1,500 MW of gas turbines
July 13, 2021
by Peter Maloney
APPA News
July 13, 2021
The Tennessee Valley Authority (TVA) plans to invest $1 billion to build three new gas-fired combustion turbines totaling 1,500 megawatts (MW)
The planned gas turbines are being built at the site of shuttered coal plants in Tuscumbia, Alabama, and Paradise, Kentucky, and will replace combustion turbines scheduled for retirement.
The new plants will bring in about 185 jobs at each location to prepare each site and construct the units, TVA said.
“As we continue to evolve our generation portfolio, natural gas is the right choice at this time because it provides the flexibility and reliability we need to add more solar energy,” Jacinda Woodward, senior vice president of power operations at TVA, said in a statement.
“It’s important to remember that solar power is an intermittent generation source — natural gas delivers reliable electricity even when the sun doesn’t shine,” Woodward said. She added that TVA will continue to consider natural gas an option for replacement generation as it studies the closing of its remaining coal fleet while adding about 10,000 MW of new solar power by 2035.
“Natural gas helps us achieve a 70% reduction in emissions by 2030, 80% by 2035 and we believe it is possible, with new technologies, to achieve net-zero by 2050,” Woodward said.
The plants scheduled for retirement are at TVA’s Allen Reservation on the Mississippi River, five miles southwest of Memphis, Tenn., and at the utility’s Johnsonville Reservation in Tennessee. The plants have a combined capacity of 1,400 MW and have “received little recent investment, are 40 or more years old and require replacement to ensure reliability,” according to TVA.
“Current and retired coal plant sites are prime locations for new gas generation because the electrical infrastructure is already in place,” Woodward said.
The new gas plants will require upgrades of the existing natural gas supplies, as well as connections to TVA’s existing transmission lines, including upgrades to those lines.
While the environmental assessment for the proposed plants was under review and open for comment, TVA noted that the most frequently mentioned comments related to climate impacts, environmental justice, analysis of alternatives, and cumulative impacts.
In its environmental assessment, TVA concluded that the proposed plants would not be “a major federal action significantly affecting the environment and issued a finding of no significant impact.”
TVA currently operates 108 natural gas and fuel oil-fired generators totaling more than 12,000 MW at 17 sites, nine in Tennessee, five in Mississippi, one in Alabama, and two in Kentucky.