EIA Forecasts Drop In Natural Gas Generation As Renewable Energy Resources Increase
January 29, 2022
by Paul Ciampoli
APPA News Director
January 29, 2022
The U.S. Energy Information Administration (EIA) expects rising electricity generation from renewable energy resources such as solar and wind will reduce generation from fossil fuel-fired power plants over the next two years.
The forecast share of generation for U.S. non-hydropower renewable sources, including solar and wind, grows from 13% in 2021 to 17% in 2023, EIA said on Jan. 18 in its latest Short-Term Energy Outlook.
EIA is also forecasting that the share of generation from natural gas will fall from 37% in 2021 to 34% by 2023 and the coal share will decline from 23% to 22%.
“One of the most significant shifts in the mix of U.S. electricity generation over the past 10 years has been the rapid expansion of renewable energy resources, especially solar and wind,” EIA noted.
The amount of solar power generating capacity operated by the U.S. electric power sector at the end of 2021 is 20 times more than it was at the end of 2011, and U.S. wind power capacity is more than twice what it was 10 years ago.
Another significant shift in the generation mix has been a steady decline in the use of coal-fired power plants since their peak output in 2007 and the increasing use of natural gas, primarily as a result of sustained low natural gas prices, EIA said.
But that trend reversed in 2021 when the cost of natural gas delivered to U.S. electric generators averaged $4.88 per million British thermal units, more than double the average cost in 2020. As a result, the share of generation from natural gas declined from 39% in 2020 to 37% last year, while the share of generation from coal rose for the first time since 2014 to average 23%.
In its current Short-Term Energy Outlook, EIA forecasts that most of the growth in U.S. electricity generation in 2022 and 2023 will come from new renewable energy sources.
EIA estimates that the electric power sector had 63 gigawatts (GW) of existing solar power generating capacity operating at the end of 2021. “We forecast solar capacity will grow by about 21 GW in 2022 and by 25 GW in 2023. We expect that 7 GW of wind generating capacity will be added in 2022 and another 4 GW in 2023. Operating wind capacity totaled 135 GW at the end of 2021,” EIA said.
“Our forecast of growth in renewable electricity generation over the next two years leads to our forecast of a reduced need for fossil-fueled generation,” the federal agency said.
Although it expects natural gas prices for electric generators to decline, the operating costs of renewable generators will continue to be generally lower than natural gas-fired units, according to EIA.
“We expect that regions of the country with the largest increases in renewable capacity, such as Texas and the Midwest/Central regions, will experience the largest reductions in natural gas generation.”
Panelists Detail Benefits Of Hydropower, Recommend Congressional Actions
January 20, 2022
by Paul Ciampoli
APPA News Director
January 21, 2022
Panelists appearing at a recent Senate Energy and Natural Resources Committee hearing detailed the key role that hydropower plays in the nation’s power supply mix and outlined actions that lawmakers could take to support hydropower going forward.
The committee heard from Jennifer Garson, Acting Director for the Water Power Technologies Office (WPTO) in the Department of Energy’s (DOE) Office of Energy Efficiency and Renewable Energy, Camille Touton, Commissioner for the Bureau of Reclamation, Scott Corwin, Executive Director of the Northwest Public Power Association (NWPPA), and Malcolm Woolf, President and CEO of the National Hydropower Association (NHA). NWPPA is a member of the American Public Power Association (APPA).
The majority of committee members at the Jan. 11 hearing, including Chairman Joe Manchin (D-WV) and Ranking Member John Barrasso (R-WY), highlighted the benefits of hydropower.
“Unlike most other renewable energy resources, hydropower generation provides baseload electricity,” Manchin noted in his opening remarks at the hearing. “It’s also flexible which means that the generation capacity is available when we need it, and it has the ability to respond to changing grid conditions and adjust output accordingly.”
That makes hydropower “unique and valuable for maintaining grid reliability as more intermittent resources come online,” he said.
“Given the baseload attributes of hydropower, we need to make sure our existing capacity remains operational,” Manchin said.
He noted that between now and 2030, 281 facilities that represent nearly 14 gigawatts of hydropower generation and pumped storage hydropower capacity are up for Federal Energy Regulatory Commission relicensing, which is close to a third of all U.S. non-federal hydropower capacity.
“Between low hydroelectricity prices and the high capital costs of maintenance and retrofits required for relicensing, there is a real possibility that many of these plants could face closure,” he said.
“The bipartisan infrastructure bill that President Biden signed into law in November made a historic investment in new and existing incentives for new hydropower production, efficiency upgrades, and infrastructure and environmental improvements,” Manchin said.
The bill also included $8.2 billion for western water infrastructure at the Bureau of Reclamation, which included investments in aging infrastructure and hydropower facilities. These resources will help to ensure that we keep vital hydropower capacity online, Manchin pointed out.
For his part, Barrasso noted that until recently, hydropower was the nation’s largest source of renewable energy.
“Hydropower can once again be our largest source of renewable energy if we maintain our existing hydroelectric dams and encourage the installation of turbines on our nation’s non-powered dams,” he said.
“Hydropower’s clearly an important component of an all of the above energy strategy. We should encourage more hydropower generation,” Barrasso said.
Meanwhile, in his prepared testimony for the hearing, Corwin said that while hydropower “is one of our oldest forms of generating electricity it is also a resource for the future because of its unique attributes enabling newer forms of generation. These qualities include a high level of flexibility that matches very well with the increasing need to balance intermittent renewable generation sources such as wind and solar. It lends system stability, reliability, ramping capacity, resilience, and effective integration of other resources.”
Corwin also said in the testimony that it is “efficient in its conversion of energy, uses reliable time-tested technology, and can be relatively low-cost. While extensive use of energy stored in batteries may be in our future, the ability to store the energy of falling water is serving us today and provides the fast response needed on demand. Significant pursuit of development of pumped storage hydropower projects will serve to create even more capacity for meeting peak demand, avoiding reliability events, and balancing other resources.”
NHA’s Woolf pointed out that hydropower “plays an essential yet often-overlooked role in enhancing grid reliability by, for example, providing nearly half of the nation’s black start capability, which is vital in re-starting the grid in the event of a blackout.”
Woolf made several recommendations for Congress to take related to hydropower.
He said that Congress needs to address the hydropower license and relicensing process.
“The uncertainty about the time and cost involved is dramatically at odds with the urgency of addressing climate change and the upcoming wave of hydropower relicensing proceedings,” Woolf said.
Congress should also enact Improvements to promote new renewable generation at existing nonpowered dams, Woolf said.
In 2020, hydropower provided 7.2% of the electricity on the grid, accounting for 37% of U.S. renewable electricity generation, noted Garson.
“With the advent of a greater level of variable renewable generation on the U.S. grid, hydropower’s role is more critical than ever,” she said.
Corwin and Woolf called for federal incentives for hydropower on par with those available to other clean energy resources and stressed the importance of ensuring any such incentives are accessible to public power utilities and rural electric cooperatives.
They thanked Sens. Maria Cantwell (D-WA) and Lisa Murkowski (R-AK) for introducing S. 2306, the Maintaining and Enhancing Hydroelectricity and River Restoration Act of 2021, to create a 30 percent tax credit to support upgrades at existing hydropower dams for dam safety, environmental improvements, and grid resilience enhancements.
They also thanked Senator Ron Wyden (D-OR) for including a narrower version of the tax credit proposed by Senators Cantwell and Murkowski in the latest tax title of the Build Back Better Act, though the legislation is currently stalled.
APPA Submits Statement For the Record
APPA submitted a Statement for the Record to the Committee related to the hearing.
APPA said it supports and agrees with the testimony submitted by Corwin.
“Making full use of the nation’s hydropower resource is key to ensuring that the nation’s grid remains reliable and resilient, and that utilities can meet emission reduction goals,” APPA said.
“Hydropower is a source of emissions-free, base-load power. Furthermore, hydroelectric generators can be started or stopped quickly, which makes them more responsive than most other energy sources for meeting demand for electricity at its “peak” or highest volume,” it said.
APPA noted that there is a significant potential for new hydropower to be generated at non-powered dams throughout the country and to increase output at existing hydropower facilities. “But there are excessive barriers to tapping this potential.”
The Federal Energy Regulatory Commission (FERC) is the primary federal agency responsible for the licensing and relicensing of such non-federal hydroelectric projects, but the process can be lengthy, difficult, costly, and uncertain for applicants, APPA said.
“Critical new additions to existing hydropower facilities are languishing under bureaucratic and often contradictory processes that can span a decade or more or which simply become too costly,” APPA said. The byzantine licensing and permitting processes are also a significant impediment to simply maintaining existing hydropower capacity.”
“We simply cannot afford to lose existing hydropower capacity without threatening to miss emission reduction goals and grid resiliency. Congress must streamline the licensing process by establishing FERC as the lead agency, giving it the authority to set and enforce schedules for the issuance of all resource agency authorizations and studies, and ensure any ‘mandatory conditions’ are directly relevant to the project,” APPA said.
APPA said that another significant obstacle to the growth and retention of non-federal hydropower capacity are insufficient federal tax incentives on par with those available to other clean energy resources.
APPA strongly supports S. 2306, which seeks to address this issue. The bill would create a 30 percent tax credit to support upgrades at existing hydroelectric dams for qualified dam safety, environmental, and grid resilience improvements. “Critically, this credit would be available as a direct payment to public power utilities,” the trade group said.
APPA said it appreciates the efforts of Wyden to include a version of the Cantwell-Murkowski credit in the updated text of the tax title of the Build Back Better Act currently pending in Congress.
Wyden’s draft includes a provision establishing an investment tax credit for five years for “hydropower environmental improvements” at existing hydropower facilities, defined to include investments to improve fish passage, water quality, and habitat maintenance. Importantly, this credit would be available to public power via “direct pay.” Moreover, the draft includes the full value of the production tax credit for building new hydropower at existing dams, marine energy, and other incremental new hydropower, extended for ten years.
Finally, APPA said that federal hydropower and power marketing administrations (PMAs) are critical, though often overlooked, elements of the nation’s power supply.
APPA supports the continued existence and federal ownership of the PMAs and the sale of federally generated hydropower at cost-based rates.
“APPA strongly opposes any efforts to disproportionately assign costs to federal hydropower users for which they receive no additional benefits,” it said, and urged Congress, the Corps, Reclamation and the PMAs to work closely with customers as the system confronts challenges such as the ongoing megadrought in the West.
Connecticut Municipal Electric Energy Cooperative Transfers Plant Ownership
January 12, 2022
by Paul Ciampoli
APPA News Director
January 12, 2022
The Connecticut Municipal Electric Energy Cooperative (CMEEC) recently transferred ownership of its Alfred L. Pierce 84-megawatt electric generating facility located in Wallingford, Conn., to MPH AL Pierce LLC.
MPH AL Pierce LLC is a Delaware limited liability company that is indirectly owned by affiliates of Hull Street Energy (HSE), a private equity firm.
CMEEC CEO Dave Meisinger noted that since its repowering in 2007, the Pierce plant has been a valuable project for CMEEC and its members, but added that the continued operation of the plant was no longer projected to provide the same wholesale rate stability and overall benefits that CMEEC’s members have come to expect.
“The sale of the Pierce plant is an important step in the alignment of CMEEC’s mission to add economic value to the communities we serve while thoughtfully addressing the impacts of climate change,” he said.
“We are confident that HSE will operate the plant in a manner that will contribute to the reliability of the New England electric grid as our wholesale market structure continues to evolve in response to regional decarbonization goals.”
The parties had previously announced the signing of the asset purchase agreement on October 8, 2021.
CMEEC is a political subdivision of the State of Connecticut created in 1976.
It is a non-profit municipal joint action electric supply agency that provides the power supply requirements, at wholesale, of six municipal electric utilities with retail electric service territories in Connecticut as well as for other customers who purchase power at wholesale.
Its municipal electric utility members are Bozrah Light & Power, Jewett City Department of Public Utilities, Groton Utilities, Norwich Public Utilities, South Norwalk Electric and Water, and The Third Taxing District of Norwalk Electric Division.
Grand Coulee Dam Overhaul Project Ensures Another 30 years Of Hydropower In The Northwest
January 10, 2022
by Paul Ciampoli
APPA News Director
January 10, 2022
The U.S. Bureau of Reclamation and the Bonneville Power Administration (BPA) recently announced the completion of the major overhaul of three hydroelectric power generating units inside the Nathaniel “Nat” Washington Power Plant at Grand Coulee Dam.
The project will ensures another 30 years of hydropower delivery in the region.
Located on the Columbia River about 90 miles west of Spokane, Wash., the Grand Coulee Dam is the largest power generating complex in the United States.
The dam can generate more than 6,800 megawatts (MW) and annually supplies more than 20 billion kilowatt hours of electricity to the region.
The project involved complete disassembly of each 805-MW hydroelectric unit, refurbishing each to ensure all of the mechanical and electrical surfaces were restored and returned to like-new condition.
Approximately 6.5 million pounds of steel were removed from each unit once every component down to the turbine runner was fully taken apart. While the units were disassembled, each component was sand blasted, welded, ground, polished, and then repainted before reassembly. Restoring the mechanical and electrical components results in less friction. As a result, the generating units operate with less wear and tear, making them more reliable and efficient.
Grand Coulee Dam provides about one-quarter of the total generation of hydroelectric power for the Federal Columbia River Power System and is one of 31 federal dams that generate more than half of the hydropower in the Northwest.
The Nathaniel “Nat” Washington Power Plant was built between 1967 and 1975 and is the largest of the four power houses. The plant contains six generating units capable of producing more than 4,200 MW, and it contributes to about two-thirds of the total power generated by the dam.
Completed in 1941, Grand Coulee Dam serves as a multipurpose facility, providing water for irrigation, hydroelectric power production, flood control, fish and wildlife conservation, and recreation. The Grand Coulee Power facility is comprised of 33 generators in three power plants, the John W. Keys III Pump-Generating Plant, and three switchyards.
BPA delivers power generated by the federal dams, one nonfederal nuclear plant and several small nonfederal power plants, to more than 140 Northwest electric utilities, serving millions of consumers and businesses in Washington, Oregon, Idaho, western Montana and parts of California, Nevada, Utah, and Wyoming.
Chelan County PUD To Supply Hydropower To Avista
January 5, 2022
by Paul Ciampoli
APPA News Director
January 5, 2022
Washington State’s Chelan County Public Utility District (PUD) and investor-owned utility Avista have finalized a contract for hydropower from the PUD’s two hydro projects on the Columbia River.
The 20-year contract will increase Avista’s carbon-free resources toward its 2030 renewable energy goals, as well as contributes flexible capacity to identified needs in Washington and Idaho. The acquisition closes out Avista’s 2020 Renewable request for proposals.
The competitively priced contract provides Avista with 5% of the output from the PUD’s Rock Island and Rocky Reach hydropower projects from 2026 through 2030 and increases to 10% of the output from these projects in 2031-2045.
The contract includes both carbon-free energy attributes provided by hydropower as well as dispatchable capacity to help Avista meet peak energy needs during high customer usage times.
Navajo Tribal Utility Authority Seeks Power Supply Proposals
January 4, 2022
by Paul Ciampoli
APPA News Director
January 4, 2022
The Navajo Tribal Utility Authority (NTUA) recently issued a request for proposals (RFP) seeking power and energy for the Navajo Nation.
The RFP, which was issued in December 2021, seeks a three-year, five-year, and seven-year firm supply of power and energy to be delivered to the trading hubs at the Four Corners/Western Area Power Administration (WAPA) Shiprock and WAPA Pinnacle Peak delivery points.
Proposals are due by Feb. 4, 2022 and the RFP is available for download here.
Arizona-based NTUA was established on Jan. 22, 1959, to address the absence of utilities on the 27,000 square-mile Navajo Nation. Since then, NTUA has grown into a self-sustaining, not-for-profit, successful tribally-owned enterprise.
NTUA is organized for the operation, maintenance and expansion of electric, communications, natural gas, water, wastewater and generation, including photovoltaic (solar) services for the Navajo people at a low and reasonable cost.
In addition to providing multi-utility services, other objectives of NTUA are to promote employment opportunities on the Navajo Nation and to improve the health and welfare of the residents of the Navajo Nation while improving the standard of life.
U.S. Power Sector’s Use Of Water Continued Downward Trend
December 20, 2021
by Paul Ciampoli
APPA News Director
December 20, 2021
The U.S. electric power sector’s cooling water withdrawals fell 10.5% from 53.1 trillion gallons in 2019 to 47.5 trillion gallons in 2020, continuing the downward trend in withdrawals, the U.S. Energy Information Administration (EIA) reported on Dec.17.
The decline has been driven by the increased use of renewable and natural gas-fired generation in place of coal-fired generation, as well as less use of once-through cooling technologies, EIA noted.
As the fuel mix has shifted to less water-intensive energy sources, the water intensity of U.S. power generation — the average amount of water withdrawn per unit of electricity generated — has declined from 14,928 gallons per megawatt hour (gal/MWh) in 2015 to 11,857 gal/MWh in 2020, EIA said.
It noted that thermoelectric power plants — including coal, nuclear, and natural gas plants — boil water to create steam, which then spins a turbine to generate electricity. Cooling water is passed through the steam leaving the turbine to cool and condense the steam. This step reduces the steam’s exit pressure and recaptures its heat, which is then used to preheat fluid entering the boiler.
According to EIA, U.S. thermoelectric plants are the largest source of U.S. water withdrawals, accounting for more than 40% of total U.S. water withdrawals in 2015.
The changing U.S. electricity generation mix accounts for approximately 80% of the downward trend in water withdrawals by the electric power sector.
EIA noted that natural gas-fired generation uses a more energy-efficient technology to produce electricity than coal and has a lower water withdrawal intensity than coal. Natural gas combined-cycle generation had an average water withdrawal intensity of 2,793 gal/MWh in 2020, compared with 21,406 gal/MWh for coal.
The share of renewable generation, which on average has a very low water withdrawal intensity, also significantly increased from 2015 to 2020.
The remaining 20% of water withdrawal reductions came from the reduced use of once-through cooling systems.
OUC Board Of Commissioners Approves Retirement Of Coal-Fired Unit
December 17, 2021
by APPA News
December 17, 2021
The Board of Commissioners for Florida public power utility Orlando Utilities Commission (OUC) on Dec. 14 formally approved the retirement of Stanton Energy Center’s (SEC) Unit 1 by no later than 2025 and the conversion of SEC’s Unit 2 to natural gas by no later than 2027.
Previously, Unit 1, OUC’s oldest coal-fired power plant, had been slated for conversion to natural gas.
The official adoption by the Board of Commissioners “is further proof of our commitment to meet our goal of Net Zero CO2 emissions by 2050 with interim targets of 50% by 2030 and 75% in 2040,” said Clint Bullock, OUC General Manager and CEO, in a statement. “The retirement of Unit 1 also is a significant milestone toward fully eliminating coal-fired generation no later than 2027. As we continue our transition to clean energy, operational flexibility is key to maintaining the reliability, resiliency and affordability our customers expect.”
The retirement of Unit 1 became possible with the recent purchase of the Osceola Generating Station, a 510-megawatt (MW) simple-cycle natural gas-fired power plant located in Harmony in Osceola County, Fla.
OUC said that as it aggressively increases its reliance on solar energy, OSG will be used to mitigate solar production fluctuations to maintain system-wide electric reliability. Currently, the facility is undergoing renovations and testing and will be fully operational by no later than 2025.
In December 2020, OUC leadership recommended significantly reducing the use of coal by no later than 2025 and eliminating it entirely by no later than 2027. The announcement was the result of the utility’s Electric Integrated Resource Plan.
OUC said that it is on its way to meeting its strategic objectives, which include continued investments in renewable energy and energy efficiency and driving the adoption of vehicle electrification and energy storage.
DOE Study Demonstrates Hydropower’s Ability To Support Grid Reliability
December 9, 2021
by Peter Maloney
APPA News
December 9, 2021
Hydropower can be a valuable resource in maintaining bulk power system reliability, according to a new report from the Department of Energy’s (DOE) HydroWIRES initiative.
HydroWIRES was launched in April 2019 by the DOE’s Water Power Technologies Office to understand and improve the contributions of hydropower and pumped storage hydropower (PSH) to reliability, resilience, and integration in the electric system.
The study analyzed the role of hydropower over a range of extreme events using a combination of historical data and simulation-based analysis.
The study looked at two main categories of events: the sudden loss of large generation assets and changes in net load due to extreme weather such as heat waves and cold snaps.
The scenarios used to evaluate hydropower’s role during extreme events were applied only to the Western Interconnection where hydropower constitutes between 20 and 25 percent of generation capacity.
The study found that hydropower could be critical in stabilizing the Western Interconnection after a sudden loss of generation. Historical data and simulation showed that hydropower is a major resource for inertial and governor response during extreme events. Specifically, the study found that hydropower facilities contribute between 30 and 60 percent of governor response to help stabilize system frequency after an outage.
Hydropower facilities also have significant reactive power capability that can help maintain voltage stability during extreme events, the study found. And while coal and nuclear plants can also provide reactive power, hydropower, like gas-fired plants, do not always operate at full power, enabling them to provide more reactive power support when needed. The study showed that hydropower is a major source of reactive power under all seasonal, loading, and water availability conditions.
The study also found that hydropower’s storage capability and dispatch flexibility are critical to ensuring system reliability during extreme weather events. Simulations of periods of extreme weather when wind and solar generation were significantly depressed, even though the impact on system load was not extreme, showed that hydropower resources were able to fill in energy and capacity gaps.
At least 40 percent of the nation’s hydropower resources are pumped storage and peaking or reservoir hydropower plants that can store water to produce electricity at times of greatest need. At least 18 percent of hydropower resources are run-of-river plants.
During a multi-day cold wave scenario, hydropower resources’ long-term storage capability was key in ameliorating the situation, the study found. In both historical and simulated scenarios, hydropower can contribute “significantly to grid reliability and resilience during extreme events,” the study found.
“The analyses in this study suggest that as the magnitude and frequency of extreme and stressful grid conditions increase, hydropower will continue to play a vital role in power system reliability and resilience,” the report’s authors concluded, adding, however, that “more work needs to be done to fully assess the role of hydropower under all potential combinations of future grid states and extreme events.”
Power Plant Coal Stockpiles Fall To Lowest Levels Since 1978: EIA
December 8, 2021
by Peter Maloney
APPA News
December 8, 2021
Coal stockpiles at electric power plants are at their lowest levels since 1978, according to the Energy Information Administration (EIA).
Stockpiled coal dropped to 80 million metric tons in September, their lowest level since March 1978 when stockpiles hit 77 million metric tons, according to EIA data.
The federal agency attributed the decline to two factors: less coal is needed as coal plants continue to retire and increased generation by coal plants over the summer reduced coal inventories.
In 2019, Moody’s Investors Service projected that utility demand for coal would decline significantly between 2020 and 2030, reducing coal-fired generation to as little as 11 percent of overall U.S. power generation, down from 27 percent in 2018.
Last summer, Moody’s predicted coal company earnings would fall by 50 percent in 2020 because of weak fundamentals and the effects the COVID-19 economic slowdown. The ratings agency also predicted a 25 percent drop in thermal coal production in 2020.
Coal plant operators typically stockpile more coal than they can burn in a month. Generating plants consume the most coal during the summer and winter months, causing stockpiles to drop to their lowest levels in the spring and fall and prompting generators to build back their reserves. However, physical delivery constraints in the supply chain can limit how quickly coal generators can increase their stockpiles, the EIA noted.
Nonetheless, coal stockpiles at generating plants, as measured by the “days to burn” metric, remain within recent historic parameters, the EIA said. “Because of less coal consumption as well as coal capacity retirements over the past three years, the days of burn of U.S. coal remain within the typical range, even though total stocks are low,” the EIA said.
For bituminous coal plants, which are mostly in the eastern United States, the average number of days of burn was 88 days in September, a slight increase from the 86 days of burn recorded by the EIA in August. The average number of days of burn for subbituminous units, which are mostly in the western United States, was 82 days in September 2021, the EIA noted.
The EIA, noting the long-term trend of declining coal consumption, also said many U.S. coal mines have begun to close. That trend, combined with supply chain disruptions, has created some concerns about the ability of coal-fired generators to replenish stockpiles to last through the winter.
Grid operators are, however, closely monitoring coal inventories. As an example, the EIA cited temporary changes taken by the PJM Interconnection regarding minimum inventory requirements to provide more flexibility for coal-fired generators.