Texas Power Plant Sends Emissions Free Electricity To The Grid From A Gas Plant
November 22, 2021
by Peter Maloney
APPA News
November 22, 2021
A zero emissions natural gas-fired power plant last week, for the first time, contributed electric power to the Electric Reliability Council of Texas (ERCOT) grid.
The power comes from NET Power’s 50-megawatt (MW) test facility in La Porte, Texas. NET Power’s technology mixes natural gas with oxygen, rather than air from the atmosphere, allowing the gas to burn more efficiently and at higher temperature and with fewer emissions.
Combustion releases carbon dioxide (CO2) that is captured under pressure as supercritical CO2 that is then is used to propel the plant’s turbine. After the CO2 leaves the turbine, it is stripped of water and either captured for sale for industrial processes or is piped back to be reused in the plant’s combustor.
NET Power is co-owned by Exelon Generation, McDermott International, 8 Rivers Capital, and Oxy Low Carbon Ventures (OLCV), a subsidiary of energy company Occidental.
NET Power, based in Durham, North Carolina, says it is working with “multiple clients worldwide” to develop utility-scale NET Power plants, with initial projects aiming to come online “in the next five years.” All the CO2 by its commercial power plants will be either utilized or permanently stored, the company said.
NET Power plants produce only electricity, water, and pipeline ready CO2, while “operating at high-efficiency, comparable to conventional power plants,” the company says.
NET Power does not manufacture its own equipment. It licenses its processes to other companies. Toshiba supplied the combustor and turbine for the La Porte test facility and was a partner in the demonstration project.
NET Power is working on deploying commercial scale versions of technology with a recently announced 300-MW project in Alberta, Canada, and four other projects under development in the United States and the United Kingdom.
Seattle City Light, National Labs Studying Hydrogen’s Potential As A Truck Fuel
November 15, 2021
by APPA News
November 15, 2021
Seattle City Light, in partnership with Pacific Northwest National Laboratory (PNNL), and Sandia National Laboratories, is embarking on studies to explore the potential of using hydrogen instead of fossil fuels for medium- and heavy-duty vehicles.
The studies are being supported by awards totaling $2.12 million from the Department of Energy, and they are designed to help Seattle City Light and the Port of Seattle to meet their emission reduction goals. Partners in the studies also includes The Northwest Seaport Alliance (NWSA) and PACCAR/Kenworth.
The City of Seattle has set a goal of reducing total core greenhouse gas emissions 58 percent by 2030 and becoming carbon dioxide neutral by 2050.
One of the studies, Analytic Framework for Optimal Sizing of Hydrogen Fueling Stations for Heavy Duty Vehicles at Ports, will explore the potential of shifting from fossil fuel to clean hydrogen as fuel to power medium-and heavy-duty vehicles, including heavy equipment such as forklifts, drayage trucks and cranes.
The study will also look at the potential to scale up the technology if demand for hydrogen increases, including the potential to use the energy stored as hydrogen to power cruise or cargo ships while they’re being loaded and unloaded.
That study is funded with a $1.35 million award from the Department of Energy (DOE), and $150,000 from Seattle City Light.
The second study, Large-scale Hydrogen Storage – Risk Assessment, Seattle City Light and the Port of Seattle will assess the risks and benefits associated with scaling hydrogen produced using renewable resource to a level large enough to serve multiple maritime-related and utility uses.
At that scale, hydrogen could potentially be used for propulsion for tugboats, commercial fishing vessels and passenger ferries and to accommodate a significant portion of drayage trucks and cargo handling equipment serving the port. The research will also look at the requirements of using clean hydrogen as a fuel for larger ships.
The second study is being funded with a $770,000 award from the DOE, $185,000 from Seattle City Light, and $145,000 from the Port of Seattle.
The project partners are projecting a two-year timeframe to produce the final project recommendations.
“It is more important than ever for Seattle City Light to collaborate with our customers who want to confront the climate crisis by decarbonizing their operations,” Debra Smith, City Light’s general manager and CEO, said in a statement. “We are excited to partner with these agencies to implement a cleaner future for our customers at the port and our region as a whole.”
Several public power utilities across the country are exploring the emissions reduction potential of hydrogen fuel, including New York Power Authority, OUC in Florida, and Los Angeles Department of Water and Power.
In the Pacific Northwest, Douglas County Public Utility District is working under a $1.9 million grant to demonstrate the first hydrogen fueling station for fuel cell electric vehicles in Washington state. And the Eugene Water and Electric Board in Oregon is developing a renewable hydrogen production facility.
NYPA Renewable Hydrogen Demonstration Project To Start In November
October 26, 2021
by Paul Ciampoli
APPA News Director
October 26, 2021
The New York Power Authority (NYPA), in collaboration with project partners, will start a demonstration project in November to assess the potential of substituting renewable hydrogen for a portion of the natural gas used to generate power at its Brentwood Power Station on Long Island.
Project partners are the Electric Power Research Institute (EPRI), General Electric (GE), Airgas, an Air Liquide company, Sargent & Lundy, and Fresh Meadow Power.
Representatives from the project partner organizations were on site in Brentwood on Oct. 25 to view progress on plant readiness to begin the project.
The NYPA-led, first-of-its-kind demonstration will evaluate the effects of different concentrations of hydrogen blended with natural gas at regular intervals to assess the blend’s effect on reducing greenhouse gas emissions and its overall system and environmental impacts, including nitrogen oxide emissions.
At the close of this short-term project, peer-reviewed results will be shared with the industry and public to better inform what efforts can help New York State reach its goal of reducing carbon emissions 85 percent by 2050. The project is expected to last between six and eight weeks.
NYPA’s Brentwood Power Station, which is operated by a GE LM-6000 combustion turbine fueled by natural gas, was commissioned in 2001 to increase power generation capacity for Long Island and New York City in anticipation of shortages.
As the gas turbine’s original equipment manufacturer, GE will supply a state-of-the art hydrogen/natural gas blending system and support the project’s planning and execution.
Sargent & Lundy, acting as the engineer of record for the project, will provide overall engineering and safety reviews.
Airgas is the supplier of renewable hydrogen and Fresh Meadow Power is providing piping system design, material procurement and installation services.
EPRI conducts research, development, and demonstration projects, with a focus on electricity generation, delivery, and use in collaboration with the electricity sector, its stakeholders and others.
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.
LES Customers Helped Reduce Peak Summer Demand Through Utility Program
October 22, 2021
by Paul Ciampoli
APPA News Director
October 22, 2021
Participants in a Lincoln Electric System (LES) program this summer helped the Nebraska public power utility reduce peak summer demand by approximately four megawatts. This was accomplished through 15 events that adjusted thermostat temperatures thanks to program participants.
“Four megawatts is the equivalent power demand of eight big-box retail stores,” noted Marc Shkolnick, manager for Energy Services at LES. “By having the ability to reduce peak demand with the help of our customers, LES can cost-effectively delay the need to add another generating source to its portfolio.”
LES launched Peak Rewards in 2018 to work with residential and small commercial customers to better manage the system’s peak demand through internet-connected thermostat adjustments.
Customers with qualifying, internet-connected thermostats controlling their central air conditioning system are eligible to participate. They are rewarded with monetary incentives to enroll and reduce electricity use during periods of high demand.
Incentives come in the form of a one-time $25 Amazon e-gift card for enrolling. There is also a $25 bill credit after the close of each program year.
“During our peak demand season, we assess historical usage trends alongside a 15-day weather forecast every morning to help us decide if calling an event that day is necessary to minimize our monthly peak demand,” said Lee Anderson, supervisor, System Energy Maintenance at LES.
Massachusetts Public Power Utilities Extend Hydropower PPAs
October 10, 2021
by Paul Ciampoli
APPA News Director
and Peter Maloney
APPA News
October 10, 2021
Middleborough Gas and Electric Department (MGED) and Taunton Municipal Lighting Plant (TMLP) in Massachusetts have extended power purchase agreements for hydroelectric supplies.
MGED extended its contract with FirstLIght Power for an additional 10 years to 2040. MGED said the extension helps to keep its rates affordable while growing the amount of carbon dioxide-free power in its portfolio.
“MGED’s 2021 power portfolio is more than 60 percent carbon free,” Jackie Crowley, MGED’s general manager, said in a statement. “And with the 2021 FirstLight extension we can ensure a growing share of renewable energy through 2040 as we work to reach the MGED Board’s commitment to net zero emissions by 2050.”
The agreement will account for approximately 910,000 megawatt-hours, equivalent to more than 12 percent of MGED’s purchases for residential, commercial and industrial customers for the term.
MGED entered into an initial 2019 agreement with FirstLight Power. The agreement was developed by Energy New England with FirstLight to supply 21 Massachusetts, Rhode Island, and Vermont municipal utilities with hydropower.
“Never before have so many municipal light plants, municipal electric departments, and other public power utilities come together to buy emissions-free renewable power on this scale,” John Tzimorangas, president and CEO of Energy New England, said at the time.
In November 2020, the 21 utilities signed agreements to purchase 200 million kilowatt-hours (kWh) per year of hydroelectric power produced by FirstLight Power.
Meanwhile, TMLP on Oct. 6 announced that it has extended its contract with FirstLight Power. The transaction will now encompass an additional seven years to 2030.
TMLP was the first Massachusetts utility to enter into an initial 2018 agreement with FirstLight Power, the owner and operator of hydroelectric generation facilities in Massachusetts and Connecticut.
The extension helps TMLP “to lock in the resources it needs to decarbonize its electric generation output,” the utility said.
The extension will keep the TMLP power portfolio at nearly 26 percent of hydropower through the year 2030.
MGED serves customers in Middleborough and Lakeville by purchasing electricity from regional generating plants in New England. The utility also buys local energy produced by privately owned solar arrays. Almost all the electric power MGED’s buys comes from hydro, nuclear, wind or solar power with less than 1 percent coming from fossil fuel-burning plants that are mostly used during times of peak demand.
TMLP serves over 38,000 customers in Taunton, Raynham, Berkley, North Dighton and sections of Lakeville and Bridgewater.
FirstLight Power owns hydro generation stations in Massachusetts and Connecticut and has a total portfolio of more than 1,400 megawatts that includes two pumped hydro energy storage facilities, six conventional hydroelectric generation plants, five run-of-river hydroelectric generation plants, and one solar generation facility.
Two Temporary Mobile Generators Now Online In Roseville, Calif.
October 10, 2021
by Paul Ciampoli
APPA News Director
October 10, 2021
Two temporary mobile generators are now online in Roseville, Calif., following six weeks of construction at Roseville Energy Park, public power utility Roseville Electric recently reported.
The two generators were deployed by the California Department of Water Resources (DWR) following an emergency proclamation by Governor Gavin Newsom in July.
Each unit can produce up to 30 megawatts. The units run on natural gas but can run on a blend of up to 75 percent hydrogen.
The generators would be deployed under emergency conditions determined by the California Independent System Operator (ISO) under a contingency plan developed in coordination with the California Energy Commission and the California Public Utilities Commission.
In order to raise awareness in the communities surrounding these generators, the California Independent System Operator (CAISO) has posted a document outlining an order from the U.S. Department of Energy as well as the circumstances under which the CAISO can activate the units.
OPPD Awards Contract For Design And Construction Of New Power Plants
October 7, 2021
by Paul Ciampoli
APPA News Director
October 7, 2021
Nebraska’s Omaha Public Power District (OPPD) on Oct. 4 said that it has made a key selection for its Power with Purpose project, which will add 400 to 600 megawatts (MW) of utility-scale solar and 600 MW of natural gas to OPPD’s generation portfolio.
The utility awarded an engineer, procure, and construct (EPC) contract to Zachry Group. The company will be responsible for the design and construction of both of OPPD’s new natural gas generation facilities — Standing Bear Lake Station, a 150 MW facility in Douglas County, and Turtle Creek Station, a 450 MW facility in Sarpy County – as well as their associated substations. Both of these plants are peaking plants.
The solar and gas generation capacity that the Power with Purpose project will build “supports reliability and resiliency of the system as our communities grow, while significantly positioning OPPD on a path to meet its net zero carbon goal in 2050,” OPPD noted.
Preliminary grading at both natural gas generation sites related to the project has begun and major construction is scheduled to start in the first quarter of 2022.
In July, OPPD announced two other contracts related to Power with Purpose. The utility selected Siemens Energy to provide two combustion turbines to power the 450 MW Turtle Creek Station, a simple-cycle turbine facility. This facility will be in commercial operation by late summer of 2023.
OPPD also selected nine Wartsila reciprocating internal combustion engines to power the 150 MW Standing Bear Lake Station. Standing Bear Lake Station will be in commercial operation by late spring of 2023.
In a recent episode of the American Public Power Association’s Public Power Now podcast, Javier Fernandez, President and CEO of OPPD, provided details on the Power with Purpose project and discussed how the project fits in with his overall vision for OPPD’s future generation mix.
NYPA Reaches Milestone In Modernization, Digitization Of Niagara Power Plant
October 5, 2021
by Peter Maloney
APPA News
October 5, 2021
The New York Power Authority (NYPA) has completed a $460 million modernization and life extension project of its Lewiston Pump Generating Plant and the digitization of the first of 13 hydropower turbines at the Robert Moses Niagara Power Plant.
The Lewiston and Robert Moses pump generating plants together comprise the 2,675-megatwatt (MW) Niagara Power Project, the largest generating station in New York State.
The digitization is the first major milestone of Next Generation Niagara, a $1.1 billion, 15-year program to extend the operating life of the Niagara Power Project.
The modernization and life extension of the Lewiston Pump Generating Plant began in 2012 and included the replacement of the facility’s 12 pump turbines and its generator step-up transformers, which date back to 1961 when the Niagara plant first entered service.
The work involved the replacement of one pump turbine every eight to nine months, ensuring that 11 of the 12 turbines were available for operation during the upgrade so that NYPA could meet commitments to its power customers.
The Lewiston pump provides energy when power demand peaks and supplements the output of the Robert Moses plant, which is the main generating facility at the Niagara Power Project.
The Next Generation Niagara program aims to extend the operating life of the Robert Moses plant. The recently completed installation of new digital controls on the first turbine generator unit included making corresponding digital connections to the facility’s control room as part of the plant’s overall control room upgrade and redesign, and to the plant’s switchyard where Niagara’s power is distributed across New York’s transmission system. In the switchyard, workers installed digital controls on the transformers and circuit breakers corresponding to the upgraded turbine.
In addition to digitizing the plant’s generating units and building a new back-up control room, the Next Generation Niagara initiative encompasses a comprehensive inspection of the Robert Moses plant’s penstocks, the 485-foot pipes that carry water from the forebay to the turbine generators; replacement of the 630-ton crane that enables mechanical work on the turbines; and the overhaul and/or replacement of mechanical components that have reached the end of their operating life.
A planned unit outage to digitize the next turbine generator unit is expected to begin in May 2022.
The digitization and modernization projects represent nearly $1.6 billion of clean energy infrastructure investments at the Niagara plant intended to advance New York State’s goal to transition to 100 percent carbon dioxide free electricity by 2040.
NHA Report Identifies Challenges To Realizing Pumped Storage’s Potential
October 5, 2021
by Peter Maloney
APPA News
October 5, 2021
A new report from the National Hydropower Association (NHA) provides recommendations for policymakers and other stakeholders aimed at raising the profile of pumped storage hydropower (PSH) and making the technology better able to support the growing level of intermittent renewable resources coming on to the grid.
The 2021 Pumped Storage Report notes that pumped storage provides 94 percent of the bulk energy storage in the United States, but the last PSH project—a 40 megawatt (MW) plant in California – was commissioned in 2012.
“The acceleration of wind and solar deployments underscores the increasing need to integrate large amounts of variable resources,” Cameron Schilling, NHA’s vice president of market strategies and regulatory affairs, said in a statement. “This report shines a spotlight on the value of pumped storage, while providing a path forward for solving the market, policy and regulatory hurdles that hinders its growth. In addition to financing, for pumped storage to fully realize its growth potential, it requires market policies that appropriately value its grid services.”
A total of 1.8 gigawatts (GW) of PSH projects have received permitting authorizations, and over 50 GW of PSH have been issued preliminary permits or in the process of receiving permits, but no new projects have yet to begin construction.
The report also noted that pumped storage hydropower is nearly two to three times less expensive than lithium-ion batteries on a per kilowatt hour (kWh) basis and PSH’s annual operations and maintenance costs at $20 per kilowatt hour year are three times lower than batteries.
Nonetheless, NHA said the key takeaway from a 2020 survey of developers it conducted is that developing a PSH project is “a risk, and without some policy or market modifications there may not be adequate long-duration energy storage capacity to meet the demand from wind and solar resources.”
The NHA report recommends that
- Congress should create a stand-alone Investment Tax Credit (ITC) for all storage technologies, to ensure that PSH can compete with other storage resources on a level economic playing field.
- States need to send a market signal that long duration storage will be needed to meet aggressive climate goals, and state legislatures should adopt robust long duration storage targets with long lead times to ensure that the demand is met and that all technologies have a chance to compete.
- In regional markets, the Federal Energy Regulatory Commission (FERC) should ensure there are sufficient compensation mechanisms for frequency response, inertia, flexible ramping, condensing, voltage control and black start and other services provided by PSH. In addition, some renumeration should be provided to those technologies like PSH that can provide broader system benefits that are hard to quantify and measure.
- Utilities should work with the Department of Energy, PSH developers and the national laboratories to ensure that the full benefits of PSH, including the full range of services provided by advanced turbine technologies, are accurately modeled in integrated resource plans.
- FERC and other stakeholders should work to reform the licensing process, including allowing projects with minimal environmental impacts to be expedited.
“Current market and energy policies do not fully value the critical services that PSH can provide to the grid,” the NHA report said.
With the potential for 50 GW of pumped storage, “now is the time to develop new long-duration energy storage resources to enable a reliable, clean energy grid, the NHA report said.
OUC Completes Purchase Of 510-Megawatt Power Plant
September 30, 2021
by Paul Ciampoli
APPA News Director
September 30, 2021
Florida public power utility Orlando Utilities Commission (OUC) on Sept. 28 completed its purchase of the Osceola Generating Station, a 510-megawatt (MW) single-cycle natural gas-fired power plant located near Harmony in Osceola County.
OUC announced plans to purchase the facility last month.
OUC noted that the nearly $100 million deal to purchase and upgrade the inactive plant from Genova, a Texas-based private ownership group, does not change OUC’s commitment to net zero CO2 emissions as outlined in its Electric Integrated Resource Plan (EIRP), the utility’s 30-year energy roadmap.
The acquisition enables OUC to retire its oldest coal-fired power plant, Stanton Unit 1, which went into operation in 1987 at the Stanton Energy Center in east Orange County, instead of converting it to natural gas as stated in the EIRP.
Unit 1’s retirement date has not been determined, but OUC remains committed to significantly reducing coal fired generation no later than 2025 and eliminating it no later than 2027, the utility said.
The 20-year-old Osceola plant is comprised of three separate turbines, known in the industry as “peakers,” which can be powered up or down in just minutes. This capability will be used to mitigate fluctuations in solar energy production.
OUC is aggressively increasing its reliance on solar energy, with plans to boost capacity to power 50,000 typical residential homes by late 2023.
“Acquiring the Osceola Generating Station provides OUC with an extra layer of resiliency because it’s equipped with emergency backup fuel, a critical resource to have on hand in case of fuel supply disruptions and is more cost effective for OUC’s customers than converting and operating Stanton Unit 1,” OUC said.
“As we move forward with our clean energy transition, ensuring operational flexibility is essential to maintaining reliability, resiliency, and affordability for our customers,” OUC General Manager & CEO Clint Bullock said in a statement. “We are also committed to continued investments in solar and energy storage. This purchase of peaker generator units positions us to better manage the solar production fluctuations caused by cloud cover in Florida.”
Under the EIRP, OUC plans to increase the use of renewable energy resources and encourage conservation to reach net zero CO2 emissions by 2050, with interim carbon emissions reductions of 50% and 75% by 2030 and 2040, respectively.