Turning electrical devices on and off might mean a simple flick of a switch, but the process to shut down or repurpose a generating facility is complex and requires careful planning and considerations as varied as reliability, workforce, environmental impact, and cost.
Two large public power utilities — Salt River Project and the Los Angeles Department of Water and Power — shared their thoughts on the decommissioning process and how they addressed a suite of challenges.
Prioritizing Safety
Until it was retired at the end of 2019, the 2,250-megawatt Navajo Generating Station in northern Arizona was one of the largest coal-fired plants in the country. The plant owners include Salt River Project, Arizona Public Service, Tucson Electric Power, Nevada Energy, and the U.S. Bureau of Reclamation.
Faced with the potential cost of new emission control equipment, and increased competition from other low-cost resources, a grim economic outlook drove the difficult decision to close NGS, said Scott Harelson, SRP’s supervisor of media relations. “The price of other resources, primarily natural gas, made continued operations of NGS uneconomical and not in the best interest of our customers,” he said.
Economics is a common thread in the closure of many U.S. coal-fired plants, according to the Energy Information Administration. Between 2010 and 2019, the EIA reported that more than 546 coal-fired power plants in the U.S. ― roughly 102 gigawatts of generating capacity ― announced their retirement. And another 17 GW of coal-fired capacity is set to retire by 2025.
The very first priority ― from the time the shut-down decision was made in 2017 ― was to keep the plant safe, said Joe Frazier, the former NGS manager who is now overseeing the decommissioning. “Knowing that the plant would close in two years was a huge distraction that could easily get someone hurt if that person is not focused on the job.”
Decommissioning began in the fall of 2019 and is expected to be completed within five years. However, Frazier said the current schedule has the decommissioning process completing within three years.
One challenge is demolition, which Frazier said is a dangerous process. “Keeping folks safe will be our No. 1 focus,” he said, adding that the process and procedures now in place will do that.
Supplanting Energy
SRP is working with the Navajo Tribal Utility Authority ― a public power utility that serves the Navajo Nation ― on land clearance and any future use. Once decommissioning is completed, the Navajo Nation will repurpose the restored land as it sees fit.
In the meantime, SRP is working with NTUA on a solar facility some 100 miles from the NGS site. Kayenta I is the first utility-scale solar project to be developed on the Navajo Nation, and it set the stage for future development, including Kayenta II, a nearly 28-MW solar facility developed, owned and operated by the NTUA. Together, the two facilities have a capacity of 55 MW, and the output of both is delivered to Navajo Nation residents.
Through a long-term power purchase agreement with NTUA, SRP purchases energy and renewable energy credits from the Kayenta facility. Because there is no transmission infrastructure to carry the energy to SRP’s grid, NTUA delivers an equivalent amount of energy to SRP from other resources within its portfolio that are interconnected to SRP’s system.
Minimizing workforce disruptions
A second priority, said Frazier, was to offer jobs to all employees who wanted to stay with SRP. Of the 433 SRP workers at NGS, 294 have accepted other positions within the utility, said Renee Castillo, the utility’s senior director of human resources.
“The majority of our NGS employees accepted an offer to redeploy and are working in a variety of different jobs — from our power plants in St. Johns and Gila Bend to administrative positions at SRP headquarters,” she said. Twenty-two employees, all Navajo, are performing site services activities. They are focusing on assisting with the initial decommissioning of NGS. Twenty-one employees left SRP, and some have chosen to work for contractors involved with the decommissioning efforts.
Getting consensus for change
The decision to repower the 1,800-MW Intermountain Power Project, a coal-fired plant in western Utah, was driven in part by the Los Angeles Department of Water & Power’s commitment to stop using coal for electricity generation by 2025.
A California state bill passed in 2006 requires that any long-term investment in new baseload power generation cannot exceed 1,100 lbs per megawatt-hour in greenhouse gas emissions.. Another California state bill established a cap and trade program, requiring power plants to purchase carbon emissions credits, making coal plants uneconomical.
The plant is owned by the Intermountain Power Agency and generates electricity for 35 utilities in Utah and southern California, including LADWP. IPA obtained agreement from all the participants to replace the IPP coal facility with a natural gas-fired facility, and in 2015, the LADWP board approved the construction of a 1,200-MW combined-cycle plant at the IPP site.
Agreements among participants stipulated that construction of the natural gas-fired units must begin by 2020 and be completed by 2025. A key component of the agreements allows LADWP and other Southern California participants to maintain rights to two critical transmission systems connecting existing and future renewable energy from Utah and the southwestern U.S. to Los Angeles.
A dispatchable power source is needed to maintain the high-voltage direct current line that runs from the plant and provides capacity to Southern California.
In 2018, LADWP and the other participants scaled back the size of the combined cycle plant, reducing it to 840 MW. Of that capacity, LADWP’s share is 544 MW. The proposal required unanimous approval of the IPP participants and the board of the IPA.
At the time the LADWP board increased the utility’s renewable goals for 2025 to 55% and for 2036 to 70%, respectively. This action accelerated the decarbonization of LADWP’s power supply portfolio by increasing the renewable portfolio standard targets by 5%.
Balancing multiple roles
Decommissioning of the IPP will begin in July 2025, with oversight of the work provided by the IPP’s Coordinating Committee, composed of representatives of IPP’s participants. The plant’s infrastructure, including administrative buildings and converter stations, will be upgraded for use by the new natural gas combined-cycle facility.
When decommissioning is completed, the IPP coal facilities will be returned to pre-construction condition, said Paul Schultz, LADWP’s director of power external energy resources.
Groundbreaking for the natural gas combined-cycle facility will begin early in 2022, said Schultz. Over the next two and a half years, the two combined cycle units will be built at the IPP site.
According to the IPA, an equipment, procurement and construction contract is expected to be awarded by the end of 2021, with Unit 1 in service by April 2025 and Unit 2 in service a month later.
The utility has two roles, said Schultz. “We're not only a participant in IPP, we're also the construction manager and the operating agent.” As the project manager, the utility will direct and manage capital investments. As the operating agent, it will continue to oversee operation and maintenance work. The IPP Coordinating Committee is responsible for approving the operation and maintenance budget and capital investments.
The new plant’s operator will be the Intermountain Power Service Corp., which operates the existing IPP coal facility.
Ultimately, LADWP expects the new plant to be fueled only by hydrogen, a dispatchable resource. At the time of startup in 2025, the units will burn 30% hydrogen. Three manufacturers have said they can support up to 30% hydrogen in the fuel mix, said Schultz.
