Coal Unit CCUS Retrofits More Economic Than Many Alternatives, NETL Study Suggests

Adding carbon capture, utilization, and storage (CCUS) to two Xcel coal units in Colorado that are slated to be retired by 2025 would push up the cost of power if compared with replacement with wind/storage hybrids. But CCUS, which generates revenues, would still work out to be cheaper than other alternatives mandated under the company’s Colorado Energy Plan (CEP), a new Department of Energy (DOE) techno-economic case study suggests.

The report, “Economic Impact Assessment of CCUS Retrofit of the Comanche Generating Station” stems from the second phase of a study initiated by the National Energy Technology Laboratory (NETL) to understand costs associated with integrating CCUS into a coal-fired power plant. The first phase investigated potential carbon dioxide markets that could support the application of CCUS, and it found Colorado was an ideal location because it has natural CO2 resources as well as necessary pipeline infrastructure.

The case study, which sought to identify whether there is a business case to add CCUS to existing plants in Colorado, uses the Comanche Generating Station as a representative plant, mainly because it is the closest to a trunk line.

Xcel owns and operates the plant in Pueblo, southern Colorado, though the report notes that the company “was not consulted or directly involved in the study.” The plant sources low-sulfur coal via rail from the Powder River Basin (PRB) in Wyoming, and it was selected in 2018 as the PRB Coal Users’ Group Plant of the Year (see “Common Goals and Team Mentality a Winning Combination” in POWER’s June 2018 issue).

Prospects for A Doomed Plant

Under the CEP—a power portfolio that the company developed as part of its 2016 Electric Resource Plan, and which the Colorado Public Utility Commission (CPUC) approved in 2018—Xcel has proposed to retire the 46-year-old 325-MW Comanche 1 by the end of 2022, and the 44-year-old 335-MW Comanche 2 no later than the end of 2025. The retirements are slated to occur between 10 and 11 years ahead of schedule. Comanche 3, a 750-MW unit that came online in 2010, will remain in operation, in part to serve the nearby Evraz Steel Mill, the utility’s largest commercial customer in the state.

The CEP anticipates Xcel would need 775 MW by 2023, and it seeks to replace the coal-fired capacity and boost its portfolio with 1.1 GW of new wind, 707 MW of solar, 275 MW of battery storage, all which could require $2.8 billion in generation and transmission investments.

NETL’s report essentially examines a hypothetical scenario where all three units would continue to operate after being retrofitted with carbon capture, and the CO2 is used for enhanced oil recovery (EOR) in the Permian Basin. That would mean Xcel would need to acquire only 450 MW of resources to meet needs by 2023. And though no new wind, solar, battery storage, and new transmission would be added, CCUS retrofits at the three Comanche units would require generation investments (capex) of about $3.74 billion. The units would have first-year capture costs of between $36 and $40 per ton (in 2017$), it suggests.

The report finds, however, that the CCUS option would offer more long-term CO2 emission reductions between 2020 and 2042 than the CEP scenario. In a business as usual scenario—where Xcel retains the Comanche units until their original retirement dates, and adds new wind, solar, and battery storage to its current, gas-heavy portfolio, emissions would only fall 45% compared to fleetwide emissions in 2005. In the CEP case, they would fall 52%, and in the CCUS case, where the three units potentially captured 9.32 MMT/yr of CO2 ,they would fall 65%.

The analysis also suggests that the two units slated for retirement currently achieve a combined power cost of $17.4/MWh (2017$). That’s lower than the estimated $18.3/MWh (2017$) cost of a wind and storage combination option. A CCUS retrofit at all three units, meanwhile, would raise power costs to $19.7/MWh (2017$), but that figure takes into consideration replacement makeup power to counteract carbon capture parasitic losses in Unit 3. However, it would still be lower than solar PV and solar PV plus storage as estimated in Xcel’s CEP.

But it notes: “If CO2 capture technology is installed at Comanche, and if the CO2 is used for EOR in the Permian Basin, the average CO2 revenue including the 45Q EOR tax credits and the sales price of CO2 from (the start of CCUS operations in) 2023 to 2042 would be $36/tonne (T) (2017$), and this will offset the cost of capturing CO2.”

As significantly, the report also finds that if revenues from the CCUS retrofit at Units 1 and 2 are applied, the plant can produce power at a levelized cost lower than the cost of renewables under the CEP.

As the study notes, Xcel told regulators that the CEPP includes “unprecedented low pricing across a range of generation technologies including wind at levelized pricing between $11-18/MWh, solar between $23-$27/MWh, solar with storage between $30-$32/MWh, and gas between $1.50 – $2.50/kW-mo.” However, CPUC staff recommended that Xcel use median bid prices for the resource acquisition period from 2016 to 2024. These work out to (in 2017$): $18.3/MWh for wind + storage; $27.5/MWh for solar PV; and $34/MWh for solar PV + storage. 

In 2017, by comparison, generation-weighted average power purchase agreement (PPA) prices in Colorado for wind were about $43/MWh and for solar PV were about $70/MWh. 

If revenues from CCUS retrofits were applied at all three Comanche units, they could produce power at a weighted levelized cost of electricity (LCOE, in 2017$) of $19.72/MWh. That’s “slightly higher than the LCOE from wind + storage but lower than solar PV and solar PV + storage in Xcel’s CEP,” the study says. But, it notes, “the combined LCOE for Units 1 and 2 is $17.37/MWh, which is lower than all of Xcel’s CEP options.” 

The study also suggests that with CCUS retrofits, plant operators will have “an incentive to operate at a higher capacity factor because of the revenues from the sale of CO2 and electricity, thereby making coal-fired generation competitive against renewables and against natural gas peaker and [combined cycle] plants.” 

Support for CCUS Widens

The case study’s findings were released amid heightened interest in carbon capture. Only one U.S. power plant is currently equipped with carbon capture: Petra Nova, which is jointly owned by NRG Energy and JX Oil & Gas. The plant is reportedly operating as designed, capturing 4,776 metric tons/day, or about 90% of the carbon dioxide from a 37% flue gas slip stream from Unit 8 at NRG’s WA Parish Plant near Houston, Texas. However, NRG CEO Mauricio Gutierrez isn’t optimistic about building another plant, noting at a conference in March that the “economics are challenging.”

Yet, Mitsubishi Heavy Industries (MHI), which provided the capture technology for that project, told POWER in February that total costs for the next large-scale carbon capture and compression plant (none are yet under construction) will be nearly 30% less. MHI also noted that the market for carbon capture in the U.S. is especially ripe, owing to a boost from the 45Q tax incentives Congress enacted in February 2018.

In June, meanwhile, Lou Hrkman, the DOE’s deputy assistant secretary for the Clean Coal and Carbon Management office, said driving down costs for CCUS, is one of the DOE’s “highest priorities.” Today, it costs about $50 to capture a metric ton of CO2 from the flue gas of a typical coal-fired power plant. “This level of cost limits wide adoption of the technology without various support mechanisms,” Hrkman said. “Our goal is to reduce CO2 capture costs to $30/ton by 2030,” he said.

New carbon capture initiatives appear to have bipartisan support in Congress, too. On July 2, four House Democrats and a Republican re-introduced the Fossil Energy Research & Development Act, a bill that will boost funding for carbon capture research and development and direct new research efforts within the federal government aimed at improving CO2 storage and use, and developing new CO2 utilization technologies. The bill echoes the EFFECT Act introduced in the Senate in April by Senators Joe Manchin (D-W.Va), Lisa Murkowski (R-Alaska), Shelley Moore Capito (R-W.Va), Kevin Cramer (R-N.D.) and Steve Daines (R-Mont.).

According to the Carbon Capture Coalition, the legislative measures are key elements of the Policy Blueprint that the coalition released in May 2019. The roadmap outlines a suite of policy priorities that, if adopted, would dramatically expand and improve carbon capture technologies and significantly boost bipartisan efforts to reduce emissions, create jobs, and build the American economy.

“Clarifying federal policy to expand support for federal investment in research and development is vital to the continued growth of carbon capture technologies in the marketplace. Federal leadership from the Department of Energy, as required by this legislation, will help drive down the cost of carbon capture technologies and improve their efficacy,” Carbon Capture Coalition co-director Brad Crabtree said in a statement emailed to POWER on Tuesday.

Sonal Patel is a POWER associate editor (@sonalcpatel, @POWERmagazine)

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