Commentary: Making a case for carbon capture at existing power plants

Attempts to reduce the carbon content of coal before burning have proven to be very expensive. However, removing CO2 from the exhaust is showing promise.”

A global energy shortage and skyrocketing prices are showing us the value of our existing affordable, reliable energy infrastructure. For example, the U.S. Energy Information Administration reports that coal use for electric generation is up 23% so far this year, as coal prices shine compared to a price tripling of natural gas.

A regulatory tsunami weeded out the oldest, least efficient coal-fired power plants and coal mines, and many of the remaining power plants have decades of life left. Capturing the carbon dioxide (CO₂) emissions from the exhaust stream at these facilities offers a potential free-market solution to reducing emissions, while preserving these valuable assets that offer fuel diversity.

Dominion Energy devised an electric-generating plan to meet the Virginia Clean Economy Act. By 2035, massive amounts of wind, solar and battery storage would replace conventional generators to eliminate 14 million tons per year of CO₂ emissions. A utility commission review of the plan showed that the $44 billion in investments would raise electric rates $800 per year, or 57% for residential customers, and by millions for large energy users. The same emission reduction with carbon capture at existing power plants might require a $4 billion investment and no increase in electric rates when potential new revenue is considered and would maintain reliable power.

Attempts to reduce the carbon content of coal before burning have proven to be very expensive. However, removing CO₂ from the exhaust is showing promise. The U.S. Department of Energy conducted a study of power plants in Wyoming, showing the removal might cost $74 per metric ton if done at the power plants with the most up-to-date technology for reducing air-pollution emissions. With widespread and ongoing research, it is not unreasonable to predict the cost may fall to $65 per metric ton.

The captured gas has value. It is used to make beverages fizzy and decaffeinated drinks; as a fire suppressant, a spray can propellant and a refrigerant; in fertilizer, dry-ice and methanol production; and in many other manufacturing processes. The compressed or liquid food-grade gas can be worth up to $175 per ton. It can also be pumped underground in oil and gas fields to enhance production without additional drilling and remaining permanently underground. According to the Wyoming study, at $60 for a barrel of oil, the gas is worth about $30 per ton. Oil is currently selling for $80 a barrel, so the value might be $40 per ton.

Besides the gas value, many companies are interested in buying carbon offset credits. In Europe, such credits were sold for almost $70 per metric ton in May. The market is mandatory there, but it’s voluntary in the U.S. The market might be helped here by having regional electric grid organizations certify the offsets with a program similar to how they track renewable-energy credits.

Existing government policy also adds value to captured gas. Thirteen states currently require coal and natural gas-fired power plants to buy allowances to emit CO₂. The latest auction price from the Regional Greenhouse Gas Initiative (RGGI) was over $9 per ton, is forecasted to rise as high as $22 per ton by 2030 and may average $15 per ton over the next decade. In addition, there is an IRS tax credit known as “45Q,” paying $35 per ton for captured CO₂ from power plants, and proposed legislation may increase the size of the credit.

For example, NRG owns the Indian River coal-fired power plant in Millsboro and had announced plans to close it in 2022. The grid operator, PJM, is studying whether the plant needs to stay open for a time, as it is the southernmost power plant on the three-state Delmarva Peninsula and may be necessary to maintain reliability. The plant has about local employees and pays local and state taxes.

The Indian River plant ran 68% of the time in 2012 but only 19% of the time so far in 2020, as the cost of RGGI allowances leaves the facility uncompetitive. That means higher electricity cost for Delaware electric customers to bring power from farther away, plus transmission and congestion charges. It also means higher emissions from transmission losses and from 15% lower efficiency at the Indian River power plant from more frequent up and down cycling. Globally, emissions are not reduced, as generation simply moves to a similar power plant in a non-RGGI state.

The Wyoming study indicates that carbon capture might require an investment of $251 per metric ton captured, and a proposed North Dakota project estimates $285. In 2012, the Indian River Unit 4 emitted 1.2 million metric tons of CO_2, which would require a $300 million to $350 million investment in carbon-capture equipment, similar to a pollution-control investment made in 2011. The CO₂ might sell for $40 per ton, receive $35 per ton in IRS 45Q tax credits and avoid $15 per ton in RGGI allowance payments, for a total of $90 per ton in equivalent value, compared to a $65- to $75-per-ton cost. Additional voluntary sales of carbon offsets are possible and could eventually eliminate the need for the IRS 45Q tax credits, allowing carbon-capture investment choices as a free-market option.

Delaware electric customers would avoid added transmission line and congestion costs, preserve the economic and reliability benefits of keeping the power plant open, and see a net global reduction in emissions. This is a win-win for everyone. It’s time to get serious about adopting carbon capture at existing power plants.

David T. Stevenson is the director of the Caesar Rodney Institute Center for Energy & Environmental Policy.