For many utilities there is a razor-thin difference in the price of electricity generated by natural gas and by coal. Slight changes in fuel price can produce dramatic swings in production costs, creating market opportunities for utilities with both gas- and coal-fired assets. Utilities considering new gas-fired assets have several options. Key among them is cofiring with coal and natural gas, allowing pricing and market conditions to drive the fuel choice and mix.

Cofiring is the lowest-risk option for substituting gas use for coal. Cofiring is defined as burning two different fuels simultaneously to produce heat in the steam generator, and it is typically implemented with natural gas or fuel oil at coal-fired power stations. Utility owners of coal-fired power stations are better able to balance their exposure with additional natural gas-fired generation.

Natural gas cofiring has many advantages that make it attractive. The first is that many power stations already use natural gas as a startup fuel, so a gas fuel supply infrastructure to the steam generator is already in place.

Some power stations currently operate their gas igniters or warm-up guns when recovering from coal-related equipment “derating.” To switch to dual fuel capability, it typically requires only a modest capital project to increase the size and duty cycle capability of the unit. If new waterwall penetrations are required, the capital cost and complexity of the project can increase significantly. However, gas igniters and warm-up guns can often be merely upsized in place. This can yield as much as 20 to 25 percent of total heat input to the steam generator.

Benefits of Cofiring

The greatest benefit of employing natural gas cofiring with coal is increasing the fuel flexibility of the unit. There are many ways in which increased fuel flexibility can benefit a coal-fired unit, such as:

• Lower-cost coals can be purchased with less concern for lost capacity. For example, a unit that operates most efficiently using only coals with moisture content of 27 percent or less (a typical Southern Powder River Basin coal) can likely push this specification to include the lower-cost, higher-moisture coals from the Northern Powder River Basin (PRB).
• Power stations that are unsure about the quality of their coal stockpiles or that suffer from poor or erratic blending practices can put those fears to rest. If for some reason too much poorer-quality coal is stocked into the bunkers or silos, then operators can modulate natural gas use to make up the difference.
• Unexpected outages of parallel equipment (such as coal mills) can be hedged by having natural gas available to make up lost load.
• Coal inventory levels can be reduced. In the event that significant unexpected coal supply restrictions occur, natural gas use can be maximized to reduce the coal pile draw-down. Conversely, should natural gas supply restrictions occur unexpectedly, coal use could be increased to maintain the unit generation plan.
• Some emissions control retrofits may be reduced in scope, delayed, or avoided, depending upon the coal quality, level of gas cofiring that is intended, and the plant’s regulatory environment.

Provided that the gas pipeline is of sufficient size, few fuel-handling system modifications are required for natural gas cofiring. Using recent Black & Veatch studies as a guideline, capital costs for implementing natural gas cofiring (outside of new pipeline costs) can range from $10,000 to $100,000 per megawatt.

Future of Coal-Fired Plants

Despite the added flexibility and relative low cost of converting to full dual fuel capabilities, some utilities are hesitant. With coal plant retirements still up in the air, many utilities are reluctant to invest any sum of money in a facility.

The just released revision of Black & Veatch’s semi-annual Energy Market Perspective (EMP) shows that 60,000 megawatts of coal-fired capacity are expected to be retired by 2020, although the majority of that will come in the next two years.

According to Rob Patrylak, who heads up EMP and is Managing Director for Black & Veatch’s management consulting division, 48,000 MW will need to be retired by 2015 to meet the U.S. Environmental Protection Agency’s (EPA) Mercury and Air Toxics Standards (MATS) that come into play that year. However, some of these plants may be able to get an extension to delay their retirement or to enable the asset owner more time to meet the MATS requirements, Patrylak stated.

The EMP makes a 25-year forecast of energy usage and pricing. The latest version shows an additional 86,000 MW of coal-fired facilities retired between 2020 and 2038. Coal accounted for 50 percent of U.S. generation in 2005 but will be down to about a 40 percent market share once the 2013 final statistics are tallied, with natural gas-fired generation at an expected 27 percent. This is down slightly from a peak in gas usage of 30 percent in 2012, but up from 18 percent in 2004.

Black & Veatch predicts that over the next 25 years, natural gas will dethrone coal. In the meantime, the operating advantage will go to utilities with diversified fleets that are able to switch between coal and gas as the market price of fuels seesaws, particularly during periods of flat electricity growth such as that experienced over the past few years.

Published Originally on Black & Veatch Solutions.