The U.S. coal industry needs a good old industry- based economic recovery to see real growth in coal burn. Since 1999, the coal industry has been stuck in neutral as it lost non-power markets and as sales to power generators reached a plateau. Some of the apparent tonnage growth is simply the substitution of sub-bituminous for bituminous coals with little increase in Btu’s consumed. It has been difficult for U.S. coal companies to bring supply in line with demand or to turn high spot prices into improved earnings performance.
Large swings in power generator inventories helped balance the market, but not without a surge in coal spot prices in late 2000 and early 2001, and again for Appalachian coal prices currently. Production increases in 2001 largely went into inventories as the coal burn for power generation declined in 2001 with lower electric power generation overall. Coal prices declined as inventories grew. Coal producers saw their costs increase faster than their revenues and have closed or idled mines in an attempt to bring supply in line with demand. The old rules of thumb concern in growth in electricity demand translating into growth in coal simply have not materialized.
For example, in 2002 electricity generation increased by 2.2% over 2001, but coal-fired generation increased by only 0.7%, according to the Energy Information Administration (EIA). Gas-fired generation increased by 7% during the same period as gas prices fell to $2 per million Btu (mmBtu) early in the year. In some cases, new, efficient gas combined cycle (CC) generating units have displaced coal-fired generation even at gas prices as high as $5- $6/mmBtu when environmental emission allowance prices and/or operating inflexibility of gas CCs are taken into account. Last spring, NOx allowance prices rose to $7,000 per ton, forcing some coal units in the Ozone Transport Region (OTR) to reduce generation until NOx allowance prices fell. The displacement of lowcost coal generation by high-cost gas generation has made it more difficult to predict coal burn and to bring supply into balance with burn.
Electricity deman profiles change
A major driver of coal’s lackluster performance has been the lack of growth in electricity sales to industry. During the go-go 1990s, industrial electricity sales grew at the anemic rate of 1.2% a year and then actually declined during the recent recession. Commercial and residential electricity sales grew at 3.5% and 2.6% per year, respectively, from 1990 to 2000, according to the EIA. Average electricity sales growth averaged at 2.4% during the last decade.
Fortunately for the coal industry, industrial electricity sales started to increase during the third quarter of 2003. From July through October, industrial electricity sales increased by 4.4% compared with decreases of 1.6% for commercial sales and 1.8% for residential sales, according to the EIA. During the first half of 2003, industrial electricity sales had declined by 0.2% compared with the first half of 2002.
Many industrial facilities closed or reduced shifts during the recession. Some companies exported their manufacturing activities to offshore locations with low labor costs. Unfortunately, it is industrial electricity users that are the source of substantial portions of off-peak demand for power and represent a sizable portion of the market for the baseload generation of coal-fired units. New commercial facilities such as offices and shopping malls, generally operate during peak hours and are closed with very little power demand during off-peak hours. Similarly, new housing developments and other residential loads add largely to peak period demand. Only factories that operate around-the-clock and throughout the year provide demand during off-peak periods (i.e., overnight, weekends, spring, and fall) that will provide coalfired generating units with increased demand during periods when they can increase load.
Coal burn peaks in summer months
The highest levels of coal use consistently occur during July and August when generating plants typically burn from 2.9 to 3.1 million tons per day. Less than 200,000 tons separate the minimum July burn rate and the maximum August burn rate.
Changes in cooling degree days do not explain these differences. Base-loaded units operate 24:7 regardless of the weather conditions. Although August 1997 was 9% cooler than normal in the East South Central Region and August 1999 was 16% higher than normal, coal fired plants generated the same amount of electricity (i.e. less than 1% difference). Hotter weather does not translate into higher generation from baseloaded units.
Seasonal peaking plants operate only during peak demand periods and may experience significant increases in generation during hot summer weather. However, the amount of coal-fired seasonal peaking capacity is small and growing smaller as generating companies retire or convert these units to natural gas to avoid retrofitting them with costly environmental cleanup technologies.
The real opportunities to increase coal burn come in the off-peak periods of spring, fall and, in some regions, winter. Coal-fired generation increased by 1.8% during the first 10 months of 2003 over the same period of 2002, but all of that increase occurred during the first two months of the year. The average coal burn for January 2003 falls within the range of July and August burn rates, making last year’s January burn rate almost equal to that of a July or August rate. During the first two months of 2003, when peak demand was strong, gas-fired generation declined by only 3.3%, despite gas prices climbing to above $5/mmBtu. During the following eight months, gas-fired generation declined by only 10.9% compared with the same period in 2002 when gas prices were less than half of what they were in 2003. Coal has not realized a significant increase in burn as a result of high natural gas prices.
Coal units caught in a squeeze
Coal-fired generating plants have been caught in a squeeze as baseload generation available for coal has not grown with total electricity sales. Besides lackluster industrial electricity sales, competing generating sources have been taking off-peak generation away from coal. For example, while nuclear units technically can cycle overnight (i.e. reduce the amount of electricity they generate), they generally do not since their operators have determined that the period between refuelings can be extended by maintaining a constant load. Since the costs associated with shutting down a nuclear unit for refuelling are substantial, the savings from extending the period between refuelings can be significant. This means that coal-fired units must cycle deeper during off-peak periods to create room for the nuclear units. Though currently insignificant, the same holds true for wind-powered generation that occurs during off-peak periods. System operators must accept wind generation whenever it occurs and back down marginal units that are no longer needed. During off-peak hours, coal-fired units are often the only units that have the flexibility to reduce load.
Some industrial plants have developed cogeneration facilities fueled by natural gas. The economics of cogeneration generally make such generators insensitive to high natural gas prices. From the end of 1999 to the end of this year, roughly 135 GW of gas-fired combined cycle generating capacity will have been built in the U.S. Total coal-fired generating capacity is roughly 305 GW. While many of the gas CC units are uneconomic at gas prices above $5/mmBtu and at off-peak demand levels, they are likely to become economic during the peaks of summer. These units do not cycle well. Therefore, if they are needed to meet peak demand, they may be kept operating during off-peak nighttime hours. This leads to the potential anomaly that hotter summer time weather could lead to lower coal burns as gas CCs are brought on line to meet high peak demands during the day and remain operating overnight forcing coal-fired units to take deeper cycles and burn less coal.
There is very little new coal-fired capacity scheduled to come on line during the next five years and over that period a number of coal units are being retired. In some cases the retirements are the result of economics, but in several cases they are the result of environmental settlements. Tampa Electric agreed to retire the Gannon coal units and Dominion Energy agreed to retire the Possum Point coal units as part of their New Source Review (NSR) settlements. According to EIA’s projections, we will have less coal-fired generating capacity in 2008 than we have today.
Hydro generation in the western U.S. recently has been well below its normal levels as a result of several dry years. In the early and mid 1990s, hydro generation in the western U.S. forced coal-fired units into reserve shutdown because they were not economic during the spring run-off season. There may be less of an impact on coal today as total power demand in the region has increased. However, it is likely that normal to high hydro conditions in the West will lead to lower coal use during off-peak hours.
Growth in electricity sales does not necessarily translate into growth in coal burn. Growth in power sales during peak summer periods will translate into little additional coal use. Many gas CCs were built in areas where transmission constraints protect them from cheaper coal-fired generation and demand growth in those areas will not lead to increased coal use. When and where growth occurs is important to coal plants.
Growth in industrial sales should translate into off-peak electricity sales and increased coal burn. The average daily burn during off-peak months could increase. The coal burn could even increase during the peak months, if it were the result of increased demand during off-peak nighttime periods. However, the average daily burn during the off-peak months will never equal the burn during the summertime peak months because plants must be scheduled for routine boiler inspections and maintenance outages. These are rarely done during peak demand periods.
If an average daily burn of 3 million tons is possible year around, coal use in the power sector could increase to about 1.1 billion tons (assuming a constant heat content for coal). While this increase of 100 million tons is possible, it is highly unlikely without strong growth during off-peak periods. Growth in industrial electricity sales is critical to achieving off-peak growth in generation. Therefore, what the coal industry needs is a good old industry-based economic recovery.
