Christopher Leshock,Senior Consultant, Resource Data International, USA
Competitive generating markets signal tough times for coal-fired power producers as environmental legislation tightens. A recent RDI study examines the US market to see who the winners will be.
Coal-fired power generators in the USA today find themselves in a bewildering conundrum. Coal-fired power plants provide the bulk of electric generation in the USA, and are a recognized source of consistent, reliable, low cost electricity. As the electric industry deregulates and restructures for a very competitive, commodity-based environment, common sense would dictate that a low cost producer should flourish in such an environment. But this logic is upset by the introduction of a series of environmental regulations that promise to significantly increase the cost of coal-fired generation.
The issues most expected to impact coal-fired generation include electric industry deregulation, new environmental regulations and the declining cost of high efficiency gas-fired generation. The forces of competition and profit motive will drive power production costs down to typical market levels forcing the retirement of uneconomic fuel supply contracts, a significant source of the disparities in production costs. The competitive position of each plant in the future under these conditions goes a long way in determining the long-run value of each generating asset.
The interaction between new environmental costs, evolving wholesale power markets and intense cost reduction pressures for power generators has been examined in a recent study by Resource Data International (RDI): ‘Coal-fired Generation in Competitive Power Markets’.
Deregulation of the electric power industry is being driven by great disparities in power costs on regional and national levels. Such disparities are evident and numerous in coal-fired power production costs across the USA. RDI has documented and benchmarked every major utility coal-fired power plant in the USA on the basis of several factors, including SO2 adjusted delivered fuel price, plant conversion efficiency, labour efficiency, power production costs and perhaps most importantly, estimated gross production margins (if operated within a competitive market) for 1998 and 2003.
The sizes of the dollar values directly involved in coal-fired power generation are staggering. The 300 000 MW of coal-fired capacity in place in the USA today carries a book value of $150 billion and an average cost of $460/kW of installed capacity. Over 20 per cent of the capacity will transfer ownership by the end of 1999 based on recent and pending transactions. RDI estimates that up to an additional 40 per cent will change hands in the future as additional states encourage divestiture of generating assets as conditions of deregulation legislation and merger proceedings.
An even larger part of the generation mix in the US is involved in M&A activity, as utilities are in the throes of an industry-wide consolidation. Coal costs to supply the 940 million t purchased for utility coal-fired plants in 1998 exceeded $16 billion, and transportation expenditures exceeded $8 billion. Above market portions of coal supply contracts in 1998 are estimated at $3 billion. As the electric industry deregulates, every component of the coal-fired value chain will be affected, some more than others.
The $3 billion in above-market coal contract value is concentrated among utilities in the west, Midwest and southern regions. As these contracts expire or are renegotiated there will be a significant reshuffling of the competitive order between coal-fired plants in each region. Coal companies that see these contracts end will lose a substantial source of operating cash flow. For example, Consol, the highest ranked beneficiary of above-market contracts in 1998, is expected to lose nearly $200 million in annual above-market contract value up on the expiration of a handful of key contracts by the end of 2000. Conversely, generation owners with expiring or renegotiated contracts will be better positioned to compete in deregulated markets.
Southern Company, the utility with the highest ranked exposure to above-market delivered coal costs in 1998, is one such example. Nearly 75 per cent or $275 million in its above-market coal expenditures ceased at the end of 1999. This large cost reduction significantly improved the competitive position of the Southern Company plants fuelled with this coal.
However, several utilities have successfully transitioned to meet the requirements of competitive markets and are buying fuel at costs below what are incurred by the industry at large. For example, TXU’s lignite purchases, Santee Cooper’s CAPP coal purchases and NPPD’s PRB (Powder River Basin) coal purchases are annually delivered at more than $20 million less than would be typical for the industry.
RDI has established annual out-of-market expenditures for each of the 403 major coal-fired utility power plants in the USA with projections made in three categories: FOB (Free on Board) coal costs, rail transportation costs and delivered coal costs. Some utilities will be intensifying their efforts to reduce above-market costs as utility deregulation moves forward, while others have already successfully reduced their coal costs to levels below typical market levels.
Select ERCOT utilities with lignite-fired plants (led by TXU) have been unusually successful in controlling their fuel costs, when benchmarked against PRB coal deliveries. On the other hand, Southern Company, AEP and Commonwealth Edison are utilities ranked with the highest 1998 above-market expenditures – all in excess of $300 million in 1998.
The cost of control
As generation owners cut costs and prepare for a competitive generation market, new federal and regional environmental regulations targeting air emissions will become increasingly strict. These regulations, which primarily focus on the emissions of sulphur dioxide (SO2) throughout the year and nitrous oxide (NOx) over a five month period of each year, are projected to increase costs at coal-fired plants through additional control equipment.
The cost for this control equipment is not trivial, ranging from $15/kW of capacity to $275/kW of capacity for full SO2 and NOx control equipment. In some instances it will be economically justified to construct new gas-fired combined cycle (CC) capacity for a cost of $500/kW, which has a near zero emissions profile, rather than invest the required capital to install environmental controls in a coal-fired facility approaching retirement age.
Delivered coal costs for coal-fired plants inclusive of environmental adders will vary regionally and NOx control costs will only apply for 22 eastern states and Texas. The imposition of the new SO2 and NOx emission limits will narrow the differential of the variable dispatch costs between existing coal-fired units and new highly efficient gas-fired CC units, putting some of the least competitive coal-fired plants at risk to competition with new CC units within each NERC region. Such competition is likely to cause CC units to garner the lion’s share of load growth and cap or curtail generation from the least competitive coal-fired units, particularly within the northeast, middle Atlantic and southeast regions during the five-month NOx control season.
Analysis of coal source switches stemming from combinations of environmental compliance and power generation economics indicate a continued shift to lower cost, lower sulphur western coal, especially coal from Wyoming’s Southern Powder River Basin (SPRB). The combination of low delivered costs and very low sulphur levels more than offsets increased handling and sub-optimal boiler performance encountered when burning SPRB coal in boilers designed for higher heat content coal. In many growth markets SPRB coal will not completely displace indigenous coal, but more often than not, will be used in 50 per cent blends that allow capture of a portion of the fuel cost savings while avoiding unit derates.
The implementation of Phase II of the Clean Air Act Amendments on January 1, 2000 governing SO2 emissions and widely expected NOx regulations in 2003 are likely to impact wholesale energy prices. Costs related to the operation of emission control equipment and the emission of any level of SO2 and NOx are anticipated to increase variable dispatch costs which will impact wholesale electricity prices when affected coal-fired units are the price setting units. Regions in which the environmental costs are highest and coal-fired units are the marginal cost units a large percentage of the hours in the year will see the largest impacts on electricity prices.
The ECAR, MAAC, MAIN and SERC regions are expected to see average electricity prices rise over $1.50/MWh due to these impositions. The increase in prices during the five-month ozone season will be more acute, reflecting the full cost of NOx compliance during that period. On a national basis, the cost of environmental adders is expected to approach $1.30/MWh, thereby potentially increasing annual electrical rates by $4.5 billion – a cost likely to be passed through to the consumer.
Plant specific energy revenues will also be affected by competition. Gross production margins vary significantly region to region, and across the range of plants within each region. The western regions of the USA, including WSCC, SPP, ERCOT and MAPP are forecast to have gross production margins in excess of 80 per cent of their production costs. Eastern regions including NPCC, MACC and the VACAR sub-region of SERC are forecast to have the lowest gross production margins due to higher delivered coal costs, older and more inefficient plants and additional environmental costs relating to NOx emissions.
The majority of the coal-fired asset sales to date have occurred in regions with low projected gross production margins while utility M&A activity has been concentrated in regions characterized by expected high gross production margins. This may signal, among a number of other factors, that former generation owners foresaw the limited future profit potential and acquiesced to divestiture requests of regulators in return for more favourable conditions in restructuring legislation or merger processes.
The geographic representation of gross production margins modelled for 2003 are shown in Figure 2. This map is a valuable indicator of the future value of generating assets after above-market coal and transportation contracts have been adjusted to market levels and plants are actively competing in a more deregulated marketplace.
The map indicates that the coal-fired plants with the largest gross production margins in 2003 will be concentrated in a wide belt stretching from the northern Rocky Mountains down through the southwest into Texas encompassing the western part of WSCC, southwestern MAPP and much of SPP and ERCOT. These plants are nearly exclusively fuelled with PRB coal, generally operate at high capacity factors and are relatively new plants equipped with modern pollution control devices. M&A and generating asset sale activity is likely to be intense within this belt, except in the instance of public power assets where savvy power marketers will attempt to extract some of this inherent value.
Gross production margins in 2003 have been projected by RDI for the 403 major coal-fired utility power plants in the USA. The ten plants offering the highest projected gross production margins in 2003 are listed in Table 2. These plants are all located within Western NERC regions that utilize PRB coal, with the sole exception of OMU-Smith, a scrubbed plant located in ECAR-W which utilizes ILB (Illinois Basin) coal. These plants should command the highest asset values in a deregulated marketplace.
Conversely RDI has projected that 29 coal-fired plants totalling near 4200 MW of capacity will have insufficient revenues in a competitive electricity market to cover production costs. The ten plants are identified in Table 3. As traditional regulated pricing structures are removed in favour of market based pricing, the incentives currently in place to operate these plants will vanish as many plants with negative gross margins will close.
The combination of increasingly stringent environmental regulations and increasingly efficient combined cycle natural gas-fired generating units stands to curtail coal-fired generation somewhat in the next five years. Older and typically smaller coal-fired units in the eastern USA are particularly at-risk to generation displacement. Some of the most inefficient units will close, as their revenues in a competitive electricity market will be insufficient to cover their cash operating costs.
Despite these relatively small losses, the large base-load coal-fired units that typify most units in the USA are projected to increase their generating levels eight per cent by 2003 and reach near maximum operating levels. In several regions the operating margins for coal-fired facilities will exceed 100 per cent, and provide such high positive cash flows that some investors will be inclined to pay values approaching $1000/kW, or close to the cost of a new coal-fired plant for such assets.