The past five years have witnessed a construction spree of more than 200,000 MW in gas-fired power plants across the U.S., mostly by merchant generation companies. Much of this construction was undoubtedly fueled by the environmental problems and siting difficulties associated with coal-fired generation and the emergence of natural gas as the fuel of choice in the 1980s and 1990s, given the low gas prices prevalent during those years.

Now, while gas prices stay persistently at high levels and exhibit significant volatility, coal prices remain relatively stable and inexpensive. Importantly, the U.S. Geological Survey estimates U.S. coal reserves at about 230 billion tons, or about 230 years at current consumption rates. In contrast, stagnant U.S. and Canadian gas production and increased usage are expected to make the U.S. significantly dependent on liquefied natural gas (LNG) imports for natural gas supplies in the future. The question is, will these conditions lay the foundation for a comeback for coal-fired generation, particularly with regulated utilities that can rate-base their investments?

Part 1 of this two-part article examines the prospects for new coal-fired generation in the U.S. and the issues that will determine when and where these plants may be built. Part 2 will explore expectations for capital costs associated with these plants, and the possible rating implications for the utility industry.

Capacity Versus Energy

The first question that arises when considering the prospects for new coal-fired generation is whether new generation is needed at all. Practically every region in the country currently has a generating capacity surplus that is well beyond the 15% to 17% capacity reserve margin expected when supply and demand are in equilibrium, and that imbalance persists well into the future (see table 1). The capacity glut is only worsened by the fact that coal and nuclear plant retirements that were forecast before the merchant build-out never materialized. Indeed, just the opposite happened as new owners of old plants, particularly nuclear plants, dramatically improved operating efficiencies and availabilities.

As table 1 demonstrates, no U.S. region is deficient in generating capacity. However, it is the capacity fuel mix that could give rise to a preference for coal-fired generation. Given that most new construction is gas-fired generation, it is possible that there would be a need for such base load generation in many regions of the country around 2010 to 2013. Otherwise, a significant proportion of energy would come from gas-fired plants that could raise the overall cost of electricity supply, or, at a minimum, create undesirable price volatility.

When and Where Will Coal Plants Be Built?

Table 2 shows the expected need for new coal-fired generation in each National Electric Reliability Council (NERC) region by 2010, assuming load growth of 2%, an end to the gas-fired construction cycle by 2007, and negligible retirements. Proposals for more than 44,000 MW of new coal capacity are under consideration (source: Platt’s POWERDat Database January 2004) and although a large number these will likely not materialize, about 4,900 MW is already either under construction or under advanced development, with about another 11,000 MW in early development.



The ECAR and MAIN regions are expected still to have a surplus of base load generation as far out as 2010. However, new coal plants are expected to come on line in these regions because they export significant amounts of generation to the SPP, NPCC, and MAAC regions, all of which are forecast to require significant additional base load generation by about 2010. Although SERC suffers from perhaps the worst overcapacity among all NERC regions and has high costs of delivered coal, new coal plant construction will be supported by the fact that a large proportion of the region’s generation is gas-based and coal will enjoy a significant economic advantage.

WECC will always require more base load generation than would be indicated by its abundance of hydro resources because such generation will serve as critical back-up during dry years. Although gas plants have claimed a significant share of such needed capacity over the past few years, load growth will eventually support more coalfired generation because no new hydro generation capacity, is planned, or even possible. Also, the economics of new coal plants, particularly in the Powder River Basin, are supported by perhaps the lowest delivered coal costs in the U.S. Unfortunately, significant transmission bottlenecks restrict the ready transportation of power from the Powder River region, and the areas of WECC and MAPP immediately adjoining this area have a surplus of base load generation. New transmission that provides access to regions that require base load generation, such as California and Colorado, could be key.

Over the next several years, many factors, including load growth, transmission constraints, and retirement of older units, will play important roles in determining exactly when, where, and how new base load generation will be required. However, given the current excess of gas-fired capacity, the price differential between gas and coal is key to the economics of new coal projects. Studies have shown that gas prices need to stay above $3.50 per million BTU (mmbtu), although specific situations can still make a coal plant competitive at gas prices below that level (see chart). This price is a significant threshold because it is expected to be the price at which LNG receiving and gasification terminals become viable. Given that the U.S. is expected to import increasingly larger amounts of natural gas, chiefly in the form of LNG, $3.50 per mmbtu seems to be a good benchmark at which to measure the competitiveness of a proposed new coal plant. The significantly lower volatility of coal prices is an added benefit.

Technology and Project Schedules

Technology.There have been few notable innovations in coalfired generation technology in recent years that provide improved operational efficiencies. Pulverized coal-combustion (PC) technology has, and is expected to be, the dominant technology for coal-fired generation. However, newer supercritical and ultra-supercritical variations allow for better combustion efficiencies and these technologies are now overcoming the negative reputation created by the poor performance of first-generation units, including lower availability and higher operating and maintenance (O&M) costs.

A survey of proposed coal-fired generation projects also shows a greater presence of fluidized-bed combustion (FBC) and integrated gasification combined-cycle (IGCC) technologies. Although FBC provides significant emissions reductions and greater fuel flexibility (including the use of waste coal), it suffers from an inability to scale beyond 350 MW. This technology could be attractive to utilities looking to exploit local sources of low-quality coal, particularly if the plant is seen as being environmentally friendly by using mine waste in states with old coal mines.

Although projects have been proposed using IGCC technology, which offers the best thermal efficiency and environmental performance, Standard & Poor’s is not optimistic about the prospects for this technology because it is very expensive and has the poorest commercial record with low availability, high O&M costs, and long start-up times. It also appears that interest in this technology is driven mainly by state utility commissions’ interest in studying the economics of a promising technology, rather than any interest on the part of utilities themselves. For instance, the Public Service Commission of Wisconsin required Wisconsin Electric Power Co. to explore the IGCC option, only to reject it as not being cost effective.

Schedule. The construction period for a coal-fired plant is expected to remain largely unchanged, with about two years for permitting and 36 to 42 months for construction. A typical project schedule is expected to consist of four nine-month construction periods for earthwork and foundations, structural erections, equipment installation, and system piping and wiring. This will be followed by a six-month start-up cycle. The Springerville Unit 3, being built by Tri-State G&T Assoc. Inc., which started construction in October 2003, has a 38-month construction period with Bechtel as the construction contractor, while the Council Bluffs Unit 4 being built by Mid- American Energy Co., which also broke ground recently, expects to be on line by summer 2007. Council Bluffs Unit 4 is the first plant in the country to be built using Mitsui’s ultrasupercritical PC technology, which probably contributes to the slightly longer construction period.

Environmental issues. While IGCC is certainly the cleanest technology, new PC and FBC plants that use the best available control technology can meet all standards established under the EPA's New Source Review guidelines. One of the crucial risks for new and existing coal-fired generation is the possibility of new, more stringent laws on carbon dioxide and mercury emissions that could mandate substantial capital expenditures. In fact, the risks inherent in environmental issues would be as important a consideration as the economic advantage over gas for utilities investing in new coal plants. In some borderline situations, they may even tilt the balance in favor of gas-fired generation. The many coal projects currently under development likely consider the risk of potential additional capital expenditures as being more manageable than that of annual volatility in gas prices. Moreover, environmental capital expenditures will be accurately known once the new laws are passed, while gas price volatility and a gas plant's position on the dispatch curve are bound to vary all the time. Standard & Poor's will closely monitor the evolution of environmental issues and expects to publish articles on the effect of upcoming federal environmental legislation on new and old coal plants and the cost impact of such laws.


Finally, early builders could have a first-mover advantage in that they could improve their economies of scale by building plants larger than their requirements and signing longterm bilateral off-take contracts for the surplus capacity with other utilities that need base load generation. Indeed, we see precisely this happening in the case of the Council Bluffs, Springerville, and Nebraska City Unit 2 project (Omaha Public Power District), where the primary sponsors of the project are only taking a portion of the output, sometimes as low as 50%.