By: Brian K. Schimmoller, Managing Editor
A growing desire for fuel diversification is driving interest in the boiler market and pulling it out from the shadows.
Less than a year ago, the boiler market appeared poised for a substantial resurgence, ready to take a bold step from behind the gas boom’s large shadow. In the aftermath of the dramatic gas price spikes in late 2000 and early 2001, several analysts predicted significant demand for new solid fuel boiler plants, 50,000 MW or more of new capacity by some estimates.
The slumping economy and the plunge in gas prices have tempered this demand somewhat, although there is still enough boiler-based project development pending to be called a solid resurgence. In many of these projects, however, the primary justification for pursuing a solid fuel boiler plant rather than a gas-fired plant has shifted from the fuel price differential to the desire for fuel diversification. “Most merchant plant developers seem to believe that fuel diversity means some firm gas and some spot gas,” said Jack Makuch with Consulting Services International in a paper presented at POWER-GEN International this past December in Las Vegas.
While that tongue-in-cheek remark may not be entirely fair to merchant plant developers, it does bring attention to the dangers of over-reliance on one fuel supply, both at the micro-level (for individual companies) and macro-level (for the entire country). Some developers and utilities are reacting to this potential problem by actively seeking to reduce their reliance on natural gas and its susceptibility to price spikes caused by events outside the fuel users control. Wisconsin Energy Corp. specifically refers to the need to “maintain a diverse generation mix” in supporting its decision to pursue additional coal-fired generation capacity. MidAmerican Energy espouses a similar philosophy in justifying its proposed coal-fired Council Bluffs, Iowa facility: “MidAmerican is committed to a diversity of generation sourcesellipseBut coal is the backbone of our and the nation’s generation because it is plentiful, economical and located here in the United States.”
The depressed natural gas prices might reduce the attractiveness of some new boiler projects, but a price correction is expected eventually. “What goes down must come up,” said Nancy Mohn, Director of Marketing Strategy with ALSTOM Power. “Interestingly, despite the fall in gas prices, many of the coal developers are still saying their pro formas are favorable, based on long-term gas futures prices in the $3.50-4.00 range. In any case, fuel prices for coal-fired boiler plants are much more predictable, and I believe every new coal plant that comes on-line in the next few years will dispatch and compete with gas and nuclear.”
Most analysts expect gas prices to rebound and settle in the $3.00-$3.50/MMBtu range within a few years, while coal prices remain in the $1.00-$1.25/MMBtu price range delivered. Such a delta makes coal reasonably attractive. “With gas at $3.00/MMBtu and coal at $1.25/MMBtu, coal is competitive,” said Jim Wood, recently appointed president and CEO of Babcock Borsig Capital Corp. during a press conference at POWER-GEN International.
The size of the boiler market over the next 5-10 years is a constantly moving target, impacted by factors such as fuel price differential, forward pricing curves for power, the fate of environmental legislation and regulations, local and global pressures to reduce CO2 emissions, economic growth and public acceptance. Project inquiries have slowed somewhat since last year, but enough of a market is expected to exist to attract new and old boiler OEMs to North America. Babcock & Wilcox, Foster Wheeler, Babcock Borsig Power, Alstom Power, Hitachi and others are all pitching their boiler technologies to project developers.
To satisfy some of the 15 GW annual growth in installed capacity needed to meet U.S. electricity demand, Babcock Borsig’s Wood foresees orders for 5,000-6,000 MW of coal-based boiler capacity in the next few years. “Attractive sites exist across the U.S., from western Pennsylvania to the Dakotas and Wyoming, and south to Texas and the Southwest,” said Wood.
AES Guayama plant under construction in Puerto Rico. Photo courtesy of AES Corp.
Hitachi provides comparable figures. “We do appreciate that large pulverized coal supercritical plants will not, and indeed, cannot be built in the same quantities as gas-fired combined-cycle plants,” said Katsukuni Hisano, president and CEO of Hitachi Ltd., in a press conference at POWER-GEN International. “Expert opinions, in fact, vary as to how many will ultimately be built, but numbers in the 10 to 20 range seem to be the most commonly accepted in the industry.” At a conservative per-unit capacity assumption of 500 MW, this translates into 5,000-10,000 MW of new North American coal capacity. Hitachi is taking the first bite of that total; EPCOR recently awarded Hitachi Canada Ltd. the EPC contract for the coal-fired 475 MW Genesee Phase 3 power project near Edmonton, Alberta.
Energy Ventures Analysis (EVA), an Arlington, Va.-based consulting company that tracks new power plant development, identifies about 2,500 MW of coal capacity in construction, another 4,000 MW nearing construction, and about 18,000 MW in various stages of development. The prospects for the last category depend on the company developing the project. “We see three classes of developers emerging for boiler projects,” said Michael Schaal, senior analyst with EVA. “The first class, the regulated developer, is in a good position because it can put the plant in its rate base and adopt a long-term perspective that minimizes concerns about low gas prices in the near term. The second class, the IPP with a track record, is also in a reasonably favorable position because it has demonstrated its ability to successfully develop, build and operate power projects in the past, but is still sensitive to gas prices in the intermediate term, three to five years. The third class, the speculative developer, is where most of the uncertainty lies. These outfits are counting on high gas prices and high electricity prices to make merchant coal projects attractive, and it’s unclear if they will be able to attract the investment necessary to move such projects forward given the current state of both the electric and gas markets.”
Pending emissions regulations – and the threat of tighter regulations – are often thought of as potential nails in the coffin of coal-fired generation. In part because of its cleaner image, natural gas is expected to increase its share of generation from about 16 percent currently to 32 percent in 2020, according to Energy Information Administration projections, while coal’s share drops from 52 percent to 46 percent.
It’s possible, however, that a strategy aimed at concurrently improving the environment and maintaining a diverse generation mix could actually help the boiler market. By replacing existing coal-fired units with new, cleaner, more efficient boilers, both objectives could be met, according to Consulting Services International’s Makuch. One way to do this would be to license the new units for only 20 or 30 years under a fixed set of environmental regulations. Continued operation beyond the original license period would be under a new set of rules, to be determined at that time.
A number of new coal-fired boiler projects are reaching the point of no return (Table 1). The majority of these are being developed by conventional utilities, unregulated utility subsidiaries, or public power entities with the demonstrated financial and project resources to carry them to completion. A number of new players are emerging, however, including Peabody Energy, EnviroPower, Westmoreland Energy, LS Power, National Energy Group and others.
After a decision has been made to pursue development of a solid fuel boiler project, the next-most important decision-point is technology selection since the boiler will typically be on the critical path once construction begins. The critical path takes on added significance in today’s competitive, “get the unit on-line yesterday” arena, and boiler projects will have to trim months off the historic construction timeline to prove economic.
The three main boiler options under consideration by developers pursuing solid fuel projects are subcritical drum, once-through supercritical and fluidized bed technology. The newer clean coal technologies, such as gasification and pressurized fluidized bed combustion, are on the radar screen, but typically not on the short list. “One cannot add the risks associated with a technology that is not already commercially proven to the other, already formidable, financial risks,” said Makuch.
Claims that gasification is already commercial are accurate – to the extent that the Polk IGCC plant in Florida, for example, has been used to generate electricity on a commercial scale beyond its government-funded demonstration period – but that only paints half the picture. Many developers are uncomfortable with the availability records of the gasification facilities. “Although gasification is evolving into a competitive, technically sound technology, its operating record has not sufficiently developed to convince the financial community that the risks are manageable,” said Thomas Hansen, Vice President and Technical Adviser at Tucson Electric, which is developing two additional coal-fired units at its Springerville Station. Hansen added that his company could not justify the selection of gasification when the “best IGCC plant in the country could only achieve about 70 percent availability.”
Subcritical boiler technology represents a mature, proven technology with predictable capital, operating and maintenance costs. As such, it’s no surprise that many of the new coal units under consideration are leaning toward the subcritical option. Tucson Electric and Santee Cooper have committed to subcritical boilers, and Sunflower Electric will likely use conventional subcritical boiler technology as well. “We have 11 other coal-fired units that utilize subcritical technology,” said Phil Pierce, Santee Cooper project manager. “We are familiar with the operation of these type of units. The capital cost for a subcritical unit is less and it minimizes staffing and training issues for us.”
Supercritical boiler technology, despite its checkered past in the U.S., is receiving close inspection. As noted in Table 1, several developers have committed to supercritical and almost all have given it a thorough review. “We seriously considered supercritical technology at Springerville,” said Hansen, “but based on the expected fuel costs and operating mode, subcritical boilers were the more economic choice. The units will run baseload in summer and ramp in the winter. If the expected demand profile had leaned toward more baseload operation, supercritical boilers would have been a more attractive choice.”
Continued development and application, primarily in Europe and Japan, have resulted in designs that are only slightly more expensive than subcritical units, that consistently demonstrate high reliability records, and that have the ability to cycle while retaining excellent part-load efficiency. At operating pressures of 3,500-4,500 psig and main and reheat steam temperatures of 1,000-1,100 F, newer supercritical boilers can provide a 5-15 percent efficiency advantage over existing coal units, according to Makuch, with a design efficiency that is about 70 percent of the design efficiency of the best gas-fired combined cycle.
MidAmerican Energy has identified its Council Bluffs, Iowa, facility as the preferred location for a planned supercritical 900 MW power plant. Photo courtesy of MidAmerican Energy.
“Many of the supercritical units in Germany operate at 40-44 percent efficiency (LHV), and further advances by Babcock Borsig AG and the German utility companies are expected to result in double reheat units achieving efficiencies approaching 50 percent (LHV) using steam temperatures in excess of 1,100 F,” said Professor Dr. Klaus Lederer, chairman of the board of Babcock Borsig AG. In Japan, HHV efficiencies in the mid-40s have been achieved without sacrificing availability. The Japanese government, in fact, mandates 99 percent availability for its supercritical plants, according to Hitachi’s Katsukuni Hisano.
Fluidized bed combustion technology remains a promising technology for developers pursuing plants that will fire low-quality or variable fuels. Fluidized bed boilers offer the flexibility to fire a range of fuels – from waste coal fines to high-moisture lignite to biomass resources – while controlling emissions within permitted levels. EnviroPower LLC has indicated it has plans to develop more than 4,000 MW of waste coal-fired capacity in the U.S. using fluidized bed boilers. Most fluidized bed projects are in the 100-250 MW per unit range, although larger units are possible. Foster Wheeler, for example, based on its efforts developing two 300 MW CFB boilers for the Jacksonville Electric Authority, will now quote prices on individual fluidized bed units at 400-450 MW, according to Ian Lutes, senior vice president with Foster Wheeler Energy International.
For the 30,000-40,000 MW in solid-fuel projects under development in the U.S., ALSTOM’s Mohn estimates about 30 percent are fluidized bed combustion units, 68 percent are pulverized coal plants, and 2 percent are gasification projects on a MW basis. Based on the number of projects under development, there is probably closer to an even 50-50 split between fluidized bed combustion and pulverized coal, which confirms that the fluidized bed boiler projects are much smaller. For those developers interested in pulverized coal technology, about one-third are focused on subcritical units, one-third are focused on supercritical units and one-third are unsure, according to Mohn. Babcock Borsig offers comparable numbers; of the 50-60 pulverized coal projects it is tracking, about half are subcritical units and the other half are on the fence, but leaning toward supercritical as they become more familiar with its benefits. The interest in both subcritical and supercritical systems, as reflected in Table 1, reinforces the need for multiple technology options since developers apply different weighting factors to their pro forma calculations.
Supercritical boiler technology offers an additional benefit over the competing technologies. Because of its higher efficiency levels, CO2 emissions are substantially less. Although it’s not clear when or to what extent carbon emissions will be regulated in the U.S., it’s increasingly likely that some form of carbon constraint will be imposed at an undetermined point in the future, and the more efficient boiler plants will stand a better chance of surviving.
Cost and Financing
The almighty dollar, of course, has much to say about whether the boiler market demonstrates a significant upsurge and also about which technologies are implemented. Each project must promise a reasonable return in a reasonable length of time, which requires the existence of stable power offtake agreements (and/or access to lucrative wholesale market opportunities), manageable capital costs, and the availability of funds.
The last item – availability of funds – is becoming more important in light of the growing risks surrounding project-financed ventures in the power industry. “There’s definitely a trend toward balance sheet financing in the industry,” said Foster Wheeler’s Lutes. “Developers considering project financing will have to negotiate a single-point wrap with the EPC in order to convince lenders that the risks are manageable. The EPC, in turn, to cover its risks, will raise the price to the developer, and the $/kW cost will go up. This chain of events may prevent some projects from moving forward.”
Table 1 includes the nominal $/kW costs for seven of the most likely PC boiler projects under development. Costs range from the $1,000/kW range up to more than $1,500/kW. Notably, all seven plants represent additions to existing coal plants, to take maximum advantage of existing infrastructure and experience and to minimize costs associated with greenfield development, which can add 10 percent or more to the overall cost.
In general, the costs of the supercritical units listed in Table 1 are higher than those of the subcritical units, although much of this difference is likely due to site-specific factors and not to the technologies themselves. Most industry experts peg the capital cost delta between new subcritical and supercritical boilers built in the U.S. at around 5 percent. Capital costs can go much higher, of course. “For some of the highly automated once-through units in Europe with multiple equipment redundancies, push-button cycling capabilities and a greater emphasis on plant aesthetics, the price can exceed $3,000/kW,” said Foster Wheeler’s Lutes.