By: Brian K. Schimmoller, Managing Editor
Market forces have dampened activity in the boiler industry, but various factors are sustaining a suprising level of interest.
The boiler industry, which has gone through several ups and downs in recent years, sits in choppy waters these days, buffeted on all sides by an array of economic, regulatory and financial issues. At the beginning of the gas turbine boom, the boiler market – outside of heat recovery steam generators – was flat to nonexistent. Environmental pressures, pending legal action against a number of coal plant owners, and the higher cost and longer development times associate with boiler plants, kept the market stagnant.
In the midst of the gas turbine boom, however, fortunes turned and the boiler industry looked poised for substantial growth, as high gas prices and concerns about fuel security led many utilities and plant developers to seriously evaluate coal-fired boilers for meeting future demand. Upwards of 50,000 MW of coal-fired boiler capacity was in some phase of development in early 2001.
The economic downturn, coupled with the financial and credit crunch in the power generation industry in late 2001 and 2002, turned the tables on the boiler market again, and many of the solid-fuel boiler plants under development quietly made their way to the back burner. New orders for HRSGs began to slow during this time as well, in line with the overall industry slowdown and the rash of power plant project cancellations.
Which brings us to early 2003. Gas prices have risen substantially, but the price rise has not reinvigorated the boiler market – yet. With reserve margins climbing as new gas-fired power plants come on-line, and with economic activity still subdued, developers are taking a much more cautious approach than they did two years ago. The effect of liquefied natural gas (LNG) has also been amplified. “LNG terminal operators and developers claim they can deliver gas to the U.S. coast for less than $4.00/MMBtu,” said Dennie Hunt, chairman of the board of the American Boiler Manufacturers Association (ABMA). “I’ve also heard from power plant owners that they will favor gas turbine-based plants over solid-fuel plants at gas prices up to $4.50-4.75/MMBtu.” This changes the historic economic equation with respect to boiler development.
Still, the longer higher gas prices persist, the more attractive coal-fired power plants become – and the potential for a tight domestic gas market remains quite high. “A record level of domestic drilling for natural gas in 2001 failed to produce the desired supply response necessary to adequately fuel the new generation of gas-fired capacity already installed, and with many more units continuing through construction in 2003, this undersupply trend is anticipated to continue,” said Bernard H. Cherry, president and CEO of Foster Wheeler Power Group Inc. Despite gas prices of $4 and $5/MMBtu, twice the traditional market levels, domestic drilling activity continues to stagnate.
New Capacity Requirements
A valid question facing boiler developers is how much new capacity will be needed over the next several years. With 27 GW of new capacity brought on-line in 2000, 43 GW in 2001, about 62 GW in 2002, and another 25-30 GW planned for completion in 2003 – almost exclusively gas-turbine capacity – the need for additional capacity is uncertain. In its recently released Annual Energy Outlook, the Energy Information Administration projects the need for 164 GW of capacity between 2001 and 2010. However, with more than half of that total already in operation by 2003, the market for new generation through 2010 comes in well below 10 GW per year. EIA predicts 74 GW of new coal-fired capacity between 2001 and 2025, 17 percent of the new capacity total (428 GW), but almost all of that is projected for operation after 2010.
The end of the gas turbine boom is forcing everyone to re-evaluate growth plans. Absent a 1990s-type economic boom, growth will be limited for the next several years. “I don’t expect the industry to come out of the current slump in new orders until 2006/07,” said Hunt. “And when new orders do come, it’s not clear if the new orders will be filled by new equipment or by the growing number of gas turbines and HRSGs in storage or never completed.” This introduces yet another uncertainty factor to the boiler market.
The industrial side of the boiler market faces similar challenges. “The industrial boiler market is almost entirely dependent on the economy and the removal of regulatory and economic uncertainty,” said Randy Rawson, president of ABMA. “Until the markets calm down and we experience significant growth in manufacturing, I don’t see managers making decisions for major upgrades and optimizations. For industrial boiler owners, the key is New Source Review, and whether people will be able to make confident long-term capital decisions regarding equipment upgrades.”
The makeup and operation of electricity markets will also influence the boiler market. For example, given the current economics of electricity sales, changes in how the value of coal-fired generation is perceived are bound to result. As gas prices escalate, the “coal spark spread” (difference between power prices and coal prices) rapidly increases as well, which significantly improves the profitability and value of coal-fired units.
“The year-on-year change in coal spark spread in fourth quarter 2002 from fourth quarter 2001 was up approximately 140 percent – at $20.85/MWh versus $8.80/MWh,” said Foster Wheeler’s Cherry. “This was partly due to a 40 percent increase in electricity price, year-on-year, in parallel with a modest decline in coal prices. Power-generation industry participants, with large proportions of coal-fired generation, are currently seen to have significant potential for earnings-per-share improvements, while predominantly gas-dependent electricity producers are expected to see declining earnings, despite the higher electricity price levels. If this paradigm shift in fuel prices for electricity continues, the boiler industry could have no better promotion than the actual economics of daily electricity sales.”
With the Republican Party attaining control of both houses of Congress, and with recent actions from the Bush Administration pertaining to environmental issues, many boiler-related participants are optimistic about finally achieving the environmental certainty that will permit capital improvements. Whether it’s piecemeal, through individual legislative and regulatory proceedings, or comprehensive, through an energy bill, is open to debate, but it’s likely that 2003 will see movement on a range of issues, including New Source Review, multi-pollutant control, and renewable portfolio standards. “If the Republican Congress doesn’t capitalize on this opportunity to take some regulatory and legislative action with respect to environmental certainty, it will be a major disappointment,” said Rawson.
The Bush Administration is already moving on New Source Review (NSR). In late November 2002, the EPA proposed revisions designed to overhaul the NSR Program under the Clean Air Act, making it easier for power plants to upgrade or perform maintenance without triggering New Source Review. EPA is also seeking comment on language defining how routine maintenance, repair and replacement (RMRR) activities would be handled, a controversial issue with a lengthy history.
The new NSR provisions could make projects such as the steam turbine upgrade at Xcel Energy’s Valmont plant in Colorado more common. Valmont spent $15 million to increase their steam turbine capacity from 181 to 195 MW without increasing Btu input, according to Thomas Hewson, principal with Energy Ventures Analysis, in a report published in Electric Light & Power. Heat rate at Valmont fell from 10,400 Btu/kWh to 9,272 Btu/kWh, an 11 percent improvement.
“If the NSR is issued as the Bush administration proposed it, you’ll see much more investment such as Valmont’s with accompanying improvements in heat rate,” said Hewson. Moreover, the investment risks tagged to such projects will likely be orders of magnitude lower than those associated with new boiler construction projects. The fate of the proposed NSR revisions is not certain, however, as several Congressional critics have promised to effectively kill the new rules by refusing to allow EPA to spend money on implementation or enforcement.
Although new boiler-based project development has slowed in the past year, it has not stalled completely. Several large-scale projects continue. Although Reliant Energy has had to cancel or delay at least a half-dozen projects – primarily gas-fired turbine projects – because of market and financial conditions, construction never slowed at its Seward plant in western Pennsylvania. The 521 MW (net) waste-coal-fired merchant fluidized bed boiler project, which Reliant is developing with EPC contractors Duke/Fluor Daniel and Alstom Power, is within budget and on-schedule for a May 1, 2004 operational date.
Construction was about 65 percent complete as of mid-January 2003, with all major materials on-site. Somewhat ironically, Seward actually benefited from the industry slowdown, since the anticipated labor shortage associated with power plant construction never materialized, according to Mike Proffit, Reliant Project Engineering Manager.
Reliant Energy is on budget and on schedule for a May 2004 start-up of the 521 MW (net) waste coal-fired fluidized bed boiler at the Seward plant in western Pennsylvania. Photo courtesy of Reliant Energy.
Seward recently passed one of its main project milestones, completing site remediation tasks associated with the 3.5 million tons of waste fuel impounded on-site from previous activities. Mixing one part waste fuel with one part CFB ash from three nearby plants, Reliant remediated much of the 100-acre site with anywhere from 5 feet to 40 feet of material, according to Project Manager Rick Blanchette.
Despite the relatively low power prices around the country for the past year, Seward sits in a prime dispatch position. “The boiler market is not very active right now because of the broader slowdown in demand, but we’ll be the low-cost producer in the PJM market,” said Proffit. Seward will provide two-and-half-times more power than the unit it is replacing, but will emit 74 percent less NOx, 85 percent less SO2, and 90 percent less particulate matter.
The Omaha Public Power District plans to build another coal-fired boiler unit at its Nebraska City Plant south of Omaha. Photo courtesy of Omaha Public Power District.
Peabody Energy is actively courting the merchant power market as well. The Thoroughbred Energy Station, a 1500 MW pulverized coal boiler in western Kentucky, cleared a major regulatory hurdle in November when the Kentucky Natural Resources Council issued an air quality permit to the plant. Considerable opposition to the plant exists, and construction and water withdrawal permits are still pending, but Peabody is optimistic about its future, citing a potential return to supply shortfalls when the economy returns to normal growth rates. Peabody is still seeking partners for the project.
Wisconsin Public Service Corp. (WPSC) has proposed an additional boiler unit at its Weston Plant in central Wisconsin, and awarded a contract in January to Black & Veatch for conceptual and detailed engineering, permitting support, and procurement assistance. “Some of our power plants are getting old and are more difficult to maintain,” said Tom Meinz, senior vice president of WPSC. “That issue, in conjunction with steady growth in electric demand, are the major reasons for this much-needed addition to our system.”
WSPC selected coal as the fuel for the 500 MW Weston Unit 4 in part to avoid the significant fluctuations in the price of natural gas in recent years, according to Meinz. The plant will rely on supercritical boiler technology to achieve the higher efficiency and lower emissions required of modern coal-fired power plants.
Farther west, MidAmerican Energy Company is proceeding with plans to add a fourth PRB coal-fired boiler unit at its Council Bluffs Energy Center in Iowa by 2007. MidAmerican has entered into a joint ownership agreement with 14 other utilities to take all of the plant’s approximately 750 MW, according to spokesman Kevin Waetke, and is currently in the process of defining EPC specifications and obtaining the necessary permits. Groundbreaking is expected later this year.
Also prominent in the development of new boiler projects are the electric cooperatives, state and municipal utilities, and public power agencies. East Kentucky Power Cooperative began construction of the Gilbert Unit at its Spurlock Station last summer, with on-line operation set for spring 2005. Gilbert will feature a 268 MW multi-fuel fluidized bed boiler that will fire coal as well as several million tires a year and up to 150,000 tons of biomass.
Sunflower Electric Power Corporation, a Hays, Kans.-based cooperative, received an air quality construction permit in October from the Kansas Department of Health and Environment for a new 600 MW coal-fired power plant to be built on the site of the existing Holcomb Unit 1. The permit authorizes Sand Sage Power LLC, a Sunflower subsidiary, to install and operate a pulverized-coal boiler, one natural gas auxiliary boiler, and a new cooling tower, and authorizes changes to the existing coal, lime and ash handling systems, which will be shared between Holcomb and Sand Sage.
Sunflower is proceeding with activities to secure water for the new plant and to finalize the EPC contract, according to spokesman Steve Miller. In the plant’s favor is the fact that 12 legitimate prospects have been identified to buy power from the facility, some of which have also indicated an interest in ownership in the plant. A hurdle yet to be scaled concerns transmission. “We have to have continued cooperation from the RTOs and perhaps from the state of Kansas to give us the ability to reliably move power around the state and the region,” said Noman Williams, senior manager of transmission services for Sunflower. Sunflower expects the unit to come on-line in 2007.
In South Carolina, site preparation has begun for the $675 million coal-fired boiler expansion at Santee Cooper’s Cross Station, and 12 contracts have been let totaling $282 million, according to Willard Strong, spokesman for the state-owned utility. Originally approved in May 2001 as a 500 MW power plant, the Santee Cooper Board of Directors subsequently approved an upgrade to 600 MW in light of projected demand growth in South Carolina. Parsons Energy and Chemicals has been hired as the A/E for the project and a subcritical boiler from Alstom Power has been ordered. Construction is expected to begin soon after environmental permits are received, which is expected in the first quarter of 2003. On-line operation is scheduled for January 2007.
The Omaha Public Power District received approval in mid-2002 from the Nebraska Power Review Board to build up to 600 MW of coal-fired capacity on the site of OPPD’s Nebraska City plant. The size of the boiler could be anywhere from 300 MW, enough to satisfy OPPD’s projected native load growth, up to 600 MW, if OPPD can secure customers for the additional output, according to OPPD spokesman Mike Jones. OPPD is currently evaluating proposals from various regional utilities for buying power from the plant, and is also pursuing permits for the plant, which is scheduled for operation in 2009.
The state of Illinois is actively courting new coal-fired power plant development. Peabody Energy is pursuing a sister station to Thoroughbred in southern Illinois, and the state of Illinois is offering various project subsidies and tax benefits that have attracted other plant developers.
Though rather small, at 91 MW, and funded in part by the state of Illinois and the U.S. Department of Energy, the Corn Belt Energy Generation Cooperative plant in southern Logan County reflects the importance Illinois still places on its native coal resources. Corn Belt will integrate a natural circulation boiler with advanced low NOx combustion and emission control technologies. The combustor is a Babcock Power Inc. U-fired furnace that converts nearly all of the coal ash to a glass-like slag by-product which is one-third the volume of a conventional boiler. The slag is inert and can be used in the construction industry, eliminating the high cost for ash disposal and storage.
On the other side of the ledger, a variety of factors have forced several entities to cancel or delay boiler projects in recent months. Great River Energy, which hoped to build a 300-500 MW lignite-fired power plant in North Dakota, announced on Dec. 31 that it had halted its feasibility study “primarily because our latest load projections indicate an intermediate, or combined-cycle, power plant in Minnesota would better serve the needs of our customers,” said Tim Seck, leader of GRE’s baseload study team. Seck also cited the regulatory risks associated with transmission policy and the high cost of transmission in delivering the electricity to GRE’s customers in Minnesota.
NRG Energy, due in large part to its financial and debt-related problems, has shelved plans, at least temporarily, to develop an additional supercritical coal-fired boiler unit at its Big Cajun facility in Louisiana. Duke Energy decided to halt its pursuit of a coal-fired power plant in Virginia in September based on the economic feasibility of the project. And while Wisconsin Energy remains committed to its “Power the Future” program, it is facing significant public opposition to its plans to develop three supercritical boiler units at its Oak Creek plant. City officials in Oak Creek announced in November that they oppose plans for the new units, citing the environmental impacts of an additional “70,000 tons of pollution.” One compromise option reportedly under consideration is scaling the program back to two new coal units rather than three.
The fact that some plants are moving forward while others are not reinforces the site-specific nature of boiler projects. Any belief that a boom in boiler projects could mirror the boom in gas turbine projects in terms of size and speed is fundamentally flawed, and ignores the many more complicating factors attendant to boiler projects – including higher capital costs, longer development and construction schedules, complex permitting and emissions control requirements, and a host of other public concerns (noise, road traffic, visual impact, land use).
Moving forward, it will be interesting to track the dynamics between the new boiler plants and the existing boiler fleet. Will the new boilers knock the older boilers far enough down the dispatch order to force their retirement? With maintenance spending for existing plants significantly down and/or delayed at most facilities, are existing plants engineering their own demise? Will new plants be able to accommodate future emissions control requirements more effectively than the older plants? Will the promised efficiency and environmental performance of the new units convince skeptics that “clean coal” is not an oxymoron?
The Next Boom
When the next “boom” or “boomlet” hits the power industry, probably not until the latter half of this decade, the mix of technologies will likely be much different than the turbine-dominated boom just completed. “The next round of power plant orders in the U.S. won’t be all gas turbine combined cycles,” said Del Williamson, President of Sales for GE Power Systems. Renewable energy technologies will likely make additional inroads, but the boiler industry will be an important part of the mix as well.
Advanced technology boiler plants – gasification, fluidized bed combustion, and supercritical and ultrasupercritical steam cycles – designed and equipped for minimal emissions and maximum efficiency, will likely be more common. Movement in this direction is already occurring, as indicated by Reliant’s Seward plant, the fluidized bed repowering of JEA’s Northside power plant (Power Engineering, Dec. 2002), and the selection of supercritical steam cycles for Wisconsin Public Service Corp.’s Weston Unit 4 and EPCOR’s new 450 MW coal unit at the Genesee plant near Edmonton, Alberta.
Moreover, public-private R&D is under way around the world to identify, evaluate, and qualify materials technology for construction of coal-fired boilers with advanced steam cycles capable of operating at much higher efficiencies than current state-of-the-art facilities. Efficiency gains of at least 8-10 percent are expected, for example, through the materials technology being developed in a collaborative program led by EPRI and DOE.
The efficiency increase will be achieved principally through development and application of materials technology suitable for reliable operation under ultrasupercritical steam conditions, according to Dr. R. Viswanathan, EPRI Project Manager. Alloy development and evaluation programs being carried out in Europe and Japan
have identified ferritic steels capable of meeting the duty requirements of ultrasupercritical plants to approximately 1150 F. A European project is under way to achieve steam conditions of about 1290 F and 5500 psi with the help of nickel-based alloys.
The collaborative U.S. program includes work to identify, fabricate, and test advanced materials and coatings with mechanical properties, oxidation resistance, and fireside corrosion resistance suitable for cost-competitive boiler operation at steam temperatures of up to 1400 F at 5500 psi. In addition, exploratory attention is being given to the materials issues impacting boiler design and operation at temperatures as high as 1600 F. The project is funded through the DOE’s National Energy Technology Laboratory, co-funded by the Ohio Coal Development Office, and managed by Energy Industries of Ohio. EPRI is providing overall technical direction and coordination. Participants at present include the domestic boiler manufacturers, i.e., Alstom Power Inc., Babcock Power Inc., Babcock & Wilcox Company, and Foster Wheeler Inc., as well as Oak Ridge National Laboratory.
In the first year of the 5-year program, preliminary studies have been completed for two alternate ultrasupercritical boiler designs. Areas exposed to different temperatures and pressures have been mapped, and piping and tubing dimensions have been delineated. Candidate materials for piping, headers, superheater/reheater (SH/RH) tubing, and waterwall panels have been identified.
For piping and headers, a candidate ferritic material has been identified for temperatures up to 1150 F; and nickel-based alloys such as Nimonic 230 and Inco 740 have been identified as candidates for higher temperatures. For SH/RH tubing, these same nickel-based alloys will be considered for the highest temperatures, while several austenitic steels are being considered for intermediate temperatures. For waterwall panels, T92 and T23 seem to be alternate candidates.
“Due to limitations in the strength of available alloys, initial analyses have focused on a boiler design with a steam cycle operating at about 1350-1400 F at 5500 psi,” said Viswanathan. Unit efficiency is estimated to be about 46 percent for a single reheat cycle and 48 percent for a double reheat cycle; this design is estimated to reduce CO2 emissions by 15-22 percent. Based on these efficiency advantages, EPRI performed breakeven cost analyses to assess critical cost considerations: