A new future for small coal-fired plants.
Small coal-fired plants are particularly vulnerable to economic and environmental pressures, putting some plant owners in what seems like a no-win position. But an emerging option—biocoal from crop wastes—might give small coal units a new lease on life.
The United States has roughly 1,400 operating coal-fired generating units, producing almost 2 billion MWh of electricity a year. These units produce almost 50 percent of our electric power, along with almost 35 percent of our CO2 emissions1 and up to 40 percent of our ground-level air pollutants such as SO2 and NOx.
These 1,400 units are quite a diverse group. For example, Figure 1 shows the distribution of units by initial operation date and capacity.2 The age of these units covers a span of almost a century and the capacity covers more than three orders of magnitude from less than 1 MW to more than 1,000 MW.
Given their economic and environmental significance, there is considerable discussion both in private strategy and public policy circles regarding management decisions affecting these units. Should an older unit be shut down or refurbished? Should environmental controls be added to an uncontrolled unit? Should a unit in a suitable location be converted to natural gas? And so forth. These management decisions can have substantial impacts locally, nationally and even globally.
Since larger units play a dominant role in the coal portfolio, it isn’t surprising that most of this discussion involves such plants. However, smaller units—those 100 MW or less in capacity—are important as well. There are roughly 150 units totalling over 800 MW that are each 10 MW or less in capacity and roughly 600 units totalling 20,000 MW that are each 100 MW or less in capacity (see Figure 2). These 600 smaller units annually produce more than 100 million MWh in electric power and more than 100 million tons of CO2, along with a substantial amount of ground-level air pollutants. While these units are well under 10 percent of the total U.S. installed coal capacity, they play a significant role both economically and environmentally. The 20,000 MW in installed capacity is more than the installed U.S. biomass, geothermal and solar capacity combined. The annual fuel bill and the value of the power produced totals tens of billions of dollars.
Some of these smaller units are older, moderately sized and operated by major utilities solely for power generation. Others are newer, very small, and operated by industrial firms, governments or universities for both power and steam. Despite their considerable differences, most of these units share two characteristics. First, roughly 60 percent of the 20,000 MW is located in 14 states in the Upper Midwest and Great Lakes region (see Figure 3). Leading states include Michigan, Wisconsin, Iowa and Ohio. Second, most of these units provide significant site-specific benefits, especially steam and voltage support. Both of these characteristics are highly relevant to management decisions involving these units.
Unlike the larger units, the management alternatives for these small units are quite limited. Because of their locational benefits, shut down (and the use of replacement power) is often undesirable. In general, it is difficult to import steam, chilled water or transmission support. Because of their size and location, capital investments such as natural gas repowering, coal gasification and carbon sequestration aren’t generally viable. Even conversion to burning raw biomass may be difficult because of needed capital investment or site constraints. As a result, most of these units continue operating in the current coal-burning mode, despite considerable economic, environmental and social challenges. Operators of many of these units are under considerable pressure to act because of the high cost of fuel; ground-level pollution and other local concerns; and global warming.
One emerging solution involves turning crop wastes into biocoal, a potential direct replacement for coal fuel in small power plants.
The past and present of the U.S. electric power industry belongs largely to fossil fuels—and coal in particular. But by most accounts, the future belongs increasingly to renewables. EIA projects that renewables will constitute 40 percent of the growth in electricity generation through 2035, and other estimates are even higher.3 Among renewables, wind is currently dominant. Solar power seems to be favored for future growth despite its intermittency and cost issues. Geothermal power is also garnering increasing attention.
Biomass is one renewable resource that has received only a limited amount of attention, and not all of it positive. Most sources indicate that more than 500 million tons of biomass is produced sustainably each year in the United States (see Figure 4). This includes waste wood from forestry, municipal waste, and crop residues from agriculture.4 Someday, this biomass resource might be used to produce ethanol at a large scale. However, the dominant use of biomass for energy currently and in the near future is in power generation. When it comes to power generation, the 500 million tons in sustainable biomass could supply 30,000 to 40,000 MW of baseload capacity. This is a sizable fraction of the installed U.S. generation capacity, and is greater than the current U.S. operating base of all renewable power generation (excluding conventional hydro). Currently, there is well under 5,000 MW of operating biomass-based power generation.
To date, most of the limited attention paid to biomass has focused on wood. However, the dominant biomass resource isn’t wood, but is instead crop waste. The great bulk of this crop waste is corn stover and wheat straw. At over 200 million tons a year, crop waste alone represents a resource that could potentially fuel 15,000 MW or more of baseload power generation. And in many cases crop waste might be less controversial and more sustainable as a biomass resource than wood is. The resource estimate for available crop waste already reflects amounts needed for soil conditioning, livestock feed and other beneficial uses.
Interestingly, the majority of crop wastes are concentrated in the Great Lakes and Upper Midwest region—the same region with a majority of small coal units, as shown in Figure 3. This suggests a natural and remarkable match between the crop-waste supply and the small coal unit demand. For example, Iowa has an estimated 1,200 MW of small coal units, and an estimated 24 million tons of annual crop waste, enough to supply perhaps 2,000 MW of baseload generation. Minnesota has an estimated 1,000 MW of small coal units and an estimated 14 million tons of annual crop waste, enough to supply that same 1,000 MW of baseload generation. Ohio has an estimated 1,100 MW of small coal units and an estimated 5 million tons of annual crop waste, enough to supply perhaps 400 MW in baseload generation. The list goes on. On a state-by-state basis, there appears to be a reasonable match between the amount of small coal-unit capacity and the amount of available crop waste.
Of course, while transportation costs are a major issue, there’s little reason that all crop waste must be used within the state where it is generated. Taking a regional perspective, in the NERC ECAR, MAIN and MAPP regions, which overlap quite closely with this Upper Midwest and Great Lakes region, there’s an estimated 130 million tons of available crop waste at $5/MMBtu.5 This is enough to supply roughly 10,000 MW in baseload generation. The bottom line is that there appears to be sufficient crop waste biomass to fuel most if not all of the small coal units in this region.
However, while crop waste contains the necessary Btus of energy, the physical and chemical nature of raw biomass makes this apparent match far from perfect.
On the physical front, raw crop waste isn’t dense, and is therefore difficult and expensive to collect, transport and store. Crop waste is typically one-quarter to one-fifth as dense as coal. Crop waste also has relatively low calorific value, perhaps one-half to one-third that of coal. All told, crop waste produces perhaps one-tenth the energy of coal on a volume basis, and this hinders the potential for using crop-waste fuel in power plants. In addition to the volume issue, crop waste is relatively difficult to use as a boiler fuel. It isn’t uniform in size and doesn’t crumble or pulverize easily, making it unfit for many existing boilers.
On the chemical front, crop waste is highly variable in composition. This is a difficulty in itself since many existing boilers are designed for a narrow range of fuel specifications. To make matters worse, crop waste often has high levels of impurities that create combustion problems. The biggest issue is typically the presence of alkali metals that cause boiler fouling.
There are also a variety of non-technical factors that impede the use of crop waste for power generation, such as the difficulty in aggregating supplies from multiple parties and the absence of large, established vendors. But these non-technical factors could likely be overcome with suitable infrastructure and technology development. The physical and chemical properties of crop waste really represent the most important rate-limiting factors.
Fortunately, there is an emerging solution to many of the dilemmas posed by crop waste as a power-generation fuel—biocoal. Biocoal is a fuel produced from biomass whose physical and chemical properties have been changed so it looks and acts to a large degree like coal. It’s important to note that biocoal, as the term is being used here, isn’t simply densified biomass. Instead it’s a plug-and-play coal substitute.
Biocoal is produced from biomass with a combination of chemical and physical processing. Chemical processing is used primarily to remove impurities, while physical processing is used primarily to increase energy density. Crop-waste biocoal is simply coal made from crop waste.
Biocoal has physical and chemical properties that are much closer to coal than raw biomass, and can often be used in existing coal boilers with minimal or no modifications. It typically has a heat content (gross calorific value) of 3,500 to 4,500 kcal/kg (or 6,000 to 7,000 Btu/lb), similar to low grade coal.
Biocoal has only recently and partially emerged from the research stage, and the path to commercial biocoal production hasn’t been smooth. There have been numerous false starts and dead ends, but momentum now appears to be building—despite difficult economic conditions and uncertain environmental regulation. RWE, a major European utility, and Topell, a clean energy technology company, recently announced plans to build the world’s first biocoal plant, a 60,000 tons-per-year facility located in the Netherlands. And Global Bio-coal Energy reportedly is working to develop a 120,000 tons-per-year biocoal facility in Vancouver, Canada. Both of these plants are expected to rely primarily on wood waste, although their processes might be appropriate for a broader range of feedstocks including crop waste.
In the United States and elsewhere, considerable progress has been made specifically in crop-waste biocoal. In terms of R&D, extensive research is happening at organizations such as the Energy and Environmental Research Center in North Dakota. On the commercial side, startups and established firms are moving the technology past the R&D stage. For example, Xcel Energy funded extensive work by Bepex, a Minnesota chemical and physical processing firm, on the design of a commercial facility to produce biocoal from corn stover.
While cost estimates are difficult to obtain and remain uncertain, the incremental delivered cost of finished biocoal over raw biomass ranges from as little as $50/ton or $3/MMBtu to as much as $75/ton or $5/MMBtu. These figures likely will be reduced by as much as 50 percent over the next several years as the technology and infrastructure improves.
Given projected availability and price, biocoal could be catalyst for bridging the gap between the crop-waste biomass supply and the small-coal unit demand.
Economic and Environmental Benefits
The potential economic and environmental benefits of biocoal are best illustrated through a concrete example. This example is built on data obtained from public sources, including available reports on the Charter Street and Capitol generating units in Wisconsin. However, the example is illustrative and the analysis isn’t intended to represent any specific unit.
Consider a 10 MW older urban coal-fired power unit in the Upper Midwest or Great Lakes region that produces electricity, steam and chilled water. The unit has minimal environmental controls and thus produces a substantial amount of SO2, NOX and PM-10, along with CO2. Given emerging environmental and social issues, continued operation as an uncontrolled coal unit is no longer an option. Given the unit’s locational importance, shut down is only a remote consideration.
As with most such units, three alternatives are being examined. First, the existing coal boilers could be refurbished and modern environmental controls could be added. Second, the unit could be repowered with natural gas. Third, the unit could be repowered with raw biomass.
The capital required for the coal refurbishment alternative is estimated at $50 million, including $30 million in environmental controls. Coal prices have been unusually volatile over the past couple of years; a future cost of $5/MMBtu is assumed. This results in an annual fuel bill of roughly $16 million. The total cost, excluding any environmental adders, is estimated at approximately $28 million/year. With coal refurbishment, the unit will continue to emit 350,000 tons of CO2 per year. If two environmental adders are considered, one for CO2 and the other for RECs, the cost increases to $38 million/year.
The capital required for natural gas repowering is considerably higher than coal refurbishment. Of course, this depends a great deal on unit specifics, particularly site conditions and location. In this example, the cost is estimated at $100 million. Natural gas prices have been extremely volatile over the past few years with prices ranging from $3 to $12/MMBtu. In this example, natural gas going forward is assumed to cost $7/MMBtu—$2/MMBtu more than coal. This results in an annual fuel bill of roughly $22 million. The cost, again excluding environmental adders, is $43 million/year. With natural gas repowering, the unit will emit 140,000 tons of CO2 per year. If the two environmental adders are considered, the cost increases to $48 million/year.
The capital required for raw biomass repowering is also considerably higher than coal refurbishment. Again, this depends a great deal on site conditions. In this example, the cost is estimated at $150 million because of site constraints and the need for feedstock diversity. Given the illiquidity and newness of the biomass market, the cost of raw biomass is difficult to estimate. In this example, biomass going forward is assumed to cost $1/MMBtu less than coal. This results in an annual fuel bill of roughly $13 million. The cost, again excluding environmental adders, is $45 million/year. Unlike the coal and natural gas alternatives, this cost remains at $45 million/year even if the two environmental adders are considered.
Although the details and the precise figures will certainly vary, this example is quite representative of the situation for much of the 12,000 MW of small coal capacity in the Upper Midwest and Great Lakes region. On a straight economic basis and excluding environmental adders, coal remains the economic choice. Natural gas and raw biomass repowering are comparable and more expensive, with natural gas somewhat preferred. The choice between natural gas and biomass depends a great deal on judgment about the future prices of those two fuels, something that is a matter of considerable debate. If natural gas is readily available and remains inexpensive, it appears preferable to biomass. If biomass is readily available and natural gas rises in price, biomass is the most appropriate choice. When modest environmental adders are considered, the picture changes only slightly. Coal refurbishment remains the best economic choice, with biomass and natural gas repowering being moderately more expensive. Of course, these observations must be considered in light of the specific conditions at each site.
How does consideration of biocoal change this picture? This is illustrated in Figure 5 where three scenarios of biocoal economics are shown: low, base and high. The capital cost required for using biocoal is modest. In this example, boiler refurbishment will be required but environmental controls required are less extensive, largely for PM-10. SO2, NOX and Hg. The estimated cost is $25 million. In this example, three possibilities are included for the cost of biocoal. In the base case, biocoal is assumed to cost $4/MMBtu more than raw biomass. This is consistent with current estimates. The low case is $2/MMBtu, which is consistent with technological and infrastructure advances as well as short transportation distances. The high case is $6/MMBtu, which is associated with disappointing technological results and long transportation distances.
Biocoal has a major effect on the choice among alternatives. In the base case, the annual fuel bill is $25 million. The resulting cost of biocoal repowering is $32 million with or without environmental adders. Without environmental adders, biocoal is considerably less expensive than both natural gas and raw biomass repowering. It remains somewhat more expensive than coal itself. With even modest environmental adders, biocoal is now considerably cheaper than all three other alternatives by between $5 million and $15 million per year.
In the low case, the cost of biocoal repowering is $26 million. This figure is even lower than coal on a pure economic basis. With foreseeable technological advances, biocoal might be able to compete in some circumstances with coal on straight economics. In the high case, the cost of biocoal repowering is $39 million. Even in this case, biocoal repowering is preferred to natural gas and raw biomass repowering. Even with disappointing technological progress, biocoal might have an important role where environmental considerations are significant.
Based on this analysis, biocoal appears to have the potential for considerable economic and environmental benefit. In the absence of any environmental adders, biocoal conversion might save up to $2 million/year on a straight economic basis over the next best alternative—coal refurbishment. If environmental adders are considered, whether they are mandated or pursued voluntarily, the savings might be as high as $5 to $15 million/year or more over the other alternatives. And if biocoal conversion takes the place of coal refurbishment or natural gas repowering, CO2 emissions are reduced by between 150,000 and 300,000 tons per year.
The 12,000 MW of small coal units in the Upper Midwest and Great Lakes region are a modest but important piece of the United States energy and emissions picture. The alternatives for dealing with the economic and environmental challenges at these units are very limited. Crop-waste biocoal has the potential to change this situation substantially for the better. This resource could save on the order of $1 billion or more per year over the typical coal alternative on a pure economic basis, ignoring CO2 and REC considerations. If such environmental considerations are factored in, either voluntarily or through mandates, the savings could be billions of dollars over the typical natural gas and raw biomass alternatives.
Given these potential benefits, the role of crop-waste biocoal likely will increase in the natural course of events. Nevertheless, there are some strategy and policy changes could help accelerate this process and make it smoother.
First, the organizations responsible for managing these small coal units—private companies, academic institutions, and government agencies—should begin thinking more broadly about the available alternatives. In many cases, little attention is being paid to alternatives at these units. Where attention is being paid, wood-based biomass is sometimes considered but certainly not crop-waste biocoal. Given the time frames involved, it isn’t too early to change this mindset. Any evaluation of alternatives for these units should consider crop-waste biocoal.
Second, the organizations responsible for supplying fuel to these small coal units should begin thinking more broadly about the scope of their services. These businesses include coal companies, agricultural product companies, transportation companies and others involved in the fuel supply chain. All could play an important role in the crop-waste biocoal market, and many of them are just barely aware of its potential.
Third, the governmental agencies and non-profit organizations that represent consumers or the public at large should establish clearer and more favorable positions with respect to crop-waste biocoal. These positions are reflected both in regulations from state and federal regulatory agencies, as well as public relations and marketing messages from public interest groups. One good example of the need for clarification is the argument over biomass sustainability. It would help the market immensely if a suitable government agency or a non-profit organization assumed the task of certifying crop-waste biocoal (or other forms of biomass) as carbon neutral and green, where appropriate.
With these changes, the economic and environmental benefits of biocoal will arrive sooner rather than later.
1. EPA, “U.S. GHG Inventory 2010,” Environmental Protection Agency.
2. U.S. Energy Information Administration, “Existing Electric Generating Units in the United States,” U.S. Department of Energy, 2008.
3 Energy Information Administration, “Annual Energy Outlook 2010,” Department of Energy, May 11, 2010.
4. Milbrandt, A., A Geographic Perspective on the Current Biomass Resource Availability in the United States, NREL/TP-560-39181, December 2005.
5. Zia Haq, “Biomass for Electricity Generation,” EIA.