The global economy is affecting our industry dramatically. Rising demand for oil and natural gas means that power generators and industrial plants will be desperate for basic feedstock that helps feed the American economy.
New technologies will be created and innovation in our industry will continue to grow, which will invariably lead to more inventive uses for coal. With the right incentives and under the proper market conditions, companies will introduce relevant products and services too meet these needs and demands. Without this type of thinking in the energy sector — where the ever-increasing demand for power and gas is tapping the availability of vital fuels and putting upward pressure on prices, it will result in dire consequences to the global economy.
As we all know, natural gas is a finite resource, which at the current rate of production and consumption would last about 60 more years in the United States. We also must face the fact that developing nations will expand and demand more of the world’s oil and natural gas to fuel their growth. Since the U.S. comprises approximately five percent of the world population but uses about 30 percent of the energy, it is inevitable for that balance to shift, especially in light of the shift in manufacturing capacity to overseas markets.
With India and China seeking the same resources as the United States, costs for these commodities will rise. For instance, the U.S. Energy Information Administration (EIA) projects oil consumption to increase by 1/3 through 2030 while electricity demand will rise by 50 percent over the next decade. Some experts predict this will lead to oil that may cost as much as $100 a barrel while natural gas could run as high as $8+ per million BTUs, in the same time period.
As oil prices rise, it usually causes other commodities such as natural gas and coal to rise as well, generally at a lesser rate than oil. Coal typically rises at a rate of 40% of that of oil, making it the cheapest and most abundant alternative to oil, which would explain why the EIA projects its use to climb over the next two decades and does not expect nuclear or renewable energy to reduce coal’s market share during this time.
There are solutions to the increasing demand for energy, and include several which use coal as its feed stock. Coal-to-liquids, is one in which coal is broken down to form a fuel oil. While potentially much cheaper per barrel than oil, it is capital intensive and requires that oil prices stay high to motivate investors to risk this capital. Coal gasification plants are another technology we have seen in the limelight in our industry. These are power facilities that clean the impurities from coal before it is burned and sent out the smokestack, or in most recent developments (mimicking a DOE project from the 70’s), creating pipeline quality natural gas (PQNG).
When coal is burned, it produces sulfur dioxide and nitrogen oxide, which produces acid rain and smog. In addition it produces particulate matter and mercury. Under the Clean Air Act, those pollutants must be removed from exhaust gases that come out of the smoke stack. Coal combustion also produces carbon dioxide, which is not currently regulated. However the pressure to do so is increasing.
Coal gasification removes the sulfur dioxide, mercury and carbon dioxide from the “syngas” before it is combusted or converted to PQNG, say experts. And because the “syngas” is cleaner than raw coal, lower quantities of nitrogen oxide and particulate matter are produced during the combustion process. The carbon dioxide is more concentrated, which makes it easier to capture.
Four coal gasification power plants are now operating: two in the United States and two in Europe. American Electric Power expects to have engineering studies completed next month on two possible coal gasification plants in Ohio and West Virginia. It would like to have one or both facilities operational by decade’s end. Duke Energy has picked up Cinergy’s proposed coal gasification plant in Ohio, since the merger of the two organizations.
There are viable options to help reduce the global dependence on oil and natural gas. Employing energy efficient technologies is a good start as well as turning waste energy into power and heat.
To keep the global economy viable, creative solutions involving all different fuel forms are necessary. Coal will continue to play a major role, however the form of that role appears to be changing. New technologies are on the verge of becoming commercially commonplace, and those utilities who utilize the traditional combustion method must commit to controlling their emissions and their carbon footprints. Regulatory and market pressures are giving coal a chance to reinvent itself, and with oil and gas prices at their current levels, and no major relief in site, the bulk of the new power required will likely be provided using coal, the workhorse of the industry.
Coal is not without its problems. Eastern spot prices for coal have risen, and have reached their highest levels in more than 25 years. This is the second time in 4 years that coal prices have more than doubled their pre-2000 pricing levels . This spike has caused prices in new long term contracts to rise as well. The current prolonged spike in Eastern spot prices is mainly due to supply shortages, as demand has not grown much in recent years.
There are several reasons that coal prices have spiked. The coal industry has undergone significant consolidation over the past 15 years, with indications pointing to a continuation in that trend. The top ten producers controlled 64% of coal production in the U.S. in 2003, compared to only 36% in 1989. Three companies control 60-70% of production in the Powder River Basin, Northern Appalachia, and Colorado/Utah. This consolidation has contributed to the volatility of spot prices by reducing excess mining capacity along with the number competing for coal contracts.
The reduction in the number of small mines has affected the price of coal in recent years as well. An example of this is a 68% reduction in the number of small mines in Central Appalachia from 1989 to 2003. By reducing the number of small mines, the ability to meet spikes in demand are reduced, resulting in price spikes in the spot market.
There are other factors contributing to rising coal prices; including increase in demand, even though over the last 5 years the increase has been small. Other contributing factors are the reduction in the size of U.S. utility coal stockpiles, the reduction in miner productivity in all of the major coal producing regions (except Northern Appalachia), pressure from U.S. export coal demand, and the reduction decrease in the number of Class 1 railroads.
With spot market coal prices increasing, where do the opportunities for coal exist? They exist with integrated coal gasification combined cycle plants. Gasification, also known as partial oxidation, has been commercially practiced for many years; especially in the chemical industry, where most of the installed plants produce ammonia, hydrogen or other chemicals. The feedstock for these plants has included natural gas, oil-derived fuels, petroleum coke and coal. Integrated Gasification Combined Cycle (IGCC) is often proposed as an alternate method of converting environmentally disadvantaged fuels into electricity. Some believe that IGCC units will not be built in the short term unless natural gas prices remain elevated, there is high load growth and a national cap on CO2 emissions are implemented. However, with the arrival of the Clean Air Interstate Rule (CAIR) and the Clean Air Mercury Rule , and the availability of high sulfur (i.e. 7 lb. /MMBtu) coal, such as Illinois Basin coal, (See Figure 2) the market for these fuels rests on a technology like IGCC and other gasification processes, which benefit from high sulfur content and which reduce emissions simultaneously. The technology’s main long-term advantage is its ability to control greenhouse gas emissions. Integrated gasification combined cycle technology, combined with the sequestration of carbon stripped out in the process, is as close to a perfect solution for environmental emissions as there is. The biggest challenge will be to make it a reality, in light of the costs to develop gasification projects and their financial ramifications.
Gasification technology, although new to the power sector, has been widely used in the chemical industry for decades. Almost ten years ago, Tampa Electric opened an innovative power plant that turned coal, the most abundant but the dirtiest fossil fuel, into a relatively clean gas, which it burns to generate electricity. The plant emitted significantly less pollution than a conventional coal-fired power plant, and it was also 10 percent more efficient.
Though there are many gasification plants currently on the drawing board, since that plant opened, however, no other similar plant has been built in the United States, mainly due to the price of constructing such a plant, (about 20% more expensive than to build a conventional pulverized coal unit) and to the abundant supply of natural gas, which had been, until recently, a lot cheaper.
In recent years there has been downward pressure on that price differential. GE Energy, a division of General Electric claims the technology offers operational cost savings that offset some of the higher construction costs. In addition, if Congress eventually limits carbon emissions, as many energy industry experts say they expect them to do, the technology’s operational advantages could make it a bargain.
There are now several utility executives who are proponents of gasification, because they assume a carbon constrained world is inevitable. Duke/PSI, Bechtel, and General Electric Company have signed a letter of intent to study the feasibility of constructing a commercial, integrated gasification combined cycle (IGCC) generating station. This is the first plant of its kind announced under a GE-Bechtel alliance. However other projects utilizing this same alliance are close behind.
The operating savings for IGCC plants result from a number of factors, including more efficient combustion (15 percent more than conventional plants do, resulting in less fuel consumption). The plants also use about 40 percent less water than conventional coal plants, a significant consideration in arid locales, and given the increasing difficulty of securing water rights.
Many in the industry who anticipate stricter pollution limits believe the primary selling point of IGCC plants is their ability to chemically strip pollutants from gasified coal more efficiently and cost-effectively, prior to burning, rather than trying to clean the emissions on the back end.
Supporters of the technology believe that half of coal’s pollutants – including sulfur dioxide and nitrogen oxides, which contribute to acid rain and smog – can be chemically stripped out before combustion. So can about 95 percent of the mercury in coal, at about a tenth the cost of trying to scrub it from exhaust gases racing up a smokestack.
The biggest long-term draw for gasification technology is its ability to capture carbon before combustion. If greenhouse-gas limits are enacted, that job will be much harder and more expensive to do with conventional coal-fired plants. It is estimated that capturing carbon would add about 25 percent to the cost of electricity from a combined-cycle plant burning gasified coal, but that it would add 70 percent to the price of power from conventional plants.
Disposing of the carbon dioxide gas stripped out in the process, however, is another matter. Government laboratories have experimented with dissolving the gas in saline aquifers or pumping it into geologic formations under the sea. The petroleum industry has long injected carbon dioxide into oil fields to help push more crude to the surface. Refining and commercializing these techniques is a significant part of a $35 billion package of clean energy incentives that the National Commission on Energy Policy is recommending.
The recent energy bill has some incentives for industry to adopt gasification technology, and the Department of Energy will continue related efforts. These include FutureGen, a $950 million project to demonstrate gasification’s full potential – not just for power plants but as a source of low-carbon liquid fuels for cars and trucks as well, and, further out, as a source of hydrogen fuel.
The Integrated Gasification Combined Cycle Process
In the IGCC process, coal or another carbon containing material (petroleum coke, coal fines, and residual oil) is converted to synthetic gas, composed mainly of carbon monoxide and hydrogen, which is cooled, cleaned and fired in a gas turbine. Next the gas turbine generates hot exhaust that passes through a generator to produce steam to power a steam turbine, whereby electricity is produced by both the gas and steam turbine-generators.
The feedstock is prepared and fed to the gasifier in either dry or slurried form. The feedstock reacts in the gasifier with steam and oxygen at high temperature and pressure in a reducing (oxygen starved) environment. This produces the synthesis gas, or syngas, made up of more than 85% carbon monoxide and hydrogen by volume, and smaller quantities of carbon dioxide and methane.
Coal gasification is a chemical process that removes potentially harmful matter such as sulfur and volatile mercury from the synthesis gas before combustion, when they are much easier and less expensive to remove. Non-volatile heavy metals can be removed in a non-leachable slag which can be usable in construction and building industries, becoming a potential added revenue stream for such a plant. The removal occurs because of the high temperature in the gasifier, and results in inorganic materials such as ash and metals into the vitrified slag material, resembling course sand. With some feedstocks, valuable metals are concentrated and recovered for reuse. The synthesis gas that is produced is much cleaner than raw coal, so it produces lower quantities of particulate matter and nitrogen oxides when it goes through the combustion process.
IGCC vs. Coal Combustion
There is a dramatic difference in the level of pollution reduction when comparing an IGCC facility to that of a traditional pulverized coal plant. A pulverized coal plant produces flue gas and flyash which compose the majority of the pollutants from the coal. Though the flue gases can be cleaned using current technology, which is capable of removing a large portion of the pollutants, it is not without cost, and those costs can be prohibitive.
Gasification on the other hand removes these pollutants more effectively and efficiently, without producing the additional wastes that the coal combustion process does, such as additional carbon dioxide, and sludges that contain sulfur (up to 5 lbs./lb. of sulfur removed). The removal of volatile mercury and carbon dioxide is a much more expensive process in traditional combustion plants, and it appears that this requirement will soon be looming over the industry, due to continued environmental constraints. To remove high levels of mercury from a coal combustion plant, it requires the injection and removal of powdered activated carbon, and the success depends heavily on the coal feedstock and other pollution control equipment
An Example of the levels emissions from an IGCC plant compared to a supercritical pulverized coal plant (SCPC) is in Table 1.
Pounds of Pollutants per MWh
Pollutant IGCC SCPC
SO2 0.47 1.19
NOx 0.50 0.72
PM-10 0.06 0.16
Pollutant IGCC SCPC
Hg (Volatile Mercury) >90% Removed 30-80% Removed
Source: Eastman Gasification Services
1) Assumes Eastern bituminous coal with 2.2% sulfur
2) For IGCC, NOX is corrected to 15% O2, For SCPC NOX is corrected to 6% O2
3) Assumes IGCC plant is equipped with an amine scrubber, packed activated carbon bed for Hg, and no SCR
4) Assumes SCPC plant is equipped with wet flue desulfurization
The levels of pollutants for an IGCC can achieve additional reductions from those shown in Table 1, by using enhanced sulfur removal technologies such as Rectisol.
IGCC Economics & Financing
One of the hottest topics in the industry these days is coal gasification and IGCC. At recent industry conferences, the coal gasification sessions were standing room only. Commercial banks are interested in the topic as well, but not without reservations. The attraction is the potentially lucrative offtake agreements from such a project. Depending on where the plant is situated, as much as 30 percent of a project’s revenues can come from non-electricity production, for such things as hydrogen, nitrogen, sulfur and carbon sequestration.
One of the biggest problems with the growth of IGCC in the past is that the turbines and the gasification equipment came from different vendors, and no one wanted to guarantee the whole package, since there were uncertainties related to the other’s equipment. In 2003, Eastman Chemical Company’s Eastman Gasification Services Company signed a cooperative agreement with ChevronTexaco under which Eastman was to provide operations, maintenance, management and technical services to ChevronTexaco projects. In 2004, GE acquired the Chevron-Texaco gasification technology, and has paired that up with their existing turbine business, with guarantees around both. In addition they have partnered with Bechtel in a consortium, in order to construct the plants. Eastman Gasification continues to be prepared to provide their services to these projects. All these collaborative efforts help lend credibility and financability to these projects, by helping to eliminate the technology’s risk.
The total cost associated with building an IGCC facility is around $1 billion+, with some industry experts claiming that the technology costs 20% more than a pulverized coal plant. Without substantial federal and state subsidies, the future of IGCC technology is considered by some to be dim. In addition, credit ratings may be at stake for utilities, making airtight commitments with regulators a necessity, in order to avoid negative rating action. Strategies to manage the financial and regulatory risks will have to be in place to help insure this.
According to Eastman Gasification Services Company however, the capital costs for new coal gasification power plants are now estimated to be at parity with the newest generation of pulverized coal power plants. The capital costs for pulverized coal plants have risen in recent years and are projected to continue in that direction, due to the increasing severity of federal air pollution regulations. With coal gasification, there are fewer environmental side effects, and it is predicted that the costs will actually head downward as commercialization of the technology moves forward, improvements are incorporated into future designs and increased operating experience is realized.
Solid fuel plants have been recently bid for less than $1,000/kW on a turnkey basis, which is 30-40% of the cost of the first few IGCC plants. Since then, capital cost reductions have been achieved through gas turbine performance improvements, gasification system enhancements, IGCC configuration changes, and finally by moving further down the learning curve in the EPC process that has provided additional efficiencies. An example of configurations changes that have reduced costs is GE’s coupling of a 9FA based combined cycle with high efficiency quench (HEQ) which resulted in a 10% reduction in costs of electricity. The reduction was due to a large portion of the high temperature heat exchanger in the gasification plant being eliminated. GE’s next generation of gas turbines, such as the GE “H” machine, are expected to provide significant performance improvements and capital cost reductions. These types of improvements will continue to provide additional economic benefits for IGCC. The capital cost of an IGCC plant is estimated to be between $1,200 to $1,400/kW and is expected to go down from there. This range is competitive with the newest generation of supercritical pulverized-coal plants
When you consider total variable costs for a coal gasification plant versus any other fossil fuel based electric power generating facility, (including natural gas) O&M, fuel, waste disposal, and byproducts credits, they are much better with coal gasification. This is a result of the higher O&M costs of coal gasification being offset by lower fuel costs from higher efficiency, lower environmental treatment costs, and lower waste disposal costs. In addition, with the production of marketable by-products such as hydrogen, nitrogen, and sulfur, additional revenue streams can be provided. Finally, with the looming Clean Air Mercury Rule limiting the emissions from new power plants, and expected carbon removal requirements likely being instituted in the future, the costs for removal of these constituents has to be considered, and it is much less for gasification than other technologies.
With gas prices increasing to their current levels, the ownership cost of an IGCC has become competitive with that of conventional, natural gas-fired combined cycle plants. The range that this remains true is when natural gas rises above $4/mmBtu. Most forecasts of long range gas prices indicate that gas will be above this level for the foreseeable future.
State & Federal Incentives for Development
The Clean Coal Power Initiative (CCPI) is the President’s response to the National Energy Policy recommendations for developing advanced clean coal technologies to ensure clean, reliable, and affordable electricity for the future of the U.S. CCPI is a ten year, $2 Billion DOE program involving multiple solicitations for coal-based power generation technologies that significantly enhance efficiency, environmental performance, or economics relative to state-of-the-art technologies. The purpose of the program is to try to accelerate the implementation of these new advanced technologies through demonstration at the commercial-scale level. They require 50% cost sharing by industry participants.
Many states, whose coal industries have been dramatically affected by environmental laws requiring reductions in sulfur, have implemented various incentives, including grants and tax abatement, in order to encourage the use of coal mined in their state. States whose resources include high sulfur coal, such as that found in Illinois, western Indiana and Kentucky, Ohio and various areas in Appalachia have borne the brunt of the job losses in the coal industry, and have seen the market for their coal being dramatically reduced. Many of these states are anxious to put these mines back in business and their unemployed miners back to work. The incentives were put in place to do that, and many of these incentives are specifically focused on IGCC, in order to spur development, while acknowledging the concerns of environmentalists.
Early in 2005, clean energy legislation unanimously passed out of the Indiana Senate which provides additional incentives for clean coal gasification plants. Senate Bill 378 provides tax credits for companies who build and operate integrated coal gasification power plants in Indiana. The legislation established the Coal Gasification Technology Investment Tax Credit, which applies to newly constructed IGCC plants that exclusively use Indiana coal. The amount of the tax credit would equal 10 percent of a $500 million investment plus 5 percent of the investment above that amount. The tax credit would be divided over a ten year period.
In April 2005, Indiana’s General Assembly passed tax incentives that would save Duke $75 million on a $1 billion IGCC plant that they are considering building in a cooperative arrangement with GE/Bechtel, if it were powered with coal from Indiana’s mines.
In 2002 Indiana’s governor signed a clean-coal law, whereby electric utilities either building new generating stations or repowering existing power plants using Illinois Basin coal are eligible for potential financial incentives including up to 3% over their normal rate of return. The Indiana Utility Regulatory Commission (IURC) determines the actual level of incentives to be awarded on a case-by-case basis.
Since 1987, coal consumption in Indiana has increased by 30 percent, while Indiana’s coal production had increased by only 3 percent. Currently over half of the 43 million tons of coal used to generate electricity is imported into Indiana. If Indiana coal were to replace 22.5 million tons of the now imported coal, it would add $1.35 billion and 18,000 jobs to that state’s economy. Therefore it is obvious why the state has implemented these incentives.
West Virginia, through using coal as its premier electric generating source material, receives $13.1 to $17.3 billion of annual economic output, $4.1 to $5.6 billion of annual household income; and 111,747 to 162,143 jobs. Taken a step further, coal is responsible for $66 to $114 billion of annual state economic output, $38 to $55 billion of annual household income and 1.1 to 1.7 million jobs, across the entire Southern Appalachian region. In other words, coal is a huge part of their economy, and it is likely to negotiate incentives to use some of their high sulfur coal
The Kentucky Coal Association (KCA) has declared that economic incentives to promote Kentucky coal are a priority for the 2006 legislative session and during the interim committee meetings. KCA has helped pass legislation in the past including severance tax credits for thin seam coal and incentives for utilities to burn Kentucky coal, so it is a reasonable expectation that they will be successful in putting incentives in place.
Numerous governmental programs exist in Kentucky that might benefit an IGCC facility. These include:
-Enterprise zone programs
-Tax increment financing
-Job assessment fee
-Industrial revenue bonds
The Ohio Coal Development Office (OCDO), within the Ohio Air Quality Development Authority (OAQDA), co-funds the development and implementation of technologies that can use Ohio’s vast reserves of high sulfur coal in an economical, environmentally sound manner. Ohio generates nearly 90 percent of its electricity from coal and is the third largest consumer of coal and the fourth largest consumer of electricity in the U.S.
Projects supported by the OCDO are sought through public solicitations and requests-for-proposals and cost-share is required. Proposals are reviewed by independent technical reviewers, and then submitted to the Office’s statutorily created Technical Advisory Committee (TAC), a 15-member group comprised of public and private members having an interest in coal, power production, and the environment. Projects favorably recommended by the TAC are submitted to the OAQDA for final approval, then grant negotiations commence.
Illinois has an extensive program in place to provide incentives to those willing to use high sulfur Illinois Coal which will put unemployed miners back to work. In recent years, the State of Illinois passed the Coal Development Act, which has the following provisions:
-Provides $3.5 billion in bonds for coal and energy projects under a consolidated Illinois State Finance Authority
-Allows sales and utility tax exemptions for new power plant construction started after July 1, 2001
-Gives property tax breaks of up to $4 million over 10 years for new power plants and transmission lines
-Orders the Governor Energy Cabinet to help develop clean-coal technology, help power companies gain required permits more quickly and look into creating a transmission corridor from the south to the north part of the State
-Calls for the IEPA to start investigating more limits on SO2, NO2, mercury, and CO2
The Department of Commerce and Economic Opportunity has pushed coal infrastructure grants through its Office of Coal Development and Marketing (OCDM). The coal infrastructure grants aim to increase domestic and international use of Illinois coal. The Illinois Clean Coal Review Board, established by Southern Illinois University and funded initially by monies from the sale of power plants of Commonwealth Edison Company, provides grants to innovative technologies seeking to increase utilization of Illinois coal resources.
In Illinois, programs that might benefit an IGCC generation facility include:
-Enterprise zone programs
-Temporary property tax relief
-Tax increment financing
-Development corporation loan program
-Community development assistance program
-Work force development program
-Community block grant program
-Linked deposit program
With the costs of BTU’s on the rise across the board, including not only natural gas and crude oil, but coal as well, the overall challenge in the energy business today comes down to replacing a higher cost Btu with a lower cost and being able to finance the cost differential. To do so means the banks and financial community have to believe that the spread will remain great enough between the sources for the life of the project, or mechanisms must be in place to protect these investments.
With recent advances in IGCC technology and development, including the ability of these facilities to burn high sulfur coal, such as that found in the Illinois Coal Basin and other high sulfur coal reserves, while meeting or exceeding all necessary environmental regulations, Gasification became a viable source of energy. Coupling those advances with public and governmental support of the technology by way of loans, grants and tax abatement, the bundling of the turbine provider with the gasifier so that they can wrap the guarantees, and improvements in operations, Integrated Gasification Combined Cycle technology is likely to become the solution to the looming domestic energy needs of the United States.
These improvements have opened the door to development of new IGCC generation facilities, such as the one by Duke, AEP, Southern Company, Exelsior Energy, Steelhead Energy, etc. However, an investigation of the transmission, fuel, and water availability, as well as, an understanding of the environmental and stakeholder issues is still critical to the identification and development of attractive sites, just as with any power plant option would require. As we have seen, these pieces can fit together in numerous ways highlighting the existence of numerous attractive sites in the Illinois Coal Basin and elsewhere in high sulfur coal territory, where there is potential to negotiate long term coal contracts for coal whose demand isn’t as high as it once was. Many believe the coal in this region will some day be the center of a huge energy complex for the U.S. Furthermore, with the increase in gasification projects that gasify coal and convert it to either PQNG, ultra-clean diesel or other liquid fuels, gasification is becoming closer and closer to being a commercial reality. Some of these gasification projects are even looking to partner with renewable energy technologies in order to achieve additional economies and convert non-dispatchable power to a dispatchable source by combining the technologies.
There is still a capital cost premium for gasification. In the interim (approximately 3-5 years), before commercialization, operation improvements and/or new environmental regulations narrow the price differential gap of gasification’s capital costs as compared to those of other technologies, incentives provided by both state and federal sources, coupled with long term contracts for the high sulfur coal and the use of hedging strategies, will be the way the first wave of gasification plants will get built. In the near term, these projects may be able to achieve the required economics through the sale of various byproducts, such as enhanced oil recovery, sulfur, and other chemicals.