Kentucky Resources Council, PO Box 1070, Frankfort, KY 40602 Phone [502] 875-2428

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PO Box 1070, Frankfort, KY 40602  Phone 502.875.2428, Fax 502.875.2845

KRC Participates In Panel Discussion on the future of coal In Kentucky  Posted: June 20, 2012

Kentucky’s Energy Future! Life Without Coal?
Kentucky Bar Association Annual Convention
June 6, 2012 Galt House Louisville
Tom FitzGerald, Director
Kentucky Resources Council

I. Current Kentucky Coal Production and Utilization (source, EIA)

Kentucky ranks third in the Nation in coal production. It accounts for about one-tenth of U.S. coal production and nearly one-fourth of U.S. production east of the Mississippi River.

Nearly one-third of all the coal mines in the Nation are found in Kentucky.

Coal-fired plants typically generate more than nine-tenths of the electricity produced in Kentucky.

Average blended price of electricity, in 2010, was 6.73 cents per kwH, making Kentucky the fourth-lowest, behind Idaho, Washington, and Wyoming. Blending the price tends to blur the trend in electricity costs by sector:

Residential rates have risen from 1990 to 2010 from 5.69 c/kwH to 8.57, with much of that increase coming after 2003, when rates were still at 5.81 c/kwH.

Commercial rates from 1990 – 2010 rose from 5.37 to 7.88, and industrial, from 3.58 to 5.05. The average blended rates rose from 4.48 in 1990 to the 2010 level of 6.73.

The emissions profile for electric generating units is, as of 2010:

Emissions (thousand metric tons) Ranking in Nation

Sulfur Dioxide 249 7
Nitrogen Oxide 85 7
Carbon Dioxide 93,160 7

As a function of efficiency of combustion relative to pollutant loading:

Sulfur Dioxide (lbs/MWh) 5.6 5
Nitrogen Oxide (lbs/MWh) 1.9 15
Carbon Dioxide (lbs/MWh) 2,091 3

II. Projections For Electricity Generation 2005-2035

The reference case trends projected by the EIA in installed electricity generation capacity during the period of 2005 – 2035 by fuel type, are these:

Natural Gas, a 1.3% increase in capacity from 316 gigawatts to 482.

Nontraditional shale gas and coalbed methane, 2.3% increase from 10.9 trillion cubic feet in 2008 to 19.8 in 2035.

Nuclear, a .4% increase from 100 gigawatts to 111 in 2035.

Coal, a 0.2% growth from 314 gigawatts to 334.

Liquids-fired, a .9% decrease from 121 down to 90 gigawatts.

Renewables, a 1.4% increase from 124 gigawatts in 2005 to 205 in 2035, with an 8.8% increase in solar during that period to 13 gigawatts.

Nationally, while coal accounted for 50% of the electricity generated in 2005, it is down to 45% in 2010, with nuclear remaining at around 20% of the generation, and increases in natural gas and renewables taking up the slack. In 2011, coal dropped to its lowest level of power generation in more than a decade, according to the U.S. Energy Information Administration (EIA). In fact, the EIA recently reported that coal’s share of U.S. electric power generation fell below 40% for the last two months of 2011, the lowest level since 1978.

III. What Are The Drivers In Determining The “Future of Coal?”

1. Market Forces

a. Production of natural gas from nontraditional sources, and drop in natural gas prices, and rising cost of coal. Natural gas prices are at a 10-year low, and projections are for those prices to drop even further, largely due to the production of shale gas.

b. Coal prices have increased significantly, with the EIA reporting the average price of Appalachian coal, up from $1.27 per million Btu in 2000 to $2.56 per million Btu in 2009, in part as a result of significant declines in mining productivity over the decade.

According to the EIA, this has substantially reduced the competitiveness of Appalachian coal with coal from other producing regions. Growing demand in Asia also has had an effect on coal pricing.

c. Growth in electricity demand has slowed, and is now projected to increase by less than 1% over the period of 2009-2035.

d. Renewables are becoming more affordable and their market share is increasing.

2. Regulatory “Drivers”

a. Changes In Air Pollution Standards

i. Mercury and Air Toxics Standards (MATS)

The MATS sets standards for all Hazardous Air Pollutants (HAPs) emitted by coal- and oil-fired Electrical Generating Units (EGUs) with a capacity of 25 megawatts or greater. Existing sources generally will have up to 4 years if they need it to comply with MATS. State permitting authorities may grant an additional year to achieve compliance.

Existing technologies are available to significantly reduce mercury and other HAPs, including Selective Catalytic Reduction (SCR )with Flue-gas Desulfurization (FGD), Activated Carbon Injection (ACI), ACI with Fabric Filter (FF) or Electrostatic Precipitators (ESP), for mercury, and fabric filters and electrostatic precipitators for non-mercury metals.

ii. Greenhouse Gas Controls

The failure of the Congress to enact comprehensive, multi-sector controls on emission of greenhouse gases, led the EPA to take regulatory action.

In the case of Massachusetts v. EPA, 549 U.S. 497 (2007), the Supreme Court found that greenhouse gases are air pollutants covered by the Clean Air Act, and directed the Administrator to determine whether or not emissions of greenhouse gases from new motor vehicles cause or contribute to air pollution which may reasonably be anticipated to endanger public health or welfare, or whether the science is too uncertain to make a reasoned decision. This so-called “endangerment finding” is required under section 202(a) of the Clean Air Act.

The endangerment finding was finalized on December 7, 2009.

On March 27, 2012, the Environmental Protection Agency (EPA) proposed a Carbon Pollution Standard for New Power Plants.

The proposal is limited to new fossil-fueled power plants, and not to existing or newly permitted plants that begin construction within a time certain. Fossil-fueled units would include boilers, integrated gasification-combined cycle (IGCC) units, and stationary combined cycle turbine units generating electricity for safe at a capacity of 25 megawatts or greater.

The proposed standards would exempt all existing fossil-fueled EGUs, even where they are modified in response to other air pollution controls. New power plant units that have permits and start construction within 12 months of this proposal would also be excluded, as would so-called “transitional” units that are part of a Department of Energy demonstration project. New units located in non‐continental areas, which include Hawaii and the Territories, and new units burning biomass alone are also exempt.

EPA projects that the output‐based standard of 1,000 pounds of CO2 per megawatt‐hour (lb CO2/MWh gross) can be met without new controls by new natural gas combined cycle (NGCC) power plant units, and that should be able to meet the nearly all (95%) of the NGCC units built recently (since 2005) would meet the standard.

According to the EPA, new power plants that are designed to use coal or petroleum coke would be able to incorporate meet the standard by incorporating technology to reduce carbon dioxide emissions to meet the standard, such as carbon capture and storage (CCS). Recognizing that such technology has not been deployed on any significant scale, the proposed regulations allow the source to choose two approaches to “averaging” emissions. New power plants that use CCS would have the option to use a 30‐year average of CO2 emissions to meet the proposed standard, rather than meeting the annual standard each year. Plants that install and operate CCS right away would have the flexibility to emit more CO2 in the early years as they learn how to best optimize the controls. A company could build a coal‐fired plant and add CCS later. For example, a new power plant could emit more CO2 for the first 10 years and then emit less for the next 20 years, as long as the average of those emissions met the standard.

According to the Massachusetts Institute of Technology Study The Future of Coal, (2007):

- The United States produced about 1.5 billion tons per year of CO2 from coal-burning power plants in 2006.

- If all of this CO2 is transported for sequestration, the quantity is equivalent to three times the weight and, under typical operating conditions, one-third of the annual volume of natural gas transported by the U.S. gas pipeline system.

- If 60% of the CO2 produced from U.S. coal-based power generation were to be captured and compressed to a liquid for geologic sequestration, its volume would about equal the total U.S. oil consumption of 20 million barrels per day.

- In 2006, the largest sequestration project was injecting one million tons/year of carbon dioxide (CO2) from the Sleipner gas field into a saline aquifer under the North Sea.

3. Other Regulatory Drivers

i. Renewable Portfolio Standards

44 states and the District of Columbia have adopted renewable portfolio standards (RPS), which require diversification of the generating portfolio of utilities to incorporate more renewable energy. See DSIRE, www.dsire.org A number have also developed tax policies and performance-based incentives (including feed-in-tariffs) to encourage investment in renewables.

ii. EPA Coal Ash Rule

On June 21, 2010, EPA proposed to regulate for the first time coal ash, to address the risks from the disposal of the wastes generated by electric utilities and independent power producers. The proposed rule provided two options for the management of coal ash: either listing the wastes as special wastes subject to regulation under subtitle C of RCRA, when destined for disposal in landfills or surface impoundments, or to regulate coal ash under subtitle D of RCRA, the section for non-hazardous wastes. The Agency considers each proposal to have its advantages and disadvantages, and includes benefits which should be considered in the public comment period.

4. Resource Availability Issues

One oft-repeated assumption is the existence of centuries of remaining coal reserves. Brian Keene of SmartPower recently wrote that we’re sitting on 500 years of coal. Hal Quinn, President of the National Mining Association, wrote recently that we have a 260-year supply of domestic coal.

A report of the National Academies of Science, entitled Coal: Research and Development to Support National Energy Policy, noted that the data upon which these assumptions are grounded may significantly overstate the amount of available reserves. The report noted that:

"Federal policy makers require accurate and complete estimates of national coal reserves to formulate coherent national energy policies. Despite significant uncertainties in existing reserve estimates, it is clear that there is sufficient coal at current rates of production to meet anticipated needs through 2030. Looking further into the future, there is probably sufficient coal to meet the nation’s needs for more than 100 years at current rates of consumption. However, it is not possible to confirm the often quoted assertion that there is a sufficient supply of coal for the next 250 years. A combination of increased rates of production with more detailed reserve analyses that take into account location, quality, recoverability, and transportation issues may substantially reduce the number of years of supply. Future policy will continue to be developed in the absence of accurate estimates until more detailed reserve analyses—which take into account the full suite of geographical, geological, economic, legal, and environmental characteristics—are completed.

Present estimates of coal reserves are based upon methods that have not been reviewed or revised since their inception in 1974, and much of the input data were compiled in the early 1970s. Recent programs to assess reserves in limited areas using updated methods indicate that only a small fraction of previously estimated reserves are actually minable reserves. Such findings emphasize the need for a reinvigorated coal reserve assessment program using modern methods and technologies to provide a sound basis for informed decision-making."

The summary noted the pivotal role that national and international action regarding climate change will play in the “future of coal,” echoing the conclusion of the MIT Study in concluding that:

"The context for any assessment of future coal production is inextricably linked with the development of a national carbon emissions policy. Potential constraints on greenhouse gas (especially CO2) emissions, and the technical and economic feasibility of CO2 control measures, are the dominant issues affecting the outlook for the future of coal use over the next 25 years and beyond. The difficulty of predicting the prices and availability of alternative energy sources for electric power generation provides additional uncertainty. Taking these factors into consideration, an assessment of forecasts for coal use indicates that over the next ten to fifteen years (until about 2020), coal production and use in the United States is projected to range from about 25 percent above to about 15 percent below 2004 levels, depending on economic conditions and environmental policies. By 2030, the range of projected coal energy use in the United States broadens considerably, from about 70 percent above to 50 percent below current levels. The higher values reflect scenarios with high oil and gas prices and no restrictions on carbon emissions. The lower values reflect scenarios with relatively strict limits on U.S. CO2 emissions, which cause coal use with sequestration to be more costly compared with other options for power generation."

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