Representation of New Environmental Rules and Regulations

In Energy Information Administration (EIA) analyses, the reference case incorporates rules and regulations in place at the time of the preparation of the report. Rules or regulations that are not finalized, are in early stages of implementation (without specific guidelines), or are still being developed or debated are not represented. As an independent statistical and analytical agency, EIA does not take positions on how legislative or regulatory issues will be resolved or how rules or regulations will, or should, be implemented.

The reference case for this analysis excludes several potential environmental actions, such as new regulations affecting regional haze, for which States are developing implementation plans; the implementation of new National Ambient Air Quality Standards (NAAQS) for fine particulates, which is still being reviewed by the U.S. Environmental Protection Agency (EPA) and the courts; and the possible ratification of the Kyoto Protocol. In addition, no effort is made to predict the outcome of ongoing studies of the need to reduce power plant mercury emissions^a or the resolution of lawsuits against the owners of 32 coal-fired power plants accused of violating the Clean Air Act (CAA).

In June 1999, the EPA issued regulations to improve visibility (reduce regional haze) in 156 national parks and wilderness areas across the United States. It is expected that these rules will have an effect on power plants, but the degree to which they will be affected is not known. Power plant emissions of SO₂ and NO_x, which contribute to the formation of regional haze, may have to be reduced to improve visibility in some areas. The regulations call for States to establish goals and design plans for improving the visibility in affected areas; however, State implementation plans (SIPs) are not required until 2004 or later and therefore are not represented in this analysis, because they have not yet been promulgated.

The revised NAAQS, issued by the EPA in 1997, created a standard for fine particles smaller than 2.5 micrometers in diameter (PM_2.5). As with regional haze, power plant emissions of SO₂ and NO_x are a component of fine particulate emissions. At the request of the President (memorandum July 16, 1997), the EPA is now reviewing scientific data on fine particulate emissions to determine whether to revise or maintain the standard. The review is expected to be completed in 2002. If the standard is maintained, States will be required to submit plans to comply by 2005; however, the NAAQS for fine particulates has been challenged in court, and the resolution of the case is uncertain.

In December 1997, 160 countries met to negotiate binding limitations on greenhouse gas emissions for the developed nations. CO₂ emissions from fossil-fired power plants are a key component of greenhouse gas emissions. The developed nations agreed to limit their greenhouse gas emissions to 5 percent below the levels emitted in 1990, on average, between 2008 and 2012. The target for the United States is 7 percent below the 1990 emission level for all greenhouse gases. Reductions would be required if the U.S. Senate ratified the protocol. At this time, while 29 countries have ratified the protocol, none of the Annex I countries (the developed countries) has ratified the agreement. Various elements of the Protocol are still under negotiation.

The Clean Air Act Amendments of 1990 (CAAA90), Section 112(n)(1)(A), required that the EPA prepare a study of hazardous air emissions from steam generating units. The report was submitted to Congress on February 24, 1998. Its key finding was that Hg emissions from coal-fired power plants posed the greatest potential for harm. The EPA is now collecting and analyzing data on Hg emissions from specific power plants. The data, together with continuing studies on the health effects of mercury, will be used to determine the extent to which emissions need to be reduced. The EPA will be developing proposed regulations for reducing Hg emissions over the next 3 years.

On November 3, 1999, the Justice Department, on behalf of the EPA, filed suit against seven electric utility companies, accusing them of violating CAAA90 by not installing state-of-the-art emissions control equipment on their power plants when major modifications were made. CAAA90 requires that when major modifications are made to older power plants they must also be upgraded to comply with the emissions standards for new power plants. The EPA is arguing that the seven companies and the Tennessee Valley Authority made major modifications to 32 power plants but did not add the required emissions control equipment. At this time, one company, Tampa Electric, has settled the case by agreeing to make modifications to its power plants. The other cases have not been settled.

At the request of the Subcommittee four alternative reference cases with different assumptions about the outcome of the ongoing litigation were examined for this analysis. In the first New Source Review (NSR) case, it is assumed that the owners of each of the 32 plants against which the EPA has taken action will be required to add best available control technology to remove SO₂ and NO_x or retire the plant by 2005. In the second NSR alternative reference case it is assumed that all coal-fired plants that do not have flue gas desulfurization (FGD) or selective catalytic reduction (SCR) equipment will be forced to add controls or retire by 2010. The third and fourth NSR cases are the same as the first two, except that they include caps on power sector emissions of NO_x, SO₂, and CO₂. The model evaluates the economics of the retrofit versus retirement decision for each plant. The resolution of these issues could have an impact on future power plant emissions, especially SO₂ and NO_x emissions.

Readers should keep in mind that some of the projected actions and costs incurred to comply with the emissions caps analyzed in this report may also result from the other pending rules and regulations discussed above when they are finalized.

Projections in the reference case in this report are not statements of what will happen but of what might happen, given the assumptions and methodologies used. The reference projections are business-as-usual trend forecasts, given known technology, technological and demographic trends, and current laws and regulations. Thus, they provide a policy-neutral reference case that can be used to analyze policy initiatives. EIA does not propose, advocate, or speculate on future legislative and regulatory changes. All laws are assumed to remain as now enacted; however, the impacts of emerging regulatory changes, when defined, are reflected.

aOn December 15, 2000, the EPA announced that Hg emissions need to be reduced, and that regulations will be issued by 2004. 

Implementing Emission Caps: Cost and Price Impacts

When emission caps are imposed in the electricity sector, power suppliers can be expected to take actions to reduce those emissions. In some cases they will add emissions control equipment, such as flue gas desulfurization equipment to reduce SO₂ and selective catalytic reduction equipment to reduce NO_x emissions. Depending on the economics, they might also choose to retire some existing generating plants and replace them with plants that have lower emissions. For example, they might retire existing coal-fired plants and replace them with plants that use natural gas or renewable fuels to reduce CO₂ emissions. In turn, in response to price changes, consumers would be expected to reduce their consumption of electricity by increasing their use of non-electric appliances, changing their usage patterns for electric appliances, and investing in more efficient electricity-using equipment.

Each of these actions will have costs. For the power sector, there will be costs associated with increased investments in control equipment and new generating plants. There may also be higher costs associated with maintaining and operating new emission control equipment. Similarly, if new plants require more expensive fuel (i.e., natural gas rather than coal), total fuel costs would also be higher. There also could be costs associated with purchasing and holding emission allowances (or paying fees) on unabated emissions. The degree to which such costs are reflected in consumers’ electricity prices (inducing them to reduce their consumption of electricity) and the impact on the economy will be affected by numerous factors.

A variety of policy instruments may be used in efforts to reduce electricity sector emissions. Possible approaches include explicit emissions or technology standards for all generators, a fee on targeted emissions, and marketable (tradable) emission permits assigned or auctioned to generators based on historical emissions (grandfathering) or current year output (such as through the use of a generation performance standard). Each of these policy instruments has cost and price implications.^a

This analysis assumes a marketable emission permit approach modeled after the SO₂ allowance program created in CAAA90. It is assumed that emission permits or allowances would be provided to affected sources by the regulatory authority, and that the total number of allowances issued to all affected parties would be equal to the national target emissions cap. To be in compliance each year, the number of allowances held for each affected source would have to be equal to or larger than their emissions. Allowances held for an affected source that are not needed could be sold to others.

As allowances are bought and sold a market price will develop for them. Power suppliers will use this price to decide whether to reduce their emissions or purchase allowances to cover them. When deciding whether or not to operate a facility that produces emissions subject to a cap, the owner will include the market price of the allowance as part of the operating costs of the plant. As with fuel, operating the plant will consume an asset— the allowance—that could be sold if the plant were not operated.

The costs associated with the investment and operating decisions made by power suppliers to meet the emissions cap together with the costs of acquiring emission allowances will affect the market price for electricity. In competitive markets the generation price is based on the variable operating costs (what economists refer to as “marginal costs”) of the plant setting the market price at any given point in time. In other words, the running plant with the highest operating cost generally sets the market price for power. Typically, for fossil fuel plants, operating costs are dominated by fuel costs, with only a small portion coming from other operating and maintenance costs. If the costs of the plant setting the market price for power are increased by expenditures associated with running new pollution control equipment, using higher cost fuel, and/or purchasing allowances to cover its emissions, the competitive market price for power will reflect those costs. Thus, the total price impact of implementing the emission cap program will include changes in resource costs (i.e., higher operating and maintenance costs and higher fuel costs) together with the allowance purchase costs that raise the operating costs of the plants setting the market price.

While power markets^b in the United States are becoming increasingly competitive, they are not fully competitive today. In some areas of the country, prices are not set by the marginal costs of producing power. Rather, they are set by dividing the total costs (i.e., fuel costs, operating maintenance costs, capital recovery costs, and a regulated return on investment) by the amount of power sold. In such markets, the costs associated with adding emission control equipment, switching fuels, and building replacement plants to reduce emissions would be added to the aforementioned total costs and a new price would be derived. The treatment of allowance costs will depend on how they are allocated and whether the public service commission in a particular State requires costs (or profits) from allowance transactions to be recovered from (or returned to) customers or borne by shareholders. However, because of the increasing role played by wholesale power market transactions and the dominance of independent power producers (IPPs) in building new capacity this analysis assumes that allowance costs will be included in the operating costs of power producers in regulated markets.

It is expected that, even in regulated cost-of-service regions, IPPs will dominate new power plant additions, and because they will have to purchase allowances to cover their emissions, the allowance costs will be included in their competitively priced power contracts with utilities. In the latest data supplied to EIA, utilities reported plans to add 10,623 megawatts of capacity between 1999 and 2003. Over the same time period nonutilities reported plans to add 61,456 megawatts, or 85 percent of the total. As a result, in this analysis it is assumed that IPPs will build all new power plants and sell the electricity at market-based rates— which will include the costs of needed emission allowances.

If the pace of deregulation slows and electricity prices continue to be set on a cost-of-service basis, then assuming that allowance costs would be reflected in the operating costs of all plants with the targeted emissions may overstate the price impacts. The operating costs for existing regulated plants that received allowances at no cost would not include the opportunity costs of holding allowances.

aFor a discussion of the relative merits of alternative policy instruments, see Perman, Ma, and McGilvray, “Pollution Control Policy,” in Natural Resource and Environmental Economics (Addison Wesley Longman, 1996).
bThis discussion refers only to the generation sector of the electricity market. The transmission and distribution sectors are assumed to continue to price their services on a cost-of-service basis.

Impacts on the Rail Industry

In addition to the substantial contraction of the U.S. coal industry projected in the CO₂ cases for this analysis, the U.S. rail industry, which has about 200,000 employees and derives considerable revenues from coal shipments, also would be greatly affected. In 1999, 751 million tons of the 1,099 million tons of coal produced in the United States (68 percent) was transported to consumers partly or entirely by rail. Coal freight provided Class I railroads with $7.7 billion in revenues (1999 dollars), or 22 percent of all freight revenue earned. Coal freight car loadings and ton-miles tend to be dominated by a handful of railroads. For the major coal-hauling railroads, coal represented 38 percent of all carloadings during 1999. The average revenue received by Class I railroads for hauling coal was $10.31 per ton (1999 dollars).^a

The National Energy Modeling System does not project financial data for the rail industry in either the reference or analysis cases. On a qualitative basis, however, certain impacts are likely. Particularly in the cases that incorporate CO₂ caps, railroads and other shipping modes would be required to respond to reduced coal traffic and excess transportation capacity by making major, costly adjustments to routes, schedules, equipment, and employment levels. Decreases in coal traffic and increased competitive pressures would lead to lower freight rates and revenues. At the same time, the inefficiencies associated with the reduced scale of operation would increase unit costs of operation. Lower revenues, special charges, and increased unit costs would sharply reduce rail earnings until new sources of freight revenues were developed.

In this report, coal transportation rates, expressed in 1999 dollars per ton, are assumed to decline over time in response to productivity gains. They are also assumed to vary with fuel prices but otherwise to be invariant across cases despite reductions or increases in traffic along any given route. All modes of coal transportation have achieved significant efficiencies over the past 20 years and have been able to pass along a portion of the savings to shippers in the form of lower rates. New equipment, improved scheduling, maintenance, and operating procedures, and more efficient use of labor have reduced average revenues for coal shipments to 1.72 cents per ton-mile in 1998, nearly a 60-percent decline in real terms from 1981. In contrast, average rail revenues for shipments of transportation equipment and chemicals were 10.55 cents and 3.68 cents per ton-mile, respectively.^b Already intense interregional competition among coal producers seeking to offer the lowest possible delivered cost is another key factor that has helped to push coal transportation prices to lower levels. As a result, it would appear that reducing coal transportation rates at a faster rate to preserve markets would represent a major challenge to railroad managers.

Data published by the American Association of Railroads indicate that labor costs (wages, plus wage supplements) represent nearly 40 percent of total freight operating expenses plus fixed charges for all Class I railroads. Fuel costs, materials and supplies, and equipment rentals are assigned weights of 7 percent, 5 percent, and 11 percent respectively.^c Reductions in coal traffic that are not offset by increases in traffic for other commodities would be likely to lead to layoffs, reducing wage costs, and to the adoption of other measures to reduce operating costs. However, fixed charges such as depreciation, interest, and taxes would then be distributed over a smaller traffic base, placing upward pressure on rates. Replacing coal traffic with other commodities would be difficult. For example, in 1998 coal accounted for four times more carloads than either the second-place commodity, transportation equipment, or the third-place commodity, chemicals.^b Both commodities use shipping routes and equipment that are quite different from those for coal.

Progressively deregulated since the Staggers Rail Act of 1980, railroads have made substantial progress in improving productivity and reducing real costs by investing in new and more powerful locomotives, improved maintenance of main-line rights of way, and more efficient use of labor. A major contribution to achieving the joint goals of lower costs and maintenance of service has been made through a number of mergers over the past decade. Mergers have resulted in the emergence of four major railroad companies—two in the East (CSX and Norfolk-Southern) and two in the West (Burlington Northern-Santa Fe and Union Pacific-Southern Pacific). In 1999, Burlington Northern-Santa Fe received 23.2 percent of all commodity revenues from coal, and Union Pacific-Southern Pacific received 20.7 percent.^a

The adoption of CO₂ emission restrictions is projected to result in a reduction in domestic coal traffic handled by the railroads. As suggested by the results of the CO₂ cap and integrated cases in this analysis, reductions in coal traffic could range from moderate to severe. In all the cases with CO₂ caps assumed, western coal, particularly subbituminous coal from the Powder River Basin, is projected to be most severely restricted, because of its dependence on long-distance rail transportation to reach its markets in locations up to 2,000 miles away.

Because the CO₂ reduction cases analyzed in this study project heavier losses in coal production for western than for eastern coalfields, and because much of the production from western coalfields is shipped over long distances to midwestern and eastern markets to satisfy demand for low-sulfur fuel, it is likely that the burden of reduced coal transportation revenues would fall most heavily on railroads in the West—particularly on the Burlington-Northern and Union Pacific systems, which now include the St. Louis Southwestern, the Chicago & Northwestern, the Denver & Rio Grande Western, the Southern Pacific, and the Atchison, Topeka & Santa Fe railroads.

^aSource: Association of American Railroads, Freight Commodity Statistics.
^bSource: Association of American Railroads, “The Rail Transportation of Coal” (January 2000).
^cSource: Association of American Railroads, AAR Railroad Coal Indexes (September 2000).