program, under which the EPA would issue NO, emission allowances to power plant operators and other large sources. Each allowance would permit the holder to emit one ton of NO, and could either be used for the facility to which it was originally allocated or sold.

As with the sulfur dioxide (SO2) allowance program created by CAAA90, the goal of the NOx cap and trade program would be to reduce compliance costs through efficient market mechanisms. The program is meant to encourage reductions in NO, emissions from facilities where they can be made relatively inexpensively, while providing the option of allowance purchases for facilities where the costs of reducing emissions would be higher.

Power plant operators have several options for reducing NOx emissions, including low-NO, burners, other combustion controls (flue gas recirculation, staged combustion, reduced oxygen, etc.), selective noncatalytic reduction (SNCR), and selective catalytic reduction (SCR). In addition, co-firing a coal plant with natural gas is also an option. In general, combustion controls (including low-NOx burners) are relatively inexpensive and reduce uncontrolled NOx emissions by 40 to 50 percent. In contrast, SNCR and SCR technologies are more expensive, but they reduce NOx emissions by 60 to 80 percent. The option chosen for each plant will depend on its uncontrolled emission rate, boiler type, size, and operational economics.

In the AEO99 reference case, a mix of options is chosen. By 2020, combustion controls alone are expected to be added to 10 gigawatts of capacity, SNCR units to 96 gigawatts, and SCR units to 111 gigawatts. The annualized cost of the control technologies is projected at $2 billion-very small in comparison with the approximately $200 billion that consumers spend annually on electricity purchases. However, many of the same units expected to add NOx reduction equipment, primarily coal steam plants, would also be affected if efforts to reduce carbon emissions were undertaken in the future. It may be economical to add NOx control equipment to such units now, but the addition of carbon reduction requirements could make retirement a more attractive option for many units. A recent EIA study [9] found that U.S. efforts to meet the carbon reduction targets of the Kyoto Protocol

Legislation and Regulations

could result in the retirement of many coal-fired power plants.

Mercury Emissions Data Collection

CAAA90, Section 112(n)(1)(A), required that the EPA prepare a study of hazardous air pollutants from steam generating units. A report on the results of the study was submitted to Congress on February 24, 1998. The key finding was that mercury emissions from coal-fired power plants posed the greatest potential for harm. The levels of mercury concentration in air or water were not found to be a problem; however, it was found that mercury can accumulate in some fish species, making them dangerous to consume in large amounts.

The role of mercury emissions from particular coalfired power plants in the process is not clear, and the EPA has decided to collect additional data from power plant operators before determining whether their mercury emissions should be regulated. The draft data collection plan states that, beginning on January 1, 1999, the owners of coal-fired power plants 25 megawatts or larger will be required to collect weekly data on the mercury contents of the coal used and the stack emissions and to submit the data to the EPA quarterly. After collecting the data for 1 year, the EPA will determine whether mercury emissions regulations are needed.

National Ambient Air Quality
Particulate Standard

AEO99 does not include the new fine particulate standard proposed in the EPA's revised National Ambient Air Quality Standards (NAAQS). The NAAQS created a new standard for fine particles, smaller than 2.5 micrometers in diameter (PM2.5). The new health-based standard sets the exceedance limits for PM2.5 at a 3-year annual arithmetic mean of 15 micrograms per cubic meter (μg/m3) and a 24 hour standard of 65 μg/m3 (99th percentile of concentrations in a year averaged over 3 years). The EPA is required to take several steps, however, before the standard can be enforced.

In a memorandum dated July 16, 1997, the President directed the EPA to determine within the next 5 years, based on review of scientific data, whether to revise or maintain the proposed standard. Thus, final standards will not be issued

Legislation and Regulations

until July 2002, at the earliest. The States will then be given 3 years to develop plans to come into compliance and will have up to 10 years to reach the required concentration levels. As a result, without any changes, the earliest full compliance date would be 2015. As the data review progresses and compliance approaches begin to take shape, the fine particle standard may be included in future AEOS.

Hazardous Air Pollutant Standards

During 1998 the EPA proposed two new sets of national emissions standards for hazardous air pollutants (NESHAPs) under the authority of the Clean Air Act. The first proposed NESHAP would limit emissions of hazardous air pollutants (HAPS) from oil and natural gas production and natural gas transmission and storage facilities. The EPA has determined that such oil and gas facilities emit HAPS including benzene, toluene, ethyl benzene, mixed xylenes, and n-hexane.

The EPA expects the proposed NESHAP to reduce HAP emissions from oil and gas production by 57 percent and from natural gas transmission and storage by 36 percent [10]. The proposed NESHAP would require the installation of Maximum Achievable Control Technology (MACT) at more than 400 facilities involved in the production of oil and natural gas and the transmission and storage of natural gas. Another 500 production facilities may be required to install less stringent controls. The rule was proposed in February 1998 and is expected to be finalized in mid-1999 [11].

A second NESHAP, proposed in September 1998, would require petroleum refineries to reduce HAPS from process vents on catalytic cracking, catalytic reforming, and sulfur plant units. NESHAPs for other refinery processing units were set in August 1995 but did not include standards for these three processes. NESHAPS for the additional processes were recently proposed, because the EPA determined that they can be expected to emit a number of HAPS. The proposed standards are specifically aimed at reducing emissions of organics, sulfur compounds, inorganics, and particulate metals. The EPA estimates that refiners would invest approximately $173 million for the required MACT control equipment and about $43 million a year for related maintenance [12]. Potential changes that would be

associated with the two NESHAP proposals are not included in the AEO99 reference case.

Electricity Industry Restructuring

Despite several proposals, no comprehensive Federal electricity restructuring bill had been enacted as of early August 1998. Several bills were proposed, but no consensus could be reached. It is expected that new bills will be introduced early in 1999 in the 106th Congress. At the State level the situation is moving forward more rapidly. Nearly every State has undertaken some effort to review options for or implement changes in the structure of the electricity business, and a number of States have taken regulatory or legislative action [13]. The critical issues in most States are whether and when to allow consumers to choose their electricity suppliers, how to deal with utility stranded costs, and what sort of market structure would most encourage competition.

Twelve States have enacted restructuring legislation and are moving toward letting consumers choose their suppliers over the next several years. Six other States have comprehensive regulatory orders in place. Barring changes, in the twelve States with legislation in place, consumers will be free to choose their electricity suppliers starting some time between 1998 and 2004 [14]. Most of the twelve call for consumer choice to be phased in over several years. Generally, larger industrial customers are given choice earlier, while smaller commercial and residential customers are given choice later.

Three States California, Rhode Island, and Massachusetts plan to allow all their consumers to choose their suppliers by the end of 1998. California opened the market to all customers on March 31, 1998 [15]. Consumers in California now receive bills with separate charges for the services provided. Depending on the type of customer, they could include fees for energy services, transmission services, distribution services, a competitive transition charge, a nuclear decommissioning charge, public program charges, fixed transition charges, and other charges.

The competitive transition charges associated with paying utilities for "stranded" investments they made to serve customers that may not be

recovered in a competitive market-will continue for only a fixed period of time, probably several years. All the services may still be provided by the incumbent utility, or each may come from a different company, depending on the decisions made by the customer. The situation is similar in Rhode Island and Massachusetts, where all customers are able to choose their suppliers as of 1998.

In all three States, decisions have been made about the level of stranded cost recovery allowed and the rate reductions required over the next few years, but some of the decisions are being challenged. Although ballot referendums in California and Massachusetts in the November 1998 elections failed, future challenges are likely.

The three States are taking a variety of approaches to stranded cost recovery [16], differing in the estimation methodology, level of recovery allowed, recovery mechanism, and length of recovery. For example, in California utilities are to be given the opportunity to recover prudently incurred stranded costs. The costs will be recovered through a competitive transition charge and financed through the issuance of rate reduction bonds. Most of the costs will be recovered by the end of 2001, but the bonds mature over a 10-year period. In Rhode Island a 2.8 cent per kilowatthour nonbypassable transition charge will be collected through December 2009. In addition, utilities are required to divest a portion of their generating assets, and the transition charge will be adjusted if market conditions warrant.

Similarly, in Massachusetts, stranded costs will be recovered over 5 to 10 years, power plant divestiture is encouraged, and the transition charge will be adjusted to reflect market conditions. The actual amount of stranded costs each utility will be able to collect in these States will depend on the price of electricity that evolves in the market and the ability of the utility to reduce its operating costs.

Throughout AEO99, all regions of the country are treated as being competitive in wholesale markets (no new rate-based capacity). In five regions-California, New York, New England, the MidAtlantic Area Council (Pennsylvania, Delaware, New Jersey, and Maryland), and the Mid-America Interconnected Network (Illinois and parts of

Legislation and Regulations

Wisconsin and Missouri)—electricity is priced competitively, based on marginal costs, at the retail level. Competitive forces are assumed to continue to put pressure on electricity producers to reduce their costs, and, as a result, nonfuel operations and maintenance costs are assumed to decline by 25 percent over the next 10 years from their current level. It is also assumed that plants will be retired when it is no longer economical to maintain them. In other words, new capacity is built to retire existing capacity and meet growth in the demand for electricity.

Renewable Technologies

In several States, electricity restructuring legislation includes provisions to stimulate the development of renewable generating technologies for wind, solar, geothermal, and biomass plants. Many believe that these technologies may not succeed in a competitive market where investment decisions are based solely on direct market costs. In general, renewable technologies are more expensive than fossil-fueled alternatives (particularly new naturalgas-fired combined-cycle plants), and it is expected that few would be built in a competitive market. Advocates of renewable technologies believe that their environmental benefits outweigh their higher costs, and that the costs could fall significantly if demand increased enough to allow manufacturers to take advantage of economies of scale in production. In other words, if they could be assured of selling more units, manufacturers would invest in larger, more efficient facilities and lower the per-unit costs of production.

To encourage the development of renewable technologies, some States are using a renewable mandate, specifying that a certain amount of renewable capacity must be built. Others are using a public benefit fund (PBF) financed by a small fee collected from customers for each kilowatthour of electricity purchased. The revenue is to be used to support a variety of programs, including low-income support, demand-side management, and renewable development.

A third approach is the renewable portfolio standard (RPS), which specifies that a percentage of the electricity generated (or sold) in the State must be

Legislation and Regulations

produced by qualifying renewable power plants. In most of the bills, qualifying renewables include all renewable facilities other than hydroelectric plants and municipal solid waste. The RPS system can operate as a tradable credit system in which anyone operating a qualifying renewable plant will be issued credits equal to its generation. If the RPS requirement is 5 percent, the operator will only need to keep credits equal to 5 percent of the plant's output. The rest can be sold to suppliers selling power produced from nonqualifying facilities. Examples of State RPS programs include the following:

Arizona has implemented a program to encourage solar power development. The program requires that 0.5 percent of new electricity sales come from solar plants in 1999 and 2000, and 1 percent thereafter.

In Connecticut, new resources are broken into two classes. Class 1 includes sustainable biomass, fuel cells, landfill gas, solar, and wind power. Class 2 includes other biomass, municipal solid waste, and conventional hydroelectricity. The program requires that by 2001 class 1 resources provide a minimum of 0.75 percent of licensed utility output, and that another 5.5 percent be provided by a mix of class 1 and class 2 resources. By 2009, the class 1 minimum requirement grows to 6.0 percent, and an additional 7.0 percent must come from a mix of class 1 and class 2 resources.

Massachusetts has instituted a program that requires an increase in the share of sales coming from qualifying sources (biomass, landfill gas, fuel cells, conventional hydroelectricity, ocean thermal, solar, and wind) from 1 percent in 2003 to 15 percent by 2020.

• In Nevada, the required share for nonhydroelectric renewables starts at 0.2 percent in 2001

and increases 0.2 percentage points per year until reaching 1 percent.

• In Maine, a much larger share is required. By March 2001, 30 percent of total retail sales must be generated from biomass, fuel cells, geothermal, small hydroelectric, municipal solid waste, solar, or wind.

In addition to these programs, States such as California, Colorado, Iowa, Minnesota, New York, and Wisconsin have implemented renewable mandates requiring specific generation or capacity levels or other "green power initiatives."

In order to represent these State programs in the AEO99 projections, estimates were made of the amounts and types of capacity each of the State programs would encourage. Accordingly, new plants with the appropriate technology, capacity, and start years were added to the inventory of plants available. (For example, the Arizona program is expected to encourage 80 megawatts of solar development.) In total, the various State RPS programs are expected to encourage just over 638 megawatts of new renewable capacity between 1999 and 2011. Wind (263 megawatts), solar (163 megawatts), and biomass (137 megawatts) are expected to account for the majority of the renewable capacity encouraged by State RPS programs.

State mandates and other requirements are expect. ed to produce another 1,372 megawatts of new renewable capacity, with wind (1,017 megawatts), geothermal (149 megawatts), biomass (137 megawatts), and landfill gas (69 megawatts) making up most of the capacity. Finally, voluntary plans, such as green power initiatives, add another 67 megawatts 47 megawatts of wind capacity, 10 mega. watts of photovoltaics, and 9 megawatts of landfill gas capacity.