This profile of the U. S. electric power industry provides background information on the evolution of the electricity industry, the composition of a traditional regulated electric utility, the current market structure of the electric industry, and deregulation trends and the potential future market structure of the electricity market. This profile also discusses current industry characteristics and trends that will influence the future generation and consumption of electricity.

5.1.1 Market Structure of the Electric Power Industry The ongoing process of deregulation of wholesale and retail electric markets is changing the structure of the electric power industry. Deregulation is leading to the functional unbundling of generation, transmission, and distribution and to competition in the generation segment of the industry. This section provides background on the current structure of the industry and future deregulation trends. It begins with a brief overview of the evolution of the electric power industry because the future market structure will, in large 5 2 part, be determined by the existing infrastructure and capital assets that have evolved over the past decades.

<IP_ADDRESS> The Evolution of the Electric Power Industry The electric utility industry began as isolated local service systems with the first electric companies evolving in densely populated metropolitan areas like New York and Chicago. Prior to World War I, rural electrification was a piecemeal process. Only small, isolated systems existed, typically serving a single town. The first high voltage transmission network was built in the Chicago area in 1911 ( the Lake County experiment). This new network connected the smaller systems surrounding Chicago and resulted in substantial production economies, lower customer prices, and increased company profits.

In light of the success of the Lake County experiment, the 1910s and 1920s saw increased consolidation and rapid growth in electricity usage. During this period, efficiency gains and demand growth provided the financing for system expansions. Even though the capacity costs ( fixed costs per peak kW demanded) were typically twice as large with the consolidated/ interconnected supply systems, the fixed costs per unit of energy production ( kWh) were comparable to those of the old single city system. This was the case because of load factor improvements, which resulted from aggregating customer demand.

Whereas the average fixed cost per customer was relatively unchanged as a result of the move from single city to consolidated supply systems, large savings were realized from decreases in operating costs. In particular, fuel costs per kWh decreased 70 percent because of the improved combustion efficiency of larger plants and lower fuel prices for purchases of large quantities. In addition, operation and maintenance costs decreased 85 percent, primarily as a result of decreased labor intensity.

During the 1920s, only a small part of the efficiency gains were passed on to customers in the form of lower prices. Producers retained the bulk of the productivity increases as profits. These profits provided the internal capital to finance system expansions and to buy out smaller suppliers. Industry expansion and consolidation led to the development of large utility holding companies whose assets were shares of common stock in many different operating utilities.

The speculative fever of the 1920s led to holding companies purchasing one another, creating financial pyramids based on inflated estimates of company assets. With the stock market crash in 1929, shareholders who had realized both real economic profits and 5 3 speculative gains lost large amounts of money. The financial collapse of the utility holding companies led to new levels of utility regulation.

From the 1930s through the 1960s, the regulated mandate of electric utilities was basically unchanged: to provide safe, adequate, and reliable service to all electricity users. The majority of the state and federal laws regulating utilities in place during this era had been written shortly after the Depression. The laws were primarily designed to prevent " ruinous competition" through costly duplication of utility functions and to protect customers against exploitation from a monopoly supplier.

During this period, most utilities were vertically integrated, controlling everything from generation to distribution. Economies of scale in generation and the inefficiency of duplicating transmission and distribution systems made the electric utility industry a textbook example of a natural monopoly. Electricity was viewed as a homogeneous good from which there were no product unbundling opportunities or unique product offerings on which competition could get a foothold. In addition, the industry was extremely capitalintensive providing a sizable barrier to entry even if the monopoly status of the utilities had not been protected.

From the 1930s to the 1960s, the electric industry experienced almost continuous growth in demand. In addition, there was a steady stream of technological innovations in generation, transmission, and distribution operations. The increased economies of scale, technological advances, and fast demand growth led to steadily declining unit costs. However, in an environment of decreasing unit costs, there were few rate cases and almost no pressure from customers to change the system. This period is often referred to as the golden era for the electric utility industry.

<IP_ADDRESS> Structure of the Traditional Regulated Utility The utilities vary substantially in size, type, and function. Figure 5 1 illustrates the typical structure of the electric utility market. Even with the technological and regulatory changes in the 1970s and 1980s, at the beginning of the 1990s the structure of the electric utility industry could still be characterized in terms of generation, transmission, and distribution. Commercial and retail customers were in essence " captive," and rates and service quality were primarily determined by public utility commissions. 5 4 The majority of utilities are interconnected and belong to a regional power pool. Pooling arrangements enable facilities to coordinate the economic dispatch of generation facilities and manage transmission congestion. In addition, pooling diverse loads can increase load factors and decrease costs by sharing reserve capacity. Large C/ I Customers Small C/ I Customers Residential Customers Transformer Generation Electricity Distribution High Voltage Lines Transmission Power Plants Figure 5 1. Traditional Electric Power Industry Structure 5 5 Generation. Coal fired plants have historically accounted for the bulk of electricity generation in the United States. With abundant national coal reserves and advances in pollution abatement technology, such as advanced scrubbers for pulverized coal and flue gasdesulfurization systems, coal will likely remain the fuel of choice for most existing generating facilities over the near term.

Natural gas accounts for approximately 10 percent of current generation capacity but is expected to grow; advances in natural gas exploration and extraction technologies and new coal gasification have contributed to the use of natural gas for power generation.

Nuclear plants and renewable energy sources ( e. g., hydroelectric, solar, wind) provide approximately 20 percent and 10 percent of current generating capacity, respectively. However, there are no plans for new nuclear facilities to be constructed, and there is little additional growth forecasted in renewable energy.

Transmission. Transmission refers to high voltage lines used to link generators to substations where power is stepped down for local distribution. Transmission systems have been traditionally characterized as a collection of independently operated networks or grids interconnected by bulk transmission interfaces.

Within a well defined service territory, the regulated utility has historically had responsibility for all aspects of developing, maintaining, and operating transmissions. These responsibilities included  system planning and expanding,

 maintaining power quality and stability, and  responding to failures.

Isolated systems were connected primarily to increase ( and lower the cost of) power reliability. Most utilities maintained sufficient generating capacity to meet customer needs, and bulk transactions were initially used only to support extreme demands or equipment outages.

Distribution. Low voltage distribution systems that deliver electricity to customers comprise integrated networks of smaller wires and substations that take the higher voltage and step it down to lower levels to match customers' needs.

The distribution system is the classic example of a natural monopoly because it is not practical to have more than one set of lines running through neighborhoods or from the curb to the house. 1The electric power supply chain includes all generation, transmission, distribution, administrative, and market activities needed to deliver electric power to consumers.

5 6 <IP_ADDRESS> Current Electric Power Supply Chain This section provides background on existing activities and emerging participants in the electric power supply chain. 1 Because the restructuring plans and time tables are made at the state level, the issues of asset ownership and control throughout the current supply chain in the electric power industry vary from state to state. However, the activities conducted throughout the supply chain are generally the same.

Table 5 1 shows costs by utility ownership and by segment of the supply chain. Generation accounts for approximately 75 percent of the cost of delivered electric power.

Figure 5 2 provides an overview of the electric power supply chain, highlighting a combination of activities and service providers. The activities/ members of the electric power supply chain are typically grouped into generation, transmission, and distribution. These three segments are described in the following sections.

Generation. As part of deregulation, the transmission and distribution of electricity are being separated from the business of generating electricity, and a new competitive market in electricity generation is evolving. As power generators prepare for the competitive market, the share of electricity generation attributed to nonutilities and utilities is shifting.

More than 7,000 electricity suppliers currently operate in the U. S. market. As shown in Table 5 2, approximately 42 percent of suppliers are utilities and 58 percent are nonutilities. Utilities include investor owned, cooperatives, and municipal systems. Of the approximately 3,100 utilities operating in the United States, only about 700 generate electric power. The majority of utilities distribute electricity that they have purchased from power generators via their own distribution systems.

Utility and nonutility generators produced a total of 3,369 billion kWh in 1995. Although utilities generate the vast majority of electricity produced in the United States, nonutility generators are quickly eroding utilities' shares of the market. Nonutility generators include private entities that generate power for their own use or to sell to utilities or other end users. Between 1985 and 1995, nonutility generation increased from 98 billion kWh ( 3.8 percent of total generation) to 374 billion kWh ( 11.1 percent). Figure 5 3 illustrates this shift in the share of utility and nonutility generation. 5 7 Utilities. There are four categories of utilities: investor owned utilities ( IOUs), publicly owned utilities, cooperative utilities, and federal utilities. Of the four, only IOUs always generate electricity.

IOUs are increasingly selling off generation assets to nonutilities or converting those assets into nonutilities ( Haltmaier, 1998). To prepare for the competitive market, IOUs have been lowering their operating costs, merging, and diversifying into nonutility businesses.

In 1995, utilities generated 89 percent of electricity, a decrease from 96 percent in 1985. IOUs generate the majority of the electricity produced in the United States. IOUs are either individual corporations or a holding company, in which a parent company operates one or more utilities integrated with one another. IOUs account for approximately three quarters of utility generation, a percentage that held constant between 1985 and 1995.

Utilities owned by the federal government accounted for about one tenth of generation in both 1985 and 1995. The federal government operated a small number of large utilities in 1995 that supplied power to large industrial consumers or federal installations. The Tennessee Valley Authority is an example of a federal utility. Table 5 1. Total Expenditures in 1996 ($ 103)

Utility Ownership Generation Transmission Distribution Customer Accounts and Sales Administration and General Expenses Investorowned 80,891,644 2,216,113 6,124,443 6,204,229 13,820,059 Publicly owned 12,495,324 840,931 1,017,646 486,195 1,360,111 Federal 3,685,719 327,443 1,435 55,536 443,809 Cooperatives 15,105,404 338,625 1,133,984 564,887 1,257,015 112,178,091 3,723,112 8,277,508 7,310,847 16,880,994 75.6% 2.5% 5.6% 4.9% 11.4%

148,370,552 Sources: U. S. Department of Energy, Energy Information Administration ( EIA). 1998a. Financial Statistics of Major Publicly Owned Electric Utilities, 1997. Washington, DC: U. S. Department of Energy.

U. S. Department of Energy, Energy Information Administration ( EIA). 1997. Financial Statistics of Major U. S. Investor Owned Electric Utilities, 1996. Washington, DC: U. S. Department of Energy. 5 8 Many states, municipalities, and other government organizations also own and operate utilities, although the majority do not generate electricity. Those that do generate electricity operate capacity to supply some or all of their customers' needs. They tend to be small, localized outfits and can be found in 47 states. These publicly owned utilities accounted for about one tenth of utility generation in 1985 and 1995. In a deregulated market, these generators may be in direct competition with other utilities to service their market. Electricity Waste Heat Intersystem Exchange Private Lines       Surplus Electricity Purchased   Fuel Source: Coal, Natural Gas, Water, etc.

Surplus Electricity Purchased Self Generation Large C/ I Customers Small C/ I Customers Residential Customers Local Distribution System Reliability and Control Bulk Transmission IPP Generation Local Utility Generation Competing Utility Generation ( outside service territory)

Figure 5 2. Electric Utility Industry 5 9 Rural electric cooperatives are the fourth category of utilities. They are formed and owned by groups of residents in rural areas to supply power to those areas. Cooperatives generally purchase from other utilities the energy that they sell to customers, but some generate their own power. Cooperatives only produced 5 percent of utility generation in 1985 and only 6 percent in 1995.

Nonutilities. Nonutilities are private entities that generate power for their own use or to sell to utilities or other establishments. Nonutilities are usually operated at mines and manufacturing facilities, such as chemical plants and paper mills, or are operated by electric and gas service companies ( DOE, EIA, 1998b). More than 4,200 nonutilities operate in the United States.

Between 1985 and 1995, nonutility generators increased their share of electricity generation from 4 percent to 11 percent ( see Figure 5 3). In 1978, the Public Utilities Regulatory Policies Act ( PURPA) stipulated that electric utilities must interconnect with and purchase capacity and energy offered by any qualifying nonutility. In 1996, FERC issued Orders 888 and 889 that opened transmission access to nonutilities and required utilities to Table 5 2. Number of Electricity Suppliers in 1999 Electricity Suppliers Number Percent Utilities 3,124 42%

Investor owned utilities 222 Cooperatives 875 Municipal systems 1,885 Public power districts 73 State projects 55 Federal agencies 14 Nonutilities 4,247 58%

Nonutilities ( excluding EWGs) 4,103 Exempt wholesale generators 144 Total 7,371 100%

Source: U. S. Department of Energy, Energy Information Administration ( EIA). 1999g. The Changing Structure of the Electric Power Industry 1999: Mergers and Other Corporate Combinations. Washington, DC: U. S. Department of Energy. 5 10 a Includes facilities classified in more than one of the following FERC designated categories: cogenerator QF, small power producer QF, or exempt wholesale generator. Cogen = Cogenerator. EWG = Exempt wholesale generator. Other Non QF = Nocogenerator Non QF. QF = Qualifying facility. SPP = Small power producer. Note: Sum of components may not equal total due to independent rounding. Classes for nonutility generation are determined by the class of each generating unit. Sources: Utility data: U. S. Department of Energy, Energy Information Administration ( EIA). 1996b. Electric Power Annual 1995. Volumes I and II. DOE/ EIA 0348( 95)/ 1. Washington, DC: U. S. Department of Energy; Table 8 ( and previous issues); 1985 nonutility data: Shares of generation estimated by EIA; total generation from Edison Electric Institute ( EEI). 1998. Statistical Yearbook of the Electric Utility Industry 1998. November. Washington, DC; 1995 nonutility data: U. S. Department of Energy, Energy Information Administration ( EIA). 1996b. Electric Power Annual 1995. Volumes I and II. DOE/ EIA 0348( 95)/ 1. Washington, DC: U. S. Department of Energy.

Figure 5 3. Utility and Nonutility Generation and Shares by Class, 1988 and 1998 5 11 share information about available transmission capacity. These moves established wholesale competition, spurring nonutilities to increase generation and firms to invest in nonutility generation.

Nonutilities are frequently categorized by their FERC classification and the type of technology they employ. There are three categories of nonutilities: cogenerators, small power producers ( SPPs), and exempt wholesale generators ( EWGs).

Cogenerators are nonutilities that sequentially or simultaneously produce electricity and another form of energy ( such as heat or steam) using the same fuel source. At cogeneration facilities, steam is used to drive a turbine to generate electricity. The waste heat and steam from driving the turbine is then used as an input in an industrial or commercial process. For a cogenerator to qualify or interconnect with utilities, it must meet certain ownership, operating, and efficiency criteria specified by FERC. In 1985, about 55 percent of nonutility generation was produced by cogenerators that qualified or met FERC's specifications and sold power to utilities. By 1995 the percentage increased to 67 percent as the push for deregulation gathered momentum. At the same time, the percentage that was produced by nonqualifying cogenerators decreased from 25 percent to 9 percent.

SPPs typically generate power using renewable resources, such as biomass, solar energy, wind, or water. However, increasingly SPPs include companies that self generate power using combustion turbines and sell excess power back to the grid. As with cogenerators, SPPs must fulfill a series of FERC requirements to interconnect with utilities. PURPA revisions enabled nonutility renewable electricity to grow significantly, and SPPs have responded by improving technologies, decreasing costs, and increasing efficiency and reliability ( DOE, EIA, 1998b). Between 1985 and 1995, the percentage of SPP nonutility generation nearly doubled to 13 percent.

EWGs produce electricity for the wholesale market. Also known as IPPs, EWGs typically contract directly with large bulk customers, such as large industrial and commercial facilities and utilities. They do not operate any transmission or distribution facilities but pay tariffs to use facilities owned and operated by utilities. Unlike with qualifying cogenerators and SPPs, utilities are not required to purchase energy produced by EWGs, but they may do so at market based prices. EWGs did not exist until the Energy Policy Act created them in 1992, and by 1995 they generated about 2 percent of nonutility electricity. 5 12 In 1995, about 4 percent of nonutility generation was produced by facilities that were classified as any combination of cogenerator, SPP, and EWG. An additional 6 percent was produced by facilities that generate electricity for their own consumption.

Transmission. Whereas the market for electricity generation is moving toward a competitive structure, the transmission of electricity is currently ( and will likely remain) a regulated, monopoly operation. In areas where power markets are developing, generators pay tariffs to distribute their electricity over established lines owned and maintained by independent organizations. Independent service operators ( ISOs) will most likely coordinate transmission operations and generation dispatch over the bulk power system.

The bulk power transmission system consists of three large regional networks, which also encompass smaller groups. The three networks are geographically defined: the Eastern Interconnect in the eastern two thirds of the nation; the Western Interconnect in the western portion; and the Texas Interconnect, which encompasses the majority of Texas. The western and eastern networks are each fully integrated with Canada. The western is also integrated with Mexico. Within each network, the electricity producers are connected by extra highvoltage connections that allow them to transfer electrical energy from one part of the network to the other.

The bulk power system makes it possible for electric power producers to engage in wholesale trade. In 1995, utilities sold 1,283 billion kWh to other utilities. The amount of energy sold by nonutilities has increased dramatically from 40 billion kWh in 1986 to 222 billion kWh in 1995, an average annual increase of 21 percent ( DOE, EIA, 1996a). Distribution utilities and large industrial and commercial customers also have the option of purchasing electricity in bulk at market prices from their local utility, a nonutility, or another utility. The process of transmitting electricity between suppliers via a third party is known as wholesale wheeling.

The wholesale trade for electricity is increasingly handled by power marketers ( brokers). Power marketers act as independent middlemen that buy and sell wholesale electricity at market prices ( EEI, 1999). Customers include large commercial and industrial facilities in addition to utilities. Power marketers emerged in response to increased competition. Brokers do not own generation facilities, transmissions systems, or distribution assets, but they may be affiliated with a holding company that operates generation facilities. Currently, 570 power marketers operate in the United States. The amount of power sold by marketers increased from 3 million MWh to 2.3 billion MWh between 1995 and 1998. This is the equivalent of going from powering 1 million homes to powering 240 million homes 5 13 ( EEI, 1999). Table 5 3 lists the top ten power marketers by sales for the first quarter of 1999.

Distribution. The local distribution system for electricity is expected to remain a regulated monopoly operation. But power producers will soon be able to compete for retail customers by paying tariffs to entities that distribute the power. Utilities may designate an ISO to operate the distribution system or continue to operate it themselves. If the utility operates its own system, it is required by law to charge the same tariff to other power producers that it charges producers within its own corporate umbrella. The sale of electricity by a utility or other supplier to a customer in another utility's retail service territory is known as retail wheeling.

Supporters of retail wheeling claim that it will help lower the average price paid for electricity. The states with the highest average prices for electricity are expected to be the first to permit retail wheeling; wholesale wheeling is already permitted nationwide. In 1996, California, New England, and the Mid Atlantic States had the highest average prices for electricity, paying 3 cents or more per kilowatt hour than the national average of 6.9 cents ( DOE, EIA, 1998b). Open access to the electricity supply, coupled with a proliferation of electricity suppliers, should combine to create falling electricity prices and increasing usage. Table 5 3. Top Power Marketing Companies, First Quarter 1999 Company Total MWh Sold Enron Power Marketing, Inc. 78,002,931 Southern Company Energy Marketing, L. P. 38,367,107 Aquila Power Corp. 29,083,612 PG& E Energy Trading Power, L. P. 28,463,487 Duke Energy Trading & Marketing, L. L. C. 22,276,608 LG& E Energy Marketing, Inc. 15,468,749 Entergy Power Marketing Corp. 12,670,520 PacifiCorp Power Marketing, Inc. 11,800,263 Tractebel Energy Marketing, Inc. 10,041,039 NorAm Energy Services, Inc. 9,817,306 Source: Resource Data International. 1999. " PMA Online Top 25 Power Marketer Rankings." Power Marketers Online Magazine. < http:// www. powermarketers. com/ top25a. htm.> As obtained on August 11, 1999. 5 14 By 2002, the nationwide average price for electricity is projected to be 11 percent lower than in 1995, an average annual decline of roughly 2 percent ( Haltmaier, 1998).

The explosion in computer and other information technology usage in the commercial sector is expected to offset energy efficiency gains in the residential and industrial sectors and lead to a net increase in the demand for electricity. Retail wheeling has the potential to allow customers to lower their costs per kilowatt hour by purchasing electricity from suppliers that best fit their usage profiles. Large commercial and industrial customers engaged in self generation or cogeneration will also be able to sell surplus electricity in the wholesale market.

<IP_ADDRESS> Overview of Deregulation and the Potential Future Structure of the Electricity Market Beginning in the latter part of the 19th century and continuing for about 100 years, the prevailing view of policymakers and the public was that the government should use its power to require or prescribe the economic behavior of " natural monopolies" such as electric utilities. The traditional argument is that it does not make economic sense for there to be more than one supplier   running two sets of wires from generating facilities to end users is more costly than one set. However, since monopoly supply is not generally regarded as likely to provide a socially optimal allocation of resources, regulation of rates and other economic variables was seen as a necessary feature of the system.

Beginning in the 1970s, the public policy view shifted against traditional regulatory approaches and in favor of deregulation for many important industries including transportation, communications, finance, and energy. The major drivers for deregulation of electric power included the following:

 existence of rate differentials across regions offering the promise of benefits from more efficient use of existing generation resources if the power can be transmitted across larger geographic areas than was typical in the era of industry regulation;

 the erosion of economies of scale in generation with advances in combustion turbine technology;

 complexity of providing a regulated industry with the incentives to make socially efficient investment choices;

 difficulty of providing a responsive regulatory process that can quickly adjust rates and conditions of service in response to changing technological and market conditions; and 5 15  complexity of monitoring utilities' cost of service and establishing cost based rates for various customer classes that promote economic efficiency while at the same time addressing equity concerns of regulatory commissions.

Viewed from one perspective, not much changes in the electric industry with restructuring. The same functions are being performed, essentially the same resources are being used, and in a broad sense the same reliability criteria are being met. In other ways, the very nature of restructuring, the harnessing of competitive forces to perform a previously regulated function, changes almost everything. Each provider and each function become separate competitive entities that must be judged on their own.

This move to market based provision of generation services is not matched on the transmission and distribution side. Network interactions on AC transmission systems have made it impossible to have separate transmission paths compete. Hence, transmission and distribution remain regulated. Transmission and generation heavily interact, however, and transmission congestion can prevent specific generation from getting to market. Transmission expansion planning becomes an open process with many interested parties. This open process, coupled with frequent public opposition to transmission expansion, slows transmission enhancement. The net result is greatly increased pressure on the transmission system.

Restructuring of the electric power industry could result in any one of several possible market structures. In fact, different parts of the country will probably use different structures, as the current trend indicates. The eventual structure may be dominated by a power exchange, bilateral contracts, or a combination. A strong Regional Transmission Organization ( RTO) may operate in the area, or a vertically integrated utility may continue to operate a control area. In any case, several important characteristics will change:

 Commercial provision of generation based services ( e. g., energy, regulation, load following, voltage control, contingency reserves, backup supply) will replace regulated service provision. This drastically changes how the service provider is assessed.

 Individual transactions will replace aggregated supply meeting aggregated demand. It will be necessary to continuously assess each individual's performance.

 Transaction sizes will shrink. Instead of dealing only in hundreds and thousands of MW, it will be necessary to accommodate transactions of a few MW and less. 2Nonutility power producers have approximately 10 percent of the capacity of utility power producers.

5 16  Supply flexibility will greatly increase. Instead of services coming from a fixed fleet of generators, service provision will change dynamically among many potential suppliers as market conditions change.

5.1.2 Electricity Generation Because of the uncertainties associated with the future course of deregulation, forecasting deregulation's impact on generation trends, and hence growth in combustion turbines, is difficult. However, most industry experts believe that deregulation will lead to increased competition in the wholesale ( and eventually retail) power markets, driving out high cost producers of electricity, and that there will be an increased reliance on distributed generation to compensate for growing demands on the transmission system.

In 2000, the United States relied on fossil fuels to produce almost 74 percent of its electricity. Table 5 4 shows a breakdown of generation by energy source. 2 Whereas natural gas seems to play a relatively minor role among utility producers, it represents 30 percent of capacity among nonutility producers. This is because nonutilities use coal and petroleum to the same extent as the larger, traditionally regulated utility power producers.

Among nonutility producers, manufacturing facilities contain the largest electricitygenerating capacity. Table 5 5 illustrates that, from 1995 through 1999, manufacturing facilities consistently had the capacity to produce over two thirds of nonutility electricity generation.

In 1997 cogenerators produced energy totaling 146 billion kWh for their own use. Cogenerators are expected to continue to increase their generation capabilities at a slightly slower rate than utilities.

Table 5 6 further disaggregates capacity by prime mover and energy source at electric utilities. As the table shows, hydroelectric and steam are the two prime movers with the most units, while steam and nuclear generators have the greatest total capacity. Combustion turbines' ( including the second stage of CCCTs) generation represents approximately 10 percent of total U. S. capacity.

Figure 5 4 shows the annual electricity sales by sector from 1970 with projections through 2020. 5 17 Table 5 4. Industry Capability by Energy Source, 2000 Energy Source Utility Generators ( MW) Nonutility Generators ( MW) Total ( MW)

Fossil fuels 424,218 173,320 597,538 Coal 259,059 56,190 315,249 Natural gas 38,964 58,668 97,632 Petroleum 26,250 13,003 39,253 Duel fired 99,945 45,549 145,494 Nuclear 85,519 12,038 97,557 Hydroelectric 91,590 7,478 99,068 Renewable/ other 1,050 16,322 17,372 Total 602,377 209,248 811,625 Sources: U. S. Department of Energy, Energy Information Administration. 2000. Electric Power Annual, 1999, Vol. 2. DOE/ EIA 0348( 99)/ 2. Washington, DC: U. S. Department of Energy.

Table 5 5. Installed Capacity at U. S. Nonutility Attributed to Major Industry Groups and Census Division, 1995 through 1999 ( MW)

Year Manufacturing Transportation and Public Utilities Services Mining Public Administration Other Industry Groups Total 1995 47,606 15,124a 2,165 3,428 544 1,388a 70,254 1996 49,529 16,050 2,181 3,313 542 1,575 73,189 1997 49,791 16,559 2,223 3,306 616 1,510 74,004 1998 51,255 24,527 2,506 3,275 534 15,989 98,085 1999 52,430 78,419 2,342 5,123 536 28,506 167,357 a Revised data.

Notes: All data are for 1 MW and greater. Data for 1997 are preliminary; data for prior years are final. Totals may not equal sum of components because of independent rounding.

Source: U. S. Department of Energy, Energy Information Administration ( EIA). 2000. Electric Power Annual 1999, Volume II. Washington, DC: U. S. Department of Energy. 5 18 Table 5 6. Existing Capacity at U. S. Electric Utilities by Prime Mover and Energy Source, as of January 1, 1998 Prime Mover Energy Source Number of Units Generator Nameplate Capacity ( MW)

U. S. Total 10,421 754,925 Steam 2,117 469,210 Coal only 911 276,895 Other solidsa 15 334 Petroleum only 137 22,476 Gas only 117 10,840 Other solids/ coala 1 2 Solids/ petroleumb 72 10,796 Solids/ gasb 232 36,763 Solids/ petroleum/ gasb 1 558 Petroleum/ gas 624 110,324 Internal Combustion 2,892 5,075 Petroleum only 1,799 2,671 Gas only 48 66 Petroleum/ gas 1,044 2,335 Other solids onlya 1 3 Combustion Turbine 1,549 63,131 Petroleum only 625 22,802 Gas only 179 5,776 Petroleum/ gas 745 34,554 Second Stage of CCCTs 202 16,224 Petroleum only 11 470 Gas only 29 2,331 Coal/ petroleum 1 326 Coal/ gas 1 113 Petroleum/ gas 100 8,852 Waste heat 60 4,130 Nuclear 107 107,632 Hydroelectric ( conventional) 3,352 73,202 Hydroelectric ( pumped storage) 141 18,669 Geothermal 27 1,746 Solar 11 5 Wind 19 14 a Includes wood, wood waste, and nonwood waste. b Includes coal, wood, wood waste, and nonwood waste.

Source: U. S. Department of Energy, Energy Information Administration ( EIA). 1999c. Electric Power Annual 1998. Volumes I and II. Washington, DC: U. S. Department of Energy. 5 19 The literature suggests that electricity consumption is relatively price inelastic. Consumers are generally unable or unwilling to forego a large amount of consumption as the price increases. Numerous studies have investigated the short run elasticity of demand for electricity. Overall, the studies suggest that, for a 1 percent increase in the price of electricity, demand will decrease by 0.15 percent. However, as Table 5 7 shows, elasticities vary greatly, depending on the demand characteristics of end users and the price structure. Demand elasticities are estimated to range from a   0.05 percent elasticity of demand for a " flat rates" case ( i. e., no time of use assumption) up to a   0.50 percent demand elasticity for a " high consumer response" case ( DOE, EIA, 1999b).

<IP_ADDRESS> Growth in Generation Capacity The electric industry is continuing to grow and change. Throughout the country, electric utility capacity additions are slightly outpacing capacity retirements. The trend goes beyond an increasing capacity but also shows that coal units are slowly being replaced by newer, more efficient methods of producing energy. In 1997, 71 electric utility units were closed, decreasing capacity by 2,127 MW. Of those, six were coal facilities and 43 were Figure 5 4. Annual Electricity Sales by Sector 5 20 Table 5 7. Key Parameters in the Cases Case Name Key Assumptions Cost Reduction and Efficiency Improvements Short Run Elasticity of Demand ( Percent) Natural Gas Prices Capacity Additions AEO97 Reference Case AEO97 Reference Case   AEO97 Reference Case As needed to meet demand No Competition No change from 1995   AEO97 Reference Case As needed to meet demand Flat Rates ( no time of use rates) AEO97 Reference Case  0.05 AEO97 Reference Case As needed to meet demand Moderate Consumer Response AEO97 Reference Case  0.15 AEO97 Reference Case As needed to meet demand High Consumer Response AEO97 Reference Case  0.50 AEO97 Reference Case As needed to meet demand High Efficiency Increased cost savings and efficiencies  0.15 AEO97 Reference Case As needed to meet demand No Capacity Additions AEO97 Reference Case  0.15 AEO97 Low Oil and Gas Supply Technology Case Not allowed High Gas Price AEO97 Reference Case  0.15 AEO97 High Oil and Gas Supply Technology Case As needed to meet demand Low Gas Price AEO97 Reference Case  0.15 AEO97 Reference Case As needed to meet demand High Value of Reliability AEO97 Reference Case  0.15 AEO97 Reference Case As needed to meet demand Half O& M AEO97 Reference Case  0.15 AEO97 Reference Case As needed to meet demand Intense Competition AEO97 Reference Case  0.15 AEO97 Reference Case As needed to meet demand   = not applicable.

Source: U. S. Department of Energy, Energy Information Administration, Office of Integrated Analysis and Forecasting. " Competitive Electricity Price Projections." < http:// www. eia. doe. gov/ oiaf/ elepri97/ chap3. html>. As obtained on November 15, 1999b. 5 21 petroleum facilities. However, of the 62 facility additions ( 2,918 MW), none were coal powered, while 24 use petroleum. Gas installations slightly outpaced petroleum ones, totaling 25 new units at electric utilities in 1997. Table 5 8 outlines capacity additions and retirements at U. S. electric utilities by energy source.

Planned additions indicate a strong trend towards gas powered turbine/ stationary combustion units. Three quarters of the gas turbine/ stationary combustion units are expected to be gas powered with the remaining quarter petroleum powered. Based on 1998 planned additions, it is likely that all additional petroleum fueled units in the near future will be gas turbine/ stationary combustion units, not steam. Table 5 9 shows planned capacity additions by prime mover and energy source. Table 5 8. Capacity Additions and Retirements at U. S. Electric Utilities by Energy Source, 1997 Primary Energy Source Additions Retirements Number of Units Generator Nameplate Capacity ( MW) Number of Units Generator Nameplate Capacity ( MW)

U. S. total 62 2,918 71 2127 Coal     6 281 Petroleum 24 199 43 445 Gas 25 2,475 18 405 Water ( pumped storage hydroelectric)         Nuclear     2 995 Waste heat 3 171     Renewablea 10 73 2 1 a Includes conventional hydroelectric; geothermal; biomass ( wood, wood waste, nonwood waste); solar; and wind. Note: Total may not equal the sum of components because of independent rounding.

Source: U. S. Department of Energy, Energy Information Administration ( EIA). 1999c. Electric Power Annual 1998. Volumes I and II. Washington, DC: U. S. Department of Energy. 5 22 5.1.3 Electricity Consumption This section analyzes the growth projections for electricity consumption as well as the price elasticity of demand for electricity. Growth in electricity consumption has traditionally paralleled GDP growth. However, improved energy efficiency of electrical equipment, such as high efficiency motors, has slowed demand growth over the past few decades. The magnitude of the relationship has been decreasing over time, from growth of 7 percent per year in the 1960s down to 1 percent in the 1980s. As a result, determining what the future growth will be is difficult, although it is expected to be positive ( DOE, EIA, 1999a). Table 5 10 shows consumption by sector of the economy over the past 10 years. The table shows that since 1989 electricity sales have increased at least 10 percent in all four Table 5 9. Fossil Fueled Existing Capacity and Planned Capacity Additions at U. S. Electric Utilities by Prime Mover and Primary Energy Source, as of January 1, 1998 Planned Additionsa Prime Mover Energy Source Number of Units Generator Nameplate Capacity ( MW)

U. S. Total 272 50,184 Steam 45 18,518 Coal 8 2,559 Petroleum     Gas 37 15,959 Gas Turbine/ Internal Combustion 226 31,663 Petroleum 52 1,444 Gas 174 30,219 a Planned additions are for 1998 through 2007. Totals include one 2.9 MW fuel cell unit.

Notes: Total may not equal the sum of components because of independent rounding. The Form EIA 860 was revised during 1995 to collect data as of January 1 of the reporting year, where " reporting year" is the calendar year in which the report is required to be filed with the Energy Information Administration. These data reflect the status of electric plants/ generators as of January 1; however, dynamic data are based on occurrences in the previous calendar year ( e. g., capabilities and energy sources based on test and consumption in the previous year).

Source: U. S. Department of Energy, Energy Information Administration ( EIA). 1999c. Electric Power Annual 1998. Volumes I and II. Washington, DC: U. S. Department of Energy. 5 23 sectors. The commercial sector has experienced the largest increase, followed by residential consumption.

In the future, residential demand is expected to be at the forefront of increased electricity consumption. Between 1997 and 2020, residential demand is expected to increase at 1.6 percent annually. Commercial growth in demand is expected to be approximately 1.4 percent, while industry is expected to increase demand by 1.1 percent ( DOE, EIA, 1999a).

5.2 Oil and Gas Extraction ( NAICS 211)

The crude petroleum and natural gas industry encompasses the oil and gas extraction process from the exploration for oil and natural gas deposits through the transportation of the Table 5 10. U. S. Electric Utility Retail Sales of Electricity by Sector, 1989 Through July 1999 ( Million kWh)

Period Residential Commercial Industrial Othera All Sectors 1989 905,525 725,861 925,659 89,765 2,646,809 1990 924,019 751,027 945,522 91,988 2,712,555 1991 955,417 765,664 946,583 94,339 2,762,003 1992 935,939 761,271 972,714 93,442 2,763,365 1993 994,781 794,573 977,164 94,944 2,861,462 1994 1,008,482 820,269 1,007,981 97,830 2,934,563 1995 1,042,501 862,685 1,012,693 95,407 3,013,287 1996 1,082,491 887,425 1,030,356 97,539 3,097,810 1997 1,075,767 928,440 1,032,653 102,901 3,139,761 1998 1,124,004 948,904 1,047,346 99,868 3,220,121 Percentage change 1989 1998 19% 24% 12% 10% 18%

a Includes public street and highway lighting, other sales to public authorities, sales to railroads and railways, and interdepartmental sales.

Sources: U. S. Department of Energy, Energy Information Administration ( EIA). 1999c. Electric Power Annual 1998. Volumes I and II. Washington, DC: U. S. Department of Energy.

U. S. Department of Energy, Energy Information Administration ( EIA). 1996b. Electric Power Annual 1995. Volumes I and II. Washington, DC: U. S. Department of Energy. 5 24 product from the production site. The primary products of this industry are natural gas, natural gas liquids, and crude petroleum.

5.2.1 Introduction The United States is home to half of the major oil and gas companies operating around the globe. Although small firms account for nearly 45 percent of U. S. crude oil and natural gas output, the domestic oil and gas industry is dominated by 20 integrated petroleum and natural gas refiners and producers, such as Exxon Mobil, BP Amoco, and Chevron ( Lillis, 1998). Despite the presence of many large global players, the industry experiences a more turbulent business cycle than most other major U. S. industries. Because the industry imports 60 percent of the crude oil used as an input into refineries, it is susceptible to fluctuations in crude oil output and prices, which are strongly influenced by the Organization of Petroleum Exporting Countries ( OPEC). OPEC is a cartel consisting of most of the world's largest petroleum producing countries that acts to increase the profits of member countries. In contrast, natural gas markets in the United States are competitive and relatively stable. Most natural gas used in the United States comes from domestic and Canadian sources.

NAICS 211 includes five major industry groups ( see Table 5 11):

 NAICS 211111 ( SIC 1311): Crude petroleum and natural gas. Firms in this industry are primarily involved in operating oil and gas fields. These firms may also explore for crude oil and natural gas, drill and complete wells, and separate crude oil and natural gas components from natural gas liquids and produced fluids.

 NAICS 211112 ( SIC 1321): Natural gas liquids ( NGL). NGL firms separate NGLs from crude oil and natural gas at the site of production. Propane and butane are NGLs.

 NAICS 213111 ( SIC 1381): Drilling oil and gas wells. Firms in this industry drill oil and natural gas wells on a contract or fee basis.

 NAICS 213112/ 54136 ( SIC 1382): Oil and gas field exploration services. Firms in this industry perform geological, geophysical, and other exploration services.

 NAICS 213112 ( SIC 1389): Oil and gas field services, not elsewhere classified. Companies in this industry perform services on a contract or fee basis that are not classified in the above industries. Services include drill site preparations, such as building foundations and excavating pits, and maintenance. 5 25 In 1997, more than 6,800 crude oil and natural gas extraction companies ( NAICS 211111) generated $ 75 billion in revenues. Revenues for 1997 were approximately 5 percent higher than revenues in 1992, although the number of companies and employees declined 11.5 and 42.5 percent, respectively.

Table 5 12 shows the NGL extraction industry ( NAICS 211112) experienced a decline in the number of companies, establishments, and employees. The industry's revenues declined nearly 8.0 percent between 1992 and 1997, from $ 27 billion per year to $ 24.8 billion per year.

Revenues for NAICS 213111, drilling oil and gas wells, more than doubled between 1992 and 1997. In 1992, the industry employed 47,700 employees at 1,698 companies and generated $ 3.6 billion in annual revenues. By the end of 1997, the industry's annual revenues were $ 7.3 billion, a 106 percent improvement. Although the total number of companies and establishments decreased from 1992 levels, industry employment increased 13 percent to 53,865.

The recent transition from the SIC system to the North American Industrial Classification System ( NAICS) changed how some industries are organized for information collection purposes and thus how certain economic census data are aggregated. Some SIC codes were combined, others were separated, and some activities were classified under one NAICS code and the remaining activities classified under another. The oil and gas field services industry is an example of an industry code that was reclassified. Under NAICS, SIC 1382, Oil and Gas Exploration Services, and SIC 1389, Oil and Gas Services Not Elsewhere Classified, were combined. The geophysical surveying and mapping services portion of SIC Table 5 11. Crude Petroleum and Natural Gas Industries Likely to Be Affected by the Regulation SIC NAICS Description 1311 211111 Crude Petroleum and Natural Gas 1321 211112 Natural Gas Liquids 1381 213111 Drilling Oil and Gas Wells 1382 213112 Oil and Gas Exploration Services 54136 Geophysical Surveying and Mapping Services 1389 213112 Oil and Gas Field Services, N. E. C. 5 26 1382 was reclassified and grouped into NAICS 54136. The adjustments to SIC 1382/ 89 have made comparison between the 1992 and 1997 economic censes difficult at this time. The U. S. Census Bureau has yet to publish a comparison report. Thus, for this industry only 1997 census data are presented. For that year, nearly 6,400 companies operated under SIC 1382/ 89 ( NAICS 213112), employing more than 100,000 people and generating $ 11.5 billion in revenues. Table 5 12. Summary Statistics, Crude Oil and Natural Gas Extraction and Related Industries NAICS Industry Number of Companies Number of Establishments Revenues ($ 1997 103) Employees 211111 Crude Oil and Natural Gas Extraction 1992 7,688 9,391 71,622,600 174,300 1997 6,802 7,781 75,162,580 100,308 211112 Natural Gas Liquid Extraction 1992 108 591 26,979,200 12,000 1997 89 529 24,828,503 10,549 213111 Drilling Oil and Gas Wells 1992 1,698 2,125 3,552,707 47,700 1997 1,371 1,638 7,317,963 53,865 213112 Oil and Gas Field Services 1997 6,385 7,068 11,547,563 106,339 Sources: U. S. Department of Commerce, Bureau of the Census. 1999a. 1997 Economic Census, Mining Industry Series: Crude Petroleum and Natural Gas Extraction. EC97N 2111A. Washington, DC: U. S. Department of Commerce.

U. S. Department of Commerce, Bureau of the Census. 1995a. 1992 Census of Mineral Industries, Industry Series: Crude Petroleum and Natural Gas. MIC92 I 13A. Washington, DC: U. S. Department of Commerce. 5 27 5.2.2 Supply Side Characterizing the supply side of the industry involves describing the production processes, the types of output, major by products, costs of production, and capacity utilization.

<IP_ADDRESS> Production Processes There are four major processes in the oil and gas extraction industry: exploration, well development, production, and site abandonment ( EPA, 1999b). Exploration is the search for rock formations associated with oil and/ or natural gas deposits. Nearly all oil and natural gas deposits are located in sedimentary rock. Certain geological clues, such as porous rock with an overlying layer of low permeability rock, help guide exploration companies to a possible source of hydrocarbons. While exploring a potential site, the firm conducts geophysical prospecting and exploratory drilling.

After an economically viable field is located, the well development process begins. Well holes, or well bores, are drilled to a depth of between 1,000 and 30,000 feet, with an average depth of about 5,500 feet ( EPA, 1999b). The drilling procedure is the same for both onshore and offshore sites. A steel or diamond drill bit, which may be anywhere between 4 inches and 3 feet in diameter, is used to chip off rock to increase the depth of the hole. The drill bit is connected to the rock by several pieces of hardened pipe known collectively as the drill string. As the hole is drilled, casing is placed in the well to stabilize the hole and prevent caving. Drilling fluid is pumped down through the center of the drill string to lubricate the equipment. The fluid returns to the surface through the space between the drill string and the rock formation or casing. Once the well has been drilled, rigging, derricks, and other production equipment are installed. Onshore fields are equipped with a pad and roads; ships, floating structures, or a fixed platform are procured for offshore fields.

Production is the process of extracting hydrocarbons through the well and separating saleable components from water and silt. Oil and natural gas are naturally occurring coproducts and most production sites handle crude oil and gas from more than one well. Once the hydrocarbons are brought to the surface, they are separated into a spectrum of substances, including liquid hydrocarbons, gas, and water and other nonsaleable constituents. After being extracted, crude oil is always delivered to a refinery for processing; natural gas may be processed at the field or at a natural gas processing plant to remove impurities. Natural gas is separated from crude oil by passing the hydrocarbons through one or two decreasing pressure chambers. Excess water is removed from the crude oil, at which point the oil is 5 28 about 98 percent pure, a purity sufficient for storage or transport to a refinery ( EPA, 1999b). Excess water is returned to the well to facilitate the production process, but silt is discarded. If enough natural pressure does not exist in the reservoir to force the hydrocarbons through the well, then the reservoir is pressurized using pumps or excess water to lift the hydrocarbons.

Natural gas is conditioned using a dehydration and a sweetening process, which removes hydrogen sulfide and carbon dioxide, so that it is of high enough quality to pass through transmission systems. The gas may be conditioned at the field or at one of the 623 operating gas processing facilities located in gas producing states, such as Texas, Louisiana, Oklahoma, and Wyoming. These plants also produce the nation's NGLs, propane and butane ( NGSA et al., 2000c).

Site abandonment occurs when a site lacks the potential to produce economic quantities of natural gas or when a production well is no longer economically viable. The well( s) are plugged using long cement plugs and steel plated caps, and supporting production equipment is disassembled and moved offsite.

<IP_ADDRESS> Types of Output The oil and gas industry's principal products are crude oil, natural gas, and NGLs ( see Tables 5 13 and 5 14). Refineries process crude oil into several petroleum products. These products include motor gasoline ( 40 percent of crude oil); diesel and home heating oil ( 20 percent); jet fuels ( 10 percent); waxes, asphalts, and other nonfuel products ( 5 percent); feedstocks for the petrochemical industry ( 3 percent); and other lesser products ( DOE, EIA, 1999d).

Natural gas is produced from either oil wells ( known as " associated gas") or wells that are drilled for the primary purpose of obtaining natural gas ( known as " nonassociated gas") ( see Table 5 14). Methane is the predominant component of natural gas ( about 85 percent), but ethane ( about 10 percent), propane, and butane are also significant components ( see Table 5 13). Propane and butane, the heavier components of natural gas, exist as liquids when cooled and compressed. These latter two components are usually separated and processed as NGLs ( EPA, 1999b). 5 29 Table 5 13. U. S. Supply of Crude Oil and Petroleum Products ( 103 barrels), 1998 Commodity Field Production Refinery Production Imports Crude Oil 2,281,919 3,177,584 Natural Gas Liquids 642,202 245,918 82,081 Ethane/ ethylene 221,675 11,444 6,230 Propane/ propylene 187,369 200,815 50,146 Normal butane/ butylene 54,093 29,333 8,612 Isobutane/ isobutylene 66,179 4,326 5,675 Other 112,886 11,418 Other Liquids 69,477 211,266 Finished Petroleum Products 69,427 5,970,090 437,515 Finished motor gasoline 69,427 2,880,521 113,606 Finished aviation gasoline 7,118 43 Jet fuel 556,834 45,143 Kerosene 27,848 466 Distillate fuel oil 1,249,881 76,618 Residual fuel oil 277,957 100,537 Naptha 89,176 22,388 Other oils 78,858 61,554 Special napthas 24,263 2,671 Lubricants 67,263 3,327 Waxes 8,355 613 Petroleum coke 260,061 263 Asphalt and road oil 181,910 10,183 Still gas 239,539 Miscellaneous products 20,506 103 Total 3,063,025 6,216,008 3,908,446 Source: U. S. Department of Energy, Energy Information Administration ( EIA). 1999f. Petroleum Supply Annual 1998, Volume I. Washington, DC: U. S. Department of Energy. 5 30 <IP_ADDRESS> Major By products The engines that provide pumping action at wells and push crude oil and natural gas through pipes to processing plants, refineries, and storage locations produce HAPs. HAPs produced in engines include formaldehyde, acetaldehyde, acrolein, and methanol.

<IP_ADDRESS> Costs of Production The 42 percent decrease in the number of people employed by the crude oil and natural gas extraction industry between 1992 and 1997 was matched by a corresponding 40 percent decrease in the industry's annual payroll ( see Table 5 15). During the same period, industry outlays for supplies, such as equipment and other supplies, increased over 32 percent, and capital expenditures nearly doubled. Automation, mergers, and corporate downsizing have made this industry less labor intensive ( Lillis, 1998).

Unlike the crude oil and gas extraction industry, the NGL extraction industry's payroll increased over 6 percent even though total industry employment declined 12 percent. The industry's expenditures on capital projects, such as investments in fields, production facilities, and other investments, increased 11.4 percent between 1992 and 1997. The cost of supplies did, however, decrease 13 percent from $ 23.3 billion in 1992 to $ 20.3 billion in 1997.

Employment increased in Drilling Oil and Gas Wells. In 1992, the industry employed 47,700 people, increasing 13 percent to 53,865 in 1997. During a period where industry revenues increased over 100 percent, the industry's payroll increased 41 percent and the cost of supplies increased 182 percent. Table 5 14. U. S. Natural Gas Production, 1998 Gross Withdrawls Production ( 106 cubic feet)

From gas wells 17,558,621 From oil wells 6,365,612 Less losses and repressuring 5,216,477 Total 18,707,756 Source: U. S. Department of Energy, Energy Information Administration ( EIA). 1999e. Natural Gas Annual 1998. Washington, DC: U. S. Department of Energy. 5 31 <IP_ADDRESS> Capacity Utilization U. S. annual oil and gas production is a small percentage of total U. S. reserves. In 1998, oil producers extracted approximately 1.5 percent of the nation's proven crude oil reserves ( see Table 5 16). A slightly lesser percentage of natural gas was extracted ( 1.4 percent), and an even smaller percentage of NGLs was extracted ( 0.9 percent). The Table 5 15. Costs of Production, Crude Oil and Natural Gas Extraction and Related Industries NAICS Industry Employees Payroll ($ 1997 103) Cost of Supplies Used, Purchased Machinery Installed, Etc. ($ 1997 103) Capital Expenditures ($ 1997 103)

211111 Crude Oil and Natural Gas Extraction 1992 174,300 $ 8,331,849 $ 16,547,510 $ 10,860,260 1997 100,308 $ 4,968,722 $ 21,908,191 $ 21,117,850 211112 Natural Gas Liquid Extraction 1992 12,000 $ 509,272 $ 23,382,770 $ 609,302 1997 10,549 $ 541,593 $ 20,359,528 $ 678,479 213111 Drilling Oil and Gas Wells 1992 47,700 $ 1,358,784 $ 1,344,509 $ 286,509 1997 53,865 $ 1,918,086 $ 7,317,963 $ 2,209,300 213112 Oil and Gas Field Services 1997 106,339 $ 3,628,416 $ 3,076,039 $ 1,165,018 Sources: U. S. Department of Commerce, Bureau of the Census. 1999a. 1997 Economic Census, Mining, Industry Series: Crude Petroleum and Natural Gas Extraction. EC97N 2111A. Washington, DC: U. S. Department of Commerce.

U. S. Department of Commerce, Bureau of the Census. 1995a. 1992 Census of Mineral Industries, Industry Series: Crude Petroleum and Natural Gas. MIC92 I 13A. Washington, DC: U. S. Department of Commerce. 5 32 United States produces approximately 40 percent ( 2,281 million barrels) of its annual crude oil consumption, importing the remainder of its crude oil from Canada, Latin America, Africa, and the Middle East ( 3,178 million barrels). Approximately 17 percent ( 3,152 billion cubic feet) of U. S. natural gas supply is imported. Most imported natural gas originates in Canadian fields in the Rocky Mountains and off the Coast of Nova Scotia and New Brunswick.

5.2.3 Demand Side Characterizing the demand side of the industry involves describing product characteristics. Crude oil, or unrefined petroleum, is a complex mixture of hydrocarbons that is the most important of the primary fossil fuels. Refined petroleum products are used for petrochemicals, lubrication, heating, and fuel. Petrochemicals derived from crude oil are the source of chemical products such as solvents, paints, plastics, synthetic rubber and fibers, soaps and cleansing agents, waxes, jellies, and fertilizers. Petroleum products also fuel the engines of automobiles, airplanes, ships, tractors, trucks, and rockets. Other applications include fuel for electric power generation, lubricants for machines, heating, and asphalt ( Berger and Anderson, 1978). Because the market for crude oil is global and its price set by OPEC, slight increases in the cost of producing crude oil in the United States will have little effect on the price of products that use crude oil as an intermediate good. Production cost increases will be absorbed by the producer, not passed along to consumers. Table 5 16. Estimated U. S. Oil and Gas Reserves, Annual Production, and Imports, 1998 Category Reserves Annual Production Imports Crude oil ( 106 barrels) 152,453 2,281 3,178 Natural gas ( 109 cubic feet) 1,330,930 18,708 3,152 Natural gas liquids ( 106 barrels) 26,792 246 NA Sources: U. S. Department of Energy, Energy Information Administration ( EIA). 1999h. U. S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1998 Annual Report. Washington, DC: U. S. Department of Energy.

U. S. Department of Energy, Energy Information Administration ( EIA). 1999f. Petroleum Supply Annual 1998, Volume I. Washington DC: U. S. Department of Energy. 5 33 Natural gas is a colorless, flammable gaseous hydrocarbon consisting for the most part of methane and ethane. The largest single application for natural gas is as a domestic or industrial fuel. However, other specialized applications have emerged over the years, such as a nonpolluting fuel for buses and other motor vehicles. Carbon black, a pigment made by burning natural gas with little air and collecting the resulting soot, is an important ingredient in dyes, inks, and rubber compounding operations. Also, much of the world's ammonia is manufactured from natural gas; ammonia is used either directly or indirectly in urea, hydrogen cyanide, nitric acid, and fertilizers ( Tussing and Tippee, 1995).

5.2.4 Organization of the Industry Many oil and gas firms are merging to remain competitive in both the global and domestic marketplaces. By merging with their peers, these companies may reduce operating expenses and reap greater economies of scale than they would otherwise. Recent mergers, such as BP Amoco and Exxon Mobil, have reduced the number of companies and facilities operating in the United States. Currently, there are 20 domestic major oil and gas companies, and only 40 major global companies in the world ( Conces, 2000). Most U. S. oil and gas firms are concentrated in states with significant oil and gas reserves, such as Texas, Louisiana, California, Oklahoma, and Alaska.

Tables 5 17 through 5 20 present the number of facilities and value of shipments by facility employee count for each of the four NIACS 211 industries. In 1997, 6,802 oil and gas extraction companies operated 7,781 facilities, an average of 1.14 facilities per company ( see Table 5 17). Facilities with more than 100 employees produced more than 55 percent of the industry's value of shipments. Although the number of companies and the number of facilities operating in 1992 were both greater then than in 1997, the distribution of shipment values by employee size was similar to that of 1992.

Facilities employing fewer than 50 people in the NGLs extraction industry accounted for 64 percent, or $ 15.8 billion, of the industry's total value of shipments in 1997 ( see Table 5 18). Four hundred eighty seven of the industry's 529 facilities are in that employment category. This also means that a relatively small number of larger facilities produced 36 percent of the industry's annual output, in terms of dollar value. The number of facilities with zero to four employees and the number with 50 or more employees decreased during the 5 year period, accounting for most of the 10.5 percent decline in the number of facilities from 1992 to 1997. The average number of facilities per company was 5.5 and 5.9 in 1992 and 1997, respectively. 5 34 As mentioned earlier, the oil and gas well drilling industry's 1997 value of shipments were 106 percent larger than 1992' s value of shipments ( see Table 5 19). However, the number of companies primarily involved in this industry declined by 327 over 5 years, and 487 facilities closed during the same period. The distribution of the number of facilities by employment size shifted towards those that employed 20 or more people. In 1997, those facilities earned two thirds of the industry's revenues. Table 5 17. Size of Establishments and Value of Shipments, Crude Oil and Natural Gas Extraction Industry ( NAICS 211111), 1997 and 1992 1997 1992 Average Number of Employees in Facility Number of Facilities Value of Shipments ($ 1997 103) Number of Facilities Value of Shipments ($ 1997 103)

0 to 4 employees 5,249 $ 5,810,925 6,184 $ 5,378,330 5 to 9 employees 1,161 $ 3,924,929 1,402 $ 3,592,560 10 to 19 employees 661 $ 4,843,634 790 $ 4,504,830 20 to 49 employees 412 $ 10,538,529 523 $ 8,820,100 50 to 99 employees 132 $ 8,646,336 203 $ 5,942,130 100 to 249 employees 105 154 $ 11,289,730 250 to 499 employees 40 68 $ 8,135,850 500 to 999 employees 14 $ 41,318,227 46 $ 14,693,630 1,000 to 2,499 employees 5 18 $ 9,265,530 2,500 or more employees 2 3 D Total 7,781 $ 75,162,580 9,391 $ 71,622,600 D = undisclosed Sums do not add to totals due to independent rounding.

Sources: U. S. Department of Commerce, Bureau of the Census. 1999a. 1997 Economic Census, Mining, Industry Series: Crude Petroleum and Natural Gas Extraction. EC97N 2111A. Washington, DC: U. S. Department of Commerce.

U. S. Department of Commerce, Bureau of the Census. 1995a. 1992 Census of Mineral Industries, Industry Series: Crude Petroleum and Natural Gas. MIC92 I 13A. Washington, DC: U. S. Department of Commerce. 5 35 In 1997, 6,385 companies operated 7,068 oil and gas field services facilities, an average of 1.1 facilities per company. Most facilities employed four or fewer employees; however, those facilities with 20 or more employees accounted for the majority of the industry's revenues ( see Table 5 20). Table 5 18. Size of Establishments and Value of Shipments, Natural Gas Liquids Industry ( NAICS 211112), 1997 and 1992 1997 1992 Average Number of Employees in Facility Number of Facilities Value of Shipments ($ 1997 103) Number of Facilities Value of Shipments ($ 1997 103)

0 to 4 employees 143 $ 1,407,192 190 $ 2,668,000 5 to 9 employees 101 $ 1,611,156 92 $ 1,786,862 10 to 19 employees 122 $ 4,982,941 112 $ 5,240,927 20 to 49 employees 121 $ 7,828,439 145 $ 10,287,200 50 to 99 employees 35 $ 5,430,448 36 $ 4,789,849 100 to 249 employees 3 D 14 $ 2,205,819 250 to 499 employees 3 D 2 D 500 to 999 employees 1 D 0   1,000 to 2,499 employees 0   0   2,500 or more employees 0   0   Total 529 $ 24,828,503 591 $ 26,979,200 D = undisclosed Sums do not add to totals due to independent rounding.

Sources: U. S. Department of Commerce, Bureau of the Census. 1999b. 1997 Economic Census, Mining, Industry Series: Natural Gas Liquid Extraction. EC97N 2111b. Washington, DC: U. S. Department of Commerce.

U. S. Department of Commerce, Bureau of the Census. 1995b. 1992 Census of Mineral Industries, Industry Series: Natural Gas Liquids. MIC92 I 13B. Washington, DC: U. S. Department of Commerce. 5 36 5.2.5 Markets and Trends Between 1990 and 1998, crude oil consumption increased 1.4 percent per year, and natural gas consumption increased 2.0 percent per year. The increase in natural gas consumption came mostly at the expense of coal consumption ( EPA, 1999b). The Energy Information Administration ( EIA), a unit of the Department of Energy, anticipates that natural gas consumption will continue to grow at a similar rate through the year 2020 to 32 trillion cubic feet/ year ( DOE, EIA, 1999d). They also expect crude oil consumption to grow at an annual rate of less than 1 percent over the same period. Table 5 19. Size of Establishments and Value of Shipments, Drilling Oil and Gas Wells Industry ( NAICS 213111), 1997 and 1992 1997 1992 Average Number of Employees in Facility Number of Facilities Value of Shipments ($ 1997 103) Number of Facilities Value of Shipments ($ 1997 103)

0 to 4 employees 825 $ 107,828 1,110 $ 254,586 5 to 9 employees 215 $ 231,522 321 $ 182,711 10 to 19 employees 197 $ 254,782 244 $ 256,767 20 to 49 employees 200 $ 1,008,375 233 $ 572,819 50 to 99 employees 95 $ 785,804 120 $ 605,931 100 to 249 employees 75 $ 1,069,895 70 $ 816,004 250 to 499 employees 10 $ 435,178 19 $ 528,108 500 to 999 employees 14 $ 1,574,139 5 $ 97,254 1,000 to 2,499 employees 6 D 3 $ 238,427 2,500 or more employees 1 D     Total 1,638 $ 7,317,963 2,125 $ 3,552,707 D = undisclosed Sums do not add to totals due to independent rounding.

Sources: U. S. Department of Commerce, Bureau of the Census. 1999c. 1997 Economic Census, Mining, Industry Series: Drilling Oil and Gas Wells. EC97N 2131A. Washington, DC: U. S. Department of Commerce.

U. S. Department of Commerce, Bureau of the Census. 1995c. 1992 Census of Mineral Industries, Industry Series: Oil and Gas Field Services. MIC92 I 13C. Washington, DC: U. S. Department of Commerce. 5 37 5.3 Natural Gas Pipelines The natural gas pipeline industry ( NAICS 4862) comprises establishments primarily engaged in the pipeline transportation of natural gas from processing plants to local distribution systems. Also included in this industry are natural gas storage facilities, such as depleted gas fields and aquifers.

5.3.1 Introduction The natural gas industry can be divided into three segments, or links: production, transmission, and distribution. Natural gas pipeline companies are the second link, performing the vital function of linking gas producers with the local distribution companies and their customers. Pipelines transmit natural gas from gas fields or processing plants Table 5 20. Size of Establishments and Value of Shipments, Oil and Gas Field Services ( NAICS 213112), 1997 and 1992 1997 Average Number of Employees at Facility Number of Facilities Value of Shipments ($ 1997 103)

0 to 4 employees 4,122 $ 706,396 5 to 9 employees 1,143 $ 571,745 10 to 19 employees 835 $ 904,356 20 to 49 employees 629 $ 1,460,920 50 to 99 employees 211 $ 1,480,904 100 to 249 employees 84 $ 1,175,766 250 to 499 employees 21 $ 754,377 500 to 999 employees 13 $ 1,755,689 1,000 to 2,499 employees 9 D 2,500 or more employees 1 D Total 7,068 $ 11,547,563 D = undisclosed Sums do not add to totals due to independent rounding.

Source: U. S. Department of Commerce, Bureau of the Census. 1999d. 1997 Economic Census, Mining, Industry Series: Support Activities for Oil and Gas Operations. EC97N 2131B. Washington, DC: U. S. Department of Commerce. 5 38 through high compression steel pipe to their customers. By the end of 1998, there were more than 300,000 miles of transmission lines ( OPS, 2000).

The interstate pipeline companies that linked the producing and consuming markets functioned mainly as resellers or merchants of gas until about the 1980s. Rather than acting as common carriers ( i. e., providers only of transportation), pipelines typically bought and resold the gas to a distribution company or to some other downstream pipelines that would later resell the gas to distributers. Today, virtually all pipelines are common carriers, transporting gas owned by other firms instead of wholesaling or reselling natural gas ( Tussing and Tippee, 1995).

According to the U. S. Bureau of the Census, the natural gas pipeline industry's revenues totaled $ 19.6 billion in 1997. Pipeline companies operated 1,450 facilities and employed 35,789 people ( see Table 5 21). The industry's annual payroll is nearly $ 1.9 billion.

As noted previously, the recent transition from the SIC system to the NAICS changed how some industries are organized for information collection purposes and thus how certain economic census data are aggregated. Some SIC codes were combined, others were separated, and some activities were classified under one NAICS code and the remaining activities classified under another. The natural gas transmission ( pipelines) industry is an example of an industry code that was reclassified. Under NAICS, SIC 4922, natural gas transmission ( pipelines), and a portion of SIC 4923, natural gas distribution, were combined. The adjustments have made comparison between the 1992 and 1997 economic censes Table 5 21. Summary Statistics for the Natural Gas Pipeline Industry ( NAICS 4862), 1997 Establishments 1,450 Revenue ($ 103) $ 19,626,833 Annual payroll ($ 103) $ 1,870,950 Paid employees 35,789 Source: U. S. Department of Commerce, Bureau of the Census. 2000. 1997 Economic Census, Transportation and Warehousing: Geographic Area Series. EC97T48A US. Washington, DC: Government Printing Office. 5 39 difficult at this time. The U. S. Census Bureau has yet to publish a comparison report. Thus, for this industry only 1997 census data are presented.

5.3.2 Supply Side Characterizing the supply side involves describing services provided by the industry, by products, the costs of production, and capacity utilization.

<IP_ADDRESS> Service Description Natural gas is delivered from gas processing plants and fields to distributers via a nationwide network of over 300,000 miles of transmission pipelines ( NGSA et al., 2000a). The majority of pipelines are composed of steel pipes that measure from 20 to 42 inches in diameter and operate 24 hours a day. Natural gas enters pipelines at gas fields, storage facilities, or gas processing plants and is " pushed" through the pipe to the city gate or interconnections, the point at which distribution companies receive the gas. Pipeline operators use sophisticated computer and mechanical equipment to monitor the safety and efficiency of the network.

Reciprocating stationary combustion engines compress and provide the pushing force needed to maintain the flow of gas through the pipeline. When natural gas is transmitted, it is compressed to reduce the volume of gas and to maintain pushing pressure. The gas pressure in pipelines is usually between 300 and 1,300 psi, but lesser and higher pressures may be used. To maintain compression and keep the gas moving, compressor stations are located every 50 to 100 miles along the pipeline. Most compressors are large reciprocating engines powered by a small portion of the natural gas being transmitted through the pipeline.

There are over 8,000 gas compressing stations along U. S. gas pipelines, each equipped with one or more engines. The combined output capability of U. S. compressor engines is over 20 million hp ( NGSA et al., 2000a). Nearly 5,000 engines have individual output capabilities from 500 to over 8,000 hp. The replacement cost of this subset of larger engines is estimated by the Gas Research Institute to be $ 18 billion ( Whelan, 1998).

Before or after natural gas is delivered to a distribution company, it may be stored in an underground facility. Underground storage facilities are most often depleted oil and/ or gas fields, aquifers, or salt caverns. Natural gas storage allows distribution and pipeline companies to serve their customers more reliably by withdrawing more gas from storage during peak use periods and reduces the time needed to respond to increased gas demand 5 40 ( NGSA et al., 2000b). In this way, storage guarantees continuous service, even when production or pipeline transportation services are interrupted.

<IP_ADDRESS> By products According to the Natural Gas Supply Association ( NGSA), about 3 percent of the natural gas moved through pipelines escapes. The engines that provide pumping action at plants and push crude oil and natural gas through pipelines to customers and storage facilities produce HAPs. As noted previously, HAPs produced in engines include formaldehyde, acetaldehyde, acrolein, and methanol.

<IP_ADDRESS> Costs of Production Between 1996 and 2000, pipeline firms committed over $ 14 billion to 177 expansion and new construction projects. These projects added over 15,000 miles and 36,178 million cubic feet per day ( MMcf/ d) capacity to the transmission pipeline system. Table 5 22 summarizes the investments made in pipeline projects during the past 5 years. Building new pipelines is more expensive than expanding existing pipelines. For the period covered in the table, the average cost per project mile was $ 862,000. However, the costs for pipeline expansions averaged $ 542,000, or 29 cents per cubic foot of capacity added. New pipelines averaged $ 1,157,000 per mile at 48 cents per cubic foot of capacity.

Pipelines must pay for the natural gas that is consumed to power the compressor engines. The amount consumed and the price paid have fluctuated in recent years. In 1998, pipelines consumed 635,477 MMcf of gas, paying, on average, $ 2.01 per 1,000 cubic feet. Pipelines used less natural gas in 1998 than in previous years; the price paid for that gas fluctuated between $ 1.49 and $ 2.29 between 1994 and 1997 ( see Table 5 23). For companies that transmit natural gas through their own pipelines the cost of the natural gas consumed is considered a business expense.

<IP_ADDRESS> Capacity Utilization During the past 15 years, interstate pipeline capacity has increased significantly. In 1990, the transmission pipeline system's capacity was 74,158 MMcf/ day ( see Table 5 24). By the end of 1997, capacity reached 85,847 MMcf/ day, an increase of approximately 16 percent. The system's usage has increased at a faster rate than capacity. The average daily flow was 60,286 MMcf/ day in 1997, a 22 percent increase over 1990' s rates. Currently, the system operates at approximately 72 percent of capacity. 5 41 Table 5 22. Summary Profile of Completed and Proposed Natural Gas Pipeline Projects, 1996 to 2000 All Type Projects New Pipelines Expansions Year Number of Projects System Mileage New Capacity ( MMcf/ d) Project Costs ($ 106) Average Cost per Mile ($ 103) Costs per Cubic Foot Capacity ( cents) Average Cost per Mile ($ 103) Costs per Cubic Foot Capacity ( cents) Average Cost per Mile ($ 103) Costs per Cubic Foot Capacity ( cents)

1996 26 1,029 2,574 $ 552 $ 448 21 $ 983 17 $ 288 27 1997 42 3,124 6,542 $ 1,397 $ 415 21 $ 554 22 $ 360 21 1998 54 3,388 11,060 $ 2,861 $ 1,257 30 $ 1,301 31 $ 622 22 1999 36 3,753 8,205 $ 3,135 $ 727 37 $ 805 46 $ 527 31 2000 19 4,364 7,795 $ 6,339 $ 1,450 81 $ 1,455 91 $ 940 57 Total 177 15,660 36,178 $ 14,285 $ 862 39 $ 1,157 48 $ 542 29 Note: Sums may not add to totals because of independent rounding.

Source: U. S. Department of Energy, Energy Information Administration ( EIA). 1999d. Natural Gas 1998: Issues and Trends. Washington, DC:

U. S. Department of Energy. 5 42 5.3.3 Demand Side Most pipeline customers are local distribution companies that deliver natural gas from pipelines to local customers. Many large gas users will buy from marketers and enter into special delivery contracts with pipelines. However, local distribution companies ( LDCs) serve most residential, commercial, and light industrial customers. LDCs also use compressor engines to pump natural gas to and from storage facilities and through the gas lines in their service area. Table 5 23. Energy Usage and Cost of Fuel, 1994 1998 Year Pipeline Fuel ( MMcf) Average Price ($ per 1,000 cubic feet)

1994 685,362 1.70 1995 700,335 1.49 1996 711,446 2.27 1997 751,470 2.29 1998 635,477 2.01 Source: U. S. Department of Energy, Energy Information Administration ( EIA). 1999e. Natural Gas Annual 1998. Washington, DC: US Department of Energy.

Table 5 24. Transmission Pipeline Capacity, Average Daily Flows, and Usage Rates, 1990 and 1997 1990 1997 Percent Change Capacity ( MMcf per day) 74,158 85,847 16 Average Flow ( MMcf per day) 49,584 60,286 22 Usage Rate ( percent) 68 72 4 Source: U. S. Department of Energy, Energy Information Administration. 1999d. Natural Gas 1998: Issues and Trends. Washington, DC: US Department of Energy. 5 43 While economic considerations strongly favor pipeline transportation of natural gas, liquified natural gas ( LNG) emerged during the 1970s as a transportation option for markets inaccessible to pipelines or where pipelines are not economically feasible. Thus, LNG is a substitute for natural gas transmission via pipelines. LNG is natural gas that has been liquified by lowering its temperature. LNG takes up about 1/ 600 of the space gaseous natural gas takes up, making transportation by ship possible. However, virtually all of the natural gas consumed in the United States reaches its consumer market via pipelines because of the relatively high expense of transporting LNG and its volatility. Most markets that receive LNG are located far from pipelines or production facilities, such as Japan   the world's largest LNG importer, Spain, France, and Korea ( Tussing and Tippee, 1995).

5.3.4 Organization of the Industry Much like other energy related industries, the natural gas pipeline industry is dominated by large investor owned corporations. Smaller companies are few because of the real estate, capital, and operating costs associated with constructing and maintaining pipelines ( Tussing and Tippee, 1995). Many of the large corporations are merging to remain competitive as the industry adjusts to restructuring and increased levels of competition. Increasingly, new pipelines are built by partnerships: groups of energy related companies share capital costs through joint ventures and strategic alliances ( DOE, EIA, 1999d). Ranked by system mileage, the largest pipeline companies in the United States are El Paso Energy ( which recently merged with Southern Natural Gas Co.), Enron, Williams Cos., Coastal Corp., and Duke Energy ( see Table 5 25). El Paso Energy and Coastal intend to merge in mid 2000.

5.3.5 Markets and Trends During the past decade, interstate pipeline capacity has increased 16 percent. Many existing pipelines underwent expansion projects, and 15 new interstate pipelines were constructed. In 1999 and 2000, proposals for pipeline expansions and additions called for a $ 9.5 billion investment, an increase of 16.0 billion cubic feet per day of capacity ( DOE, EIA, 1999d).

The EIA ( 1999d) expects natural gas consumption to grow steadily, with demand forecasted to reach 32 trillion cubic feet by 2020. The expected increase in natural gas demand has significant implications for the natural gas pipeline system. 5 44 The EIA ( 1999d) expects the interregional pipeline system, a network that connects the lower 48 states and the Canadian provinces, to grow at an annual rate of 0.7 percent between 2001 and 2020. However, natural gas consumption is expected to grow at more than twice that annual rate, 1.8 percent, over that same period. The majority of the growth in consumption is expected to be fueled by the electric generation sector. According to the EIA, a key issue is what kinds of infrastructure changes will be required to meet this demand and what the financial and environmental costs will be of expanding the pipeline network.

The EIA addresses the discrepancy between annual consumption growth and interregional pipeline capacity growth with the following explanation: " Overall, interregional pipeline capacity ( including imports) is projected to grow at an annual rate of only about 0.7 percent between 2001 and 2020 ( compared with 3.7 percent between 1997 Table 5 25. Five Largest Natural Gas Pipeline Companies by System Mileage, 2000 Company Headquarters Sales ($ 1999 106) Employment ( 1999) Miles of Pipeline El Paso Energy Corporation Incl. El Paso Natural Gas Co. Southern Natural Gas Co. Tennessee Gas Pipe Line Co. Houston, TX $ 5,782 4,700 40,200 Enron Corporation Incl. Northern Border Pipe Line Co. Northern Natural Gas Co. Transwestern Pipeline Co. Houston, TX $ 40,112 17,800 32,000 Williams Companies, Inc. Incl. Transcontinental Gas Pipe Line Northwest Pipe Line Co. Texas Gas Pipe Line Co. Tulsa, OK $ 8,593 21,011 27,000 The Coastal Corporation Incl. ANR Pipeline Co. Colorado Interstate Gas Co. Houston, TX $ 8,197 13,000 18,000 Duke Energy Corporation Incl. Panhandle Eastern Pipeline Co. Algonquin Gas Transmission Co. Texas Eastern Transmission Co. Charlotte, NC $ 21,742 21,000 11,500 Sources: Heil, Scott F., Ed. Ward's Business Directory of U. S. Private and Public Companies 1998, Volume 5. Detroit, MI: Gale Research Inc.

Sales, employment, and system mileage: Hoover's Incorporated. 1998. Hoover's Company Profiles. Austin, TX: Hoover's Incorporated. < http:// www. hoovers. com/>. 5 45 and 2000 and 3.8 percent between 1990 and 2000). However, EIA also forecasts that consumption will grow at a rate of 27 Bcf per day ( 1.8 percent annually) during the same period. The difference between these two growth estimates is predicted upon the assumption that capacity additions to support increased demand will be local expansions of facilities within regions ( through added compression and pipeline looping) rather than through new long haul ( interregional) systems or large scale expansions" ( 1999d, p. 125). 6 1 SECTION 6 ECONOMIC ANALYSIS METHODS This section presents the methodology for analyzing the economic impacts of the NESHAP. Implementation of this methodology will provide the economic data and supporting information needed by EPA to support its regulatory determination. This analysis is based on microeconomic theory and the methods developed for earlier EPA studies to operationalize this theory. These methods are tailored to and extended for this analysis, as appropriate, to meet EPA's requirements for an economic impact analysis ( EIA) of controls placed on stationary combustion turbines.

This methodology section includes a description of the Agency requirements for conducting an EIA, background information on typical economic modeling approaches, the conceptual approach selected for this EIA, and an overview of the computerized market model used in the analysis. The focus of this section is on the approach for modeling the electricity market and its interactions with other energy markets and final product markets. Appendix A contains additional detail on estimating changes is producer and consumer surplus in the nonelectric utility markets included in the economic model.

6.1 Agency Requirements for Conducting an EIA The CAA provides the statutory authority under which all air quality regulations and standards are implemented by OAQPS. The 1990 CAA Amendments require that EPA establish emission standards for sources releasing any of the listed HAPs.

Congress and the Executive Office have imposed requirements for conducting economic analyses to accompany regulatory actions. The Agency has published its guidelines for developing an EIA ( EPA, 1999a). Section 312 of the CAA specifically requires a comprehensive analysis that considers benefits, costs, and other effects associated with compliance. On the benefits side, it requires consideration of all the economic, public health, and environmental benefits of compliance. On the cost side, it requires consideration of the effects on employment, productivity, cost of living, economic growth, and the overall economy. These effects are evaluated by measures of facility and company level production impacts and societal level producer and consumer welfare impacts. The RFA and SBREFA require regulatory agencies to consider the economic impacts of regulatory actions on small entities. Executive Order 12866 requires regulatory agencies to conduct an analysis of the economic benefits and costs of all proposed regulatory actions with projected costs greater than $ 100 million. Also, Executive Order 13211 requires EPA to consider for 6 2 particular rules the impacts on energy markets. The Agency's draft Economic Analysis Guidelines provide detailed instructions and expectations for economic analyses that support rulemaking ( EPA, 1999a). The EIA provides the data and information needed to comply with the federal regulation, the executive order, and the guidance manual.

6.2 Overview of Economic Modeling Approaches In general, the EIA methodology needs to allow EPA to consider the effect of the different regulatory alternatives. Several types of economic impact modeling approaches have been developed to support regulatory development. These approaches can be viewed as varying along two modeling dimensions:

 the scope of economic decisionmaking accounted for in the model and  the scope of interaction between different segments of the economy.

Each of these dimensions was considered in recommending our approach. The advantages and disadvantages of each are discussed below.

6.2.1 Modeling Dimension 1: Scope of Economic Decisionmaking Models incorporating different levels of economic decisionmaking can generally be categorized as with behavior responses and without behavior responses ( accounting approach). Table 6 1 provides a brief comparison of the two approaches. The behavioral approach is grounded in economic theory related to producer and consumer behavior in response to changes in market conditions. In essence, this approach models the expected reallocation of society's resources in response to a regulation. The behavioral approach explicitly models the changes in market prices and production. Resulting changes in price and quantity are key inputs into the determination of a number of important phenomena in an EIA, such as changes in producer surplus, changes in consumer surplus, and net social welfare effects. For example, a large price increase may imply that consumers bear a large share of the regulatory burden, thereby mitigating the impact on producers' profits and plant closures.

In contrast, the nonbehavioral/ accounting approach essentially holds fixed all interaction between facility production and market forces. In this approach, a simplifying assumption is made that the firm absorbs all control costs, and discounted cash flow analysis is used to evaluate the burden of the control costs. Typically, engineering control costs are weighted by the number of affected units to develop " engineering" estimates of the total annualized costs. These costs are then compared to company or industry sales to evaluate the regulation's impact. 6 3 6.2.2 Modeling Dimension 2: Interaction Between Economic Sectors Because of the large number of markets potentially affected by the combustion turbines regulation, an issue arises concerning the level of sectoral interaction to model. In the broadest sense, all markets are directly or indirectly linked in the economy; thus, all commodities and markets are to some extent affected by the regulation. For example, the control costs on turbines may directly affect the market for aluminum if aluminum plants are operating turbines for self generation of electricity or generation of process steam. However, control costs will also indirectly affect the market for aluminum because the cost of electricity will increase. As a result, the increased price of aluminum production ( due to direct and indirect costs on the aluminum industry) may be passed onto consumers of aluminum products.

The appropriate level of market interactions to be included in the EIA is determined by the scope of the regulation across industries and the ability of affected firms to pass along the regulatory costs in the form of higher prices. Alternative approaches for modeling interactions between economic sectors can generally be divided in three groups: Table 6 1. Comparison of Modeling Approaches EIA With Behavioral Responses Incorporates control costs into production function Includes change in quantity produced Includes change in market price Estimates impacts for  affected producers  unaffected producers  consumers  foreign trade EIA Without Behavioral Responses  Assumes firm absorbs all control costs  Typically uses discounted cash flow analysis to evaluate burden of control costs  Includes depreciation schedules and corporate tax implications  Does not adjust for changes in market price  Does not adjust for changes in plant production 6 4  Partial equilibrium model: Individual markets are modeled in isolation. The only factor affecting the market is the cost of the regulation on facilities in the industry being modeled.

 General equilibrium model: All sectors of the economy are modeled together. General equilibrium models operationalize neoclassical microeconomic theory by modeling not only the direct effects of control costs, but also potential input substitution effects, changes in production levels associated with changes in market prices across all sectors, and the associated changes in welfare economywide. A disadvantage of general equilibrium modeling is that substantial time and resources are required to develop a new model or tailor an existing model for analyzing regulatory alternatives.

 Multiple market partial equilibrium model: A subset of related markets are modeled together, with intersectoral linkages explicitly specified. To account for the relationships and links between different markets without employing a full general equilibrium model, analysts can use an integrated partial equilibrium model. In instances where separate markets are closely related and there are strong interconnections, there are significant advantages to estimating market adjustments in different markets simultaneously using an integrated market modeling approach.

6.3 Selected Modeling Approach Used for Combustion Turbine Analysis To conduct the analysis for the combustion turbine MACT, the Agency used a market modeling approach that incorporates behavioral responses in a multiple market partial equilibrium model as described above. The majority of the regulation's control costs are projected to be associated with combustion turbines in the electricity market. These control costs will increase the price of energy, affecting almost all sectors of the economy. Because the elasticity of demand for energy varies across fuel types, it is important to use a market modeling approach to estimate the share of the burden borne by producers and consumers.

Multiple market partial equilibrium analysis provides a manageable approach to incorporate interactions between energy markets and final product markets into the EIA to accurately estimate the impact of the regulation. The multiple market partial equilibrium approach represents an intermediate step between a simple, single market partial equilibrium approach and a full general equilibrium approach. This approach involves identifying and modeling the most significant subset of market interactions using an integrated partial equilibrium framework. In effect, the modeling technique is to link a series of standard partial equilibrium models by specifying the interactions between supply functions and then solving for all prices and quantities across all markets simultaneously. 1Technical changes are indirectly captured through the own price and cross price elasticities of demand used to model fuel switching. These are discussed in Section 6.4.1.

6 5 Figure 6 1 presents an overview of the key market linkages included in the economic impact modeling approach used to analyze the combustion turbines MACT. The focus of the analysis is on the energy supply chain, including the extraction and distribution of natural gas and oil, the generation of electricity, and the consumption of energy by producers of final products and services. As shown in Figure 6 1, wholesale electricity generators consume natural gas and petroleum products to generate electricity that is then used in the production of final products and services. In addition, the final product and service markets also use natural gas and petroleum products as an input into their production process. This analysis explicitly models the linkages between these market segments.

The control costs associated with the regulation will directly affect the cost of the generation of wholesale electricity using combustion turbines. In addition to the direct impact of control costs on entities installing new combustion turbines, indirect impacts are passed along the energy supply chain through changes in prices. For example, the price of natural gas will increase because of two effects: the higher price of electricity used in the natural gas industry and increased demand for natural gas generated by fuel switching from electricity to natural gas. Similarly, production costs for manufacturers of final products will change as a result of price of electricity and natural gas.

Also included in the impact model is feedback on changes in outputs in final product markets to the demand for Btus in the fuel markets. The change in facility output is determined by the size of the Btu cost increase ( typically variable cost per output), the facility's production function ( slope of facility level supply curve), and the characteristics of the facility's downstream market ( other market suppliers and market demanders). For example, if consumers' demand for a product is not sensitive to price, then producers can pass the cost of the regulation through to consumers and the facility output will not change. However, if only a small number of facilities in a market are affected, then competition will prevent a facility from raising its prices.

One possible feedback pathway not explicitly modeled is technical changes in manufacturing processes. For example, if the cost of Btus increases, a facility may use measures to increase manufacturing efficiency or capture waste heat. These facility level responses are a form of pollution prevention. However, directly incorporating these responses into the model is beyond the scope of our analysis. 1 6 6   demand oil Oil Supply Exogenous Demand Endogenous   demand NG Gas   demand coal Coal Industry A Btu Production Manufacturing Process Industry C Industry B Regulatory Costs Energy Consumption   demand elec Electricity Electricity Market Fuel Markets   supply product A Product A Supply Endogenous Demand Exogenous Intermediate or Final Product Markets

Figure 6 1. Links Between Energy and Final Product Markets 2The same controls are required for SCCTs and for CCCTs. But the relative costs are higher for SCCTs because their equipment and installation costs are approximately 40 percent less compared to CCCTs. Control costs are discussed in Section 6.1. 3A similar figure and analysis apply for peak load power with the exception that peak load supply is generally less responsive to price changes at the margin ( i. e., base load elasticity of supply > peak load elasticity of supply).

6 7 The major market segments included in the model and the intermarket linkages connecting the fuel markets and final product and service markets are described below. Because, as mentioned in Section 3, the overwhelming majority of combustion turbine units are used to generate wholesale electric power, the discussion focuses on the electricity market.

6.3.1 Electricity Markets In this analysis, the market for base load energy and peak power are modeled separately. As the industry deregulates, it is becoming increasingly common for separate market prices to be determined for these two commodity attributes of electricity. In addition, the growth of CCCTs is being driven primarily by growth in base load energy demand, and the growth in SCCTs will be driven primarily by growth in peak demand. And because the relative impact on the control costs is greater for SCCTs compared to CCCTs, economic impacts will be different for base load energy and peak power. 2 The base load energy and peak power market analyses compare the baseline equilibrium ( without the regulation) to the regulated market equilibrium. Figure 6 2a presents a generalized market for the base load electricity that includes the installation of new turbines to meet demand growth for base load power. 3 Existing source supply is characterized by an upward sloping marginal cost ( supply) curve. The supply of new base load generation capacity is characterized by constant marginal costs and is modeled as a horizontal supply curve through the current market price. Figure 6 2b shows that the control costs associated with the rule will affect both existing and new sources of supply, shifting the market supply curve and leading to an increase in price and decrease in quantity of base load power consumed.

6.3.2 Other Energy Markets The petroleum, natural gas, and coal markets are also included in the market model. Because the overwhelming majority of the affected combustion turbines is projected to be used in the electricity market, the other energy markets are assumed not to be directly affected by the rule. However, these markets will be indirectly affected through changes in input fuel prices ( i. e., a supply shift) and changes in demand from final product and service 6 8 a) Without Regulation b) With Control Costs Price $/ kWh Quantity ( kWh)   P Price $/ kWh P 0 Q 0 Existing Sources New Sources Quantity ( kWh)   Q Existing Source Shift New Source Shift Figure 6 2. Electricity Market markets using these energy sources ( i. e., a demand shift). The ultimate impact on market price and quantities depends on the relative magnitudes of these shifts. Note the demand for other fuels may increase ( Figure 6 3a) as firms switch away from electricity to petroleum, natural gas, or coal, or demand may decrease ( Figure 6 3b) as the higher price for electricity suppresses economic activity decreasing demand for all fuels.

6.3.3 Supply and Demand Elasticities for Energy Markets The market model incorporates behavioral changes based on the price elasticities of supply and demand. The price elasticities used to estimate the economic impacts presented in Section 6.3 are given in Table 6 2. Appendix B contains the sensitivity analysis for the key supply and demand elasticity assumptions.

Because most of the direct cost impacts fall on the combustion turbines in electricity markets, the price elasticities of supply in the electricity markets are important factors influencing the size and distribution of the economic impacts associated with the combustion turbine regulation. The elasticities of supply are intended to represent the behavioral 4The supply curve for new sources is assumed to be horizontal, reflecting a constant marginal cost of production for new sources.

6 9 S 1 S 0 Btu Price ($/ Btu)

D 0 D 1 S 1 S 0 Btu Price ($/ Btu)

D 0 D 1   Q   P a) Demand Increase b) Demand Decrease   P   Q Figure 6 3. Potential Market Effects of the MACT on Petroleum, Natural Gas, or Coal responses from existing sources. 4 However, in general, there is no consensus on estimates of the price elasticity of supply for electricity. Estimates of the elasticity of supply for electric power were unavailable. This is in part because, under traditional regulation, the electric utility industry had a mandate to serve all its customers. In addition, utilities werecompensated on a rate based rate of return. As a result, the market concept of supply elasticity was not the driving force in utilities' capital investment decisions. To operationalize the model, a supply elasticity of 0.75 was assumed for the base load energy market. We assumed that the peak power market was one half of base load energy elasticity. Given the uncertainty surrounding these parameters, the Agency conducted a sensitivity analysis for this value. The results of this sensitivity analysis are reported in Appendix B.

In contrast, many studies have been conducted on the elasticity of demand for electricity, and it is generally agreed that, in the short run, the demand for electricity is relatively inelastic. Most residential, commercial, and industrial electricity consumers do not significantly adjust short run behavior in response to changes in the price of electricity. The elasticity of demand for electricity is primarily driven by long run decisions regarding 6 10 equipment efficiency and fuel substitution. Table 6 6 shows the elasticities of demand used for the commercial, residential, and transportation sectors.

Additional elasticity of demand parameters for the commercial, residential, and transportation sectors, by fuel type ( natural gas, petroleum and coal), were obtained from the Energy Information Administration. The elasticity of demand in the energy market for the manufacturing sector is not specified because the model calculates the derived demand for each of the five energy markets modeled. In effect, adjustments in the final product markets due to changes in production levels and fuel switching are used to estimate changes in demand, eliminating the need for demand elasticity parameters in the energy markets.

6.3.4 Final Product and Service Markets Producers of final products and services are segmented into industrial, commercial, transportation, and residential sectors. The industrial sector is further partitioned into the 23 manufacturing, agricultural, and mining sectors. A partial equilibrium analysis was Table 6 2. Supply and Demand Elasticities Elasticity of Demand Energy Sectors Elasticity of Supply Manufacturing Commerciala Transportationa Residentiala Electricity: baseload energy 0.75 Derived demand Derived demand   0.24   0.23 Electricity: peak power 0.375b Derived demand Derived demand   0.24   0.23 Natural gas 0.41c Derived demand Derived demand   0.47   0.26 Petroleum 0.58d Derived demand Derived demand   0.28   0.28 Coal 1.0e Derived demand Derived demand   0.28   0.28 a Energy Information Administration. 2000. " Issues in Midterm Analysis and Forecasting 1999   Table 1." < http:// www. eia. doe. gov/ oaif/ issues/ pricetbl1. html>. As obtained on May 8, 2000. b Assumed to be one half of baseload energy elasticity. c Dahl, Carol A., and Thomas E. Duggan. 1996. " U. S. Energy Product Supply Elasticities: A Survey and Application to the U. S. Oil Market." Resource and Energy Economics18: 243 263. d Hogman, William W. 1989. " World Oil Price Projections: A Sensitivity Analysis." Prepared pursuant to the Harvard Japan World Oil Market Study. Cambridge, MA: Energy Environmental Policy Center, John F. Kennedy School of Government, Harvard University. e Zimmerman, M. B. 1977. " Modeling Depletion in the Mineral Industry: The Case of Coal." The Bell Journal of Economics 8( 2): 41 65. 6 11 Btu Production Decision Output Market   Fuel Use   Output   $/ Btu Production Decision $/ Btu   $/ Btu Fuel Markets Compliance Costs Figure 6 4. Fuel Market Interactions with Facility Level Production Decisions conducted for each of these model the supply and demand of final products. Changes in production levels and fuel switching due to the regulation's impact on the price of electricity are then linked back into the energy markets.

<IP_ADDRESS> Modeling the Impact on the Industrial and Commercial Sectors The impact of the regulation on these sectors was modeled using changes in the cost of Btus used in production processes. In this context, Btus refer to the generic energy requirements that are used to generate process heat, process steam, or shaft power. As shown in Figure 6 4, the regulation will increase the cost of Btu production indirectly through increases in the price of Btus due to control costs on wholesale electricity generators. The effect is similar to placing a tax on certain types of energy sources ( i. e., on Btus generated by combustion turbines). The firms' reactions to the change in the cost of Btu production feeds back into the energy markets in two ways ( see Figure 6 4). The first feedback pathway is through changing the fuel used in the production process. This can include fuel switching, such as switching from gas turbines to power processes to diesel engines, and/ or process changes that increase energy efficiency and reduce the amount of Btus required per unit of output. Fuel switching impacts are modeled using cross price elasticities of demand between energy sources and own price elasticities. 6 12 EPA modeled fuel switching using secondary data developed by the U. S. Department of Energy for the National Energy Modeling System ( NEMS). Table 6 3 contains fuel price elasticities of demand for electricity, natural gas, petroleum products, and coal. The diagonal elements in the table represent own price elasticities. For example, the table indicates that for steam coal, a 1 percent change in the price of coal will lead to a 0.499 percent decrease in the use of coal. The off diagonal elements are cross price elasticities and indicate fuel switching propensities. For example, for steam coal, the second column indicates that a 1 percent increase in the price of coal will lead to a 0.061 percent increase in the use of natural gas.

The second feedback pathway to the energy markets is through the facility's change in output. Because Btus are an input into the production process, price increases (  $ / Btu) lead to an upward shift in the industry supply curve. In a perfectly competitive market, the point where supply equals demand determines the market price and quantity. A shift in the industry supply curve leads to a change in the equilibrium market price and quantity. EPA assumed constant returns to scale in production so that the percentage change in the equilibrium market quantity in each final product and service market equals the percentage change in Btus consumed by industries.

The change in equilibrium supply and demand in each final industrial and commercial sector was modeled using a partial equilibrium approach. The size of the regulation induced shifts in the final product supply curves is a function of the indirect fuel costs ( determined by the change in fuel prices and the fuel intensity) relative to variable production costs in each manufacturing industry. Table 6 3. Fuel Price Elasticities Inputs Own and Cross Elasticities in 2015 Electricity Natural Gas Coal Residual Distillate Electricity   0.074 0.092 0.605 0.080 0.017 Natural Gas 0.496   0.229 1.087 0.346 0.014 Steam Coal 0.021 0.061   0.499 0.151 0.023 Residual 0.236 0.036 0.650   0.587 0.012 Distillate 0.247 0.002 0.578 0.044   0.055 Source: U. S. Department of Energy, Energy Information Administration ( EIA). January 1998c. Model Documentation Report: Industrial Sector Demand Module of the National Energy Modeling System. DOE/ EIA M064( 98). Washington, DC: U. S. Department of Energy. 6 13 It was assumed that the demand for final industrial and commercial products and services is unchanged by the regulation. However, because the demand function quantifies the change in quantity demanded in response to a change in price, the baseline demand conditions are important in determining the regulation's impact. Because prices changes are anticipated to be small, the key demand parameters are the elasticity of demand with respect to changes in the price of final products. Demand elasticities for each of the sectors included in the analysis are reported in Table 6 4.

<IP_ADDRESS> Impact on the Residential Sector and Transportation Sectors The residential and transportation sector does not bear any direct costs associated with the regulation because they do not own combustion turbines. However, they bear indirect costs due to price increases. These sectors' change in energy demand in response to changes in energy prices is modeled as a series of demand curves parameterized by elasticity of demand parameters ( see Table 6 2).

<IP_ADDRESS> Impact on the Government Sector All combustion turbines projected to be installed by government entities will be for local generation of electricity. These municipal generators are grouped into the electricity energy market; thus the government sector is not explicitly included in the model.

6.4 Summary of the Economic Impact Model We summarize the linkages used to operationalize the estimation of economic impacts associated with the compliance costs in Figure 6 5.

Control costs on new turbines used for generators will shift the supply curve for wholesale electricity. The new equilibrium price and quantity in the electricity market will determine the distribution of impacts between producers ( electricity generators) and consumers. Changes in wholesale electricity generators' demand for input fuels ( due to changes in the market quantity of electricity) feed back into the natural gas, coal, and petroleum markets.

Finally, manufacturers experience supply curve shifts due to changes in prices for natural gas, petroleum, electricity, and coal. The share of these costs borne by producers ( manufactures) and consumers is determined by the new equilibrium price and quantity in the final product and service markets. Changes in manufacturers' Btu demands due to fuel switching and changes in production levels feed back into the energy markets. 6 14 Table 6 4. Supply and Demand Elasticities for Industrial and Commercial Sectors NAICS Description Supply Demand Industrial Sectors 311 Food 0.75   1.00 312 Beverage and Tobacco Products 0.75   1.30 313 Textile Mills 0.75   1.50 314 Textile Product Mills 0.75   1.50 315 Apparel 0.75   1.10 316 Leather and Allied Products 0.75   1.20 321 Wood Products 0.75   1.00 322 Paper 0.75   1.50 323 Printing and Related Support 0.75   1.80 325 Chemicals 0.75   1.80 326 Plastics and Rubber Products 0.75   1.80 327 Nonmetallic Mineral Products 0.75   1.00 331 Primary Metals 0.75   1.00 332 Fabricated Metal Products 0.75   0.20 333 Machinery 0.75   0.50 334 Computer and Electronic Products 0.75   0.30 335 Electrical Equip., Appliances, and Components 0.75   0.50 336 Transportation Equipment 0.75   0.50 337 Furniture and Related Products 0.75   1.80 339 Miscellaneous 0.75   0.60 11 Agricultural Sector 0.75   1.80 23 Construction Sector 0.75   1.00 21 Other Mining Sector 0.75   0.30 Commercial Sector ( NAICS 42 45; 51 56; 61 72) 0.75   1.00 6 15   demand elec Electricity Electricity Market   demand oil Oil Assume Supply Model Demand   demand NG Gas   demand coal Coal Industry A Btu Production Manufacturing Process Industry Z Industry B Regulatory Costs

P   Q Q Energy Consumption Final Product Markets Fuel Markets Fuel Prices Fuel Prices Fuel Prices Fuel Prices   Production Process ( Fuel Switching)   Production Levels Product Supply Product Price P = market price of final output Q = quantity sold of final output     Residential Households Commercial Businesses Fuel Prices Figure 6 5. Operationalizing the Estimation of Economic Impact 6 16 Adjustments in price and quantity in all energy and final product markets occur simultaneously. A computer model was used to numerically simulate market adjustments by iterating over commodity prices until equilibrium is reached ( i. e., until supply equals demand in all markets being modeled) and to estimate the economic impact of the regulation ( change in producer and consumer surplus) in the sectors of the economy being modeled.

This model comprises a series of computer spreadsheet modules. The modules integrate the engineering inputs and the market level adjustment parameters to estimate the regulation's impact on the price and quantity in each market being analyzed. At the heart of the model is a market clearing algorithm that compares the total quantity supplied to the total quantity demanded for each market commodity. Appendix A describes the computer model in more detail.

6.4.1 Estimating Changes in Social Welfare The combustion turbine regulation will impact almost every sector of the economy either directly through control costs or indirectly through changes in the price of energy and final products. For example, a share of control costs that originate in the energy markets are passed through the final product markets and are borne by both the producers and consumers of final products. To estimate the total change in social welfare without double counting impacts across the linked partial equilibrium markets being modeled, EPA quantified social welfare changes for the following categories:

 change in producer surplus in the energy markets,

 change in producer surplus in the final product and service markets,

 change in consumer surplus in the final product and service markets, residential and transportation energy markets.

Figure 6 6 illustrates the change in producer and consumer surplus in the intermediate energy market and the final product markets. For example, assume a simple world with only one energy market, wholesale electricity, and one final product market, pulp and paper. If the regulation increased the cost of generating wholesale electricity, then part of the cost of the regulation will be borne by the electricity producers as decreased producer surplus and part of the costs will be passed on to the pulp and paper manufacturers. In Figure 6 6a, the pulp and paper manufacturers are the consumers of electricity, so the change in consumer surplus is displayed. This change in consumer surplus in the energy market is captured by the final product market ( because the consumer is the pulp and paper industry in this case), where it is split between consumer surplus and producer surplus in those markets. Figure 6 6b shows the change in producer surplus in the energy market. 6 17 S D S

D ( a) Change in Consumer Surplus in the Energy Market ( c) Change in Consumer Surplus in Final Product Markets ( b) Change in Producer Surplus in the Energy Market ( d) Change in Producer Surplus in Final Product Markets P P 2 Q P 1 Q 2 Q 1 S D S

P P B Q P A Q B Q A S D S  P P B Q P A Q B Q A P P 2 Q P 1 Q 2 Q 1 S D S

A B C E F Figure 6 6. Changes in Economic Welfare with Regulation As shown in Figures 6 6c and 6 6d, the cost affects the pulp and paper industry by shifting up the supply curve in the pulp and paper market. These higher electricity prices therefore lead to costs in the pulp and paper industry that are distributed between producers and consumers of paper products in the form of lower producer surplus and lower consumer surplus. Note that the change in consumer surplus in the intermediate energy market must equal the total change in consumer and producer surplus in the final product market. Thus, to avoid double counting, the change in consumer surplus in the intermediate energy market was not quantified; instead the total change in social welfare was calculated as 6 18 Change in Social Welfare =   PSE +   PSF +   CSF +   CSRT ( 6.1)

where  PSE = change in producer surplus in the energy markets,

 PSF = change in producer surplus in the final product markets,

 CSF = change in consumer surplus in the final product markets, and  CSRT = change in consumer surplus residential and transportation energy markets.

Appendix A contains the detailed equations used to calculate the change in producer and consumer surplus in the appropriate intermediate and final product markets. 1All costs are reported in 1998 dollars.

7 1 SECTION 7 ECONOMIC IMPACT ANALYSIS Control measures implemented to comply with the regulation will impose regulatory costs on affected facilities in the energy, manufacturing, commercial, and government sectors. These costs will be distributed between producers and consumers through changes in energy prices and changes in prices of final products and services. This section describes the engineering control costs of the regulatory alternatives and presents the economic impact estimates, including energy impacts, of the regulation.

7.1 Engineering Control Cost Inputs The cost impacts associated with the regulation in the fifth year after promulgation comprise capital and annual operating, performance testing, monitoring, recordkeeping, and reporting costs. The Department of Energy ( DOE) projects the 218 new combustion turbines will begin operation during the 5 year period between 2002 and 2007. Of these new turbines, it is estimated that approximately 44 units ( 20 percent) will be located at major HAP sources and be required to comply with the combustion turbine NESHAP.

EPA estimates the annualized capital costs of these add on controls for 44 new stationary combustion turbines ( 170 MW) are $ 42.6 million ( see Table 7 1). 1 Additional annual costs include performance testing, monitoring, recordkeeping, reporting, and the annual costs of the oxidation catalyst control system and CEMS yielding a total annual cost of $ 43.3 million for affected units. All new sources will be required to conduct an initial performance test to demonstrate compliance. In addition, EPA estimates that every year most of the " nonaffected" new sources ( 70 percent) may have to perform an initial notification to comply with the regulation. The total cost for initial notification for 123 new turbines is estimated to be approximately $ 12,000. For more details on the derivation of these costs, refer to the " Cost Analysis for Impacts Associated with Stationary Combustion Turbine MACT," a memo that is in the public docket. 2Revenue in the electric utility industry was segmented into the base load and peak power markets assuming an 80/ 20 split, respectively. This ratio was estimated based on discussions with industry experts.

7 2 Table 7 1. Engineering Cost Analysis for the Stationary Combustion Turbine MACT Standard ($ 1998)

Combine per Turbine Number of Affected Turbines Total Cost Capital Costs CEMS $ 3,000 44 $ 132,000 Oxidation catalyst $ 3,255,377 44 $ 143,236,588 Total Capital Cost $ 143,368,588 Annual Costs CEMS $ 427 44 $ 18,788 Oxidation catalyst $ 969,499 44 $ 42,657,956 Performance tests $ 12,350 44 $ 543,400 Monitoring, recordkeeping, reporting $ 2,709 44 $ 119,201 Initial notification only 98 123 $ 11,993 Total Annual Cost ( 1998$) $ 43,351,338 aRevenues and costs are in 1998$.

7.1.1 Computing Supply Shifts in the Electricity Market For the purpose of the market model, the electric services industry is broken into two market sectors: base load energy and peak power. As shown in Section 4 ( Table 4 3), EPA estimates approximately two thirds of new combustion turbine units are projected to contribute to the base load energy market, and the remaining one third are projected to contribute to the peak power market. As a result, the control costs for the electricity are distributed 67 percent to the electric base load energy market and 33 percent to the peak power market. The relative shift in the supply curve for each segment is presented as the percentage shift in the price of the marginal unit produced. The percentage shift is calculated as the ratio of control costs to the revenue of the affected portion of the industry2 ( see Table 7 2). As shown, new affected sources with add on controls and testing requirements have the largest supply shift ( 1.8 percent for base load energy and 3.5 percent for peak power). The supply shifters for the remaining segments are all less than 0.1 percent. 7 3 Table 7 2. Summary of Turbine Cost Information and Supply Shifts Share Units of Market (%) Revenuea ($ 109) Control Costsa ($ 106) Supply Shift (%)

Base Load Energy Existing   unaffected 95.08 169.0 0.00 0.00 New unaffected 1.07 1.9 0.00 0.00 New affected   notification only 2.59 4.6 0.01 0.00 New affected   notification and capital 0.92 1.6 29.04 1.77 Total 100.00 177.6 29.05 0.02 Peak Power Existing   unaffected 95.08 42.2 0.00 0.00 New unaffected 1.07 0.5 0.00 0.00 New affected   notification only 2.59 1.1 0.00 0.00 New affected   notification and capital 0.92 0.4 14.30 3.48 Total 100.00 44.4 14.31 0.03 Total 222.1 43.35 aRevenues and costs are in 1998$.

Figure 7 1 illustrates the supply shifts and shows the with regulation supply curve S 1. In this example, the regulation leads to an increased supply by unaffected existing units, crowding out the new units with add on capital costs.

7.2 Market Level Results The model projects the MACT standard will increase base load electricity price by 0.529 percent and peak power prices by 0.717 percent ( see Table 7 3). Domestic production declines by 0.534 and 0.665 percent, respectively.

The analysis also shows the impact on distribution of electricity supply ( see Table 7 4). First, it delays entry of affected new units with add on controls and testing requirements because price does not sufficiently increase to cover the costs of production for these units. Second, the increase in the price of electricity will make it profitable for existing unaffected sources to increase supply, displacing approximately 0.92 percent of affected new supply. This increase in supply implies that fewer older units may be retired as a result of the regulation. The remaining change in quantity results from decreased consumer demand as the prices of base load energy and peak power increase. 7 4 C E F Projected new source growth G S 1 S 0 D kWh Price ($/ kWh)

( Projected Demand)

B = New unaffected unit supply B+ C = Increase in supply from existing units D = New notification only F = Decreased quantity demanded due to price increase G = Affected supply that delays entry into the market until demand sufficiently grows a = Supply shift for new monitoring only units b = Supply shift for new testing and capital equipment units D B S 0 b a Figure 7 1. Market for Baseload Electricity 7 5 Table 7 3. Market Level Impacts of Stationary Combustion Turbines MACT Standard: 2005 Percent Change Energy Markets Price Quantitya Petroleum 0.019 0.010 Natural Gas 0.052 0.018 Base Electricity 0.529   0.534 Peak Electricity 0.717   0.665 Coal   0.244   0.244 Industrial Sectors NAICS Description Description Percent Change Price Quantity 311 Food 0.001   0.001 312 Beverage and Tobacco Products 0.000   0.001 313 Textile Mills 0.002   0.003 314 Textile Product Mills 0.001   0.001 315 Apparel 0.000 0.000 316 Leather and Allied Products 0.001   0.001 321 Wood Products 0.002   0.002 322 Paper 0.002   0.003 323 Printing and Related Support 0.001   0.001 325 Chemicals 0.002   0.004 326 Plastics and Rubber Products 0.002   0.003 327 Nonmetallic Mineral Products 0.004   0.004 331 Primary Metals 0.005   0.005 332 Fabricated Metal Products 0.003   0.001 333 Machinery 0.001   0.001 334 Computer and Electronic Products 0.001 0.000 335 Electrical Equipment, Appliances, and Components 0.001   0.001 336 Transportation Equipment 0.001   0.001 337 Furniture and Related Products 0.001   0.001 339 Miscellaneous 0.001   0.001 11 Agricultural Sector 0.003   0.005 23 Construction Sector 0.012   0.012 21 Other Mining Sector 0.002   0.001 Commercial Sector 0.002   0.002 aActual value for all 0.000 entries for the various sectors is >   0.001 and < 0. 7 6 In the natural gas and petroleum markets, both the price and quantity increase, indicating that an increase in demand for the fuel ( due to fuel switching) dominates the upward shift in the supply curve ( increased electricity costs as a fuel input). Price increases in these markets are below 0.1 percent. Price and quantity decrease in the coal market, reflecting the decreased demand for coal as electric utilities reduce output. Market level impacts on downstream product and service markets are less than 0.3 percent.