Electric Industry Restructuring:
Opportunities and Risks for West Virginia

 

Interim Report No. 3:

Implications for Electricity Producers
Part I

Submitted to:

Director of Operations
Governor’s Office
1900 Kanawha Boulevard East
Charleston, WV 25305

Submitted by:

West Virginia University
Electric Industry Restructuring Research Group
P.O. Box 6064
Morgantown, WV 26506

July 31, 1997

Table of Contents

PART I

3.0.0 Implications for West Virginia Electricity Producers

3.1.0 The Energy Industry in West Virginia

3.2.0 Potential Growth in the Energy Industry

3.2.1 The Regional Marketplace: Exent and Constraints

(i) Defining the Product: Energy versus Capacity

(ii) The Price of Electrical Energy in West Virginia

(iii) The Market for West Virginia Capacity

(iv) Regulatory and Institutional Constraints

3.2.2 Greater Efficiency Due to Competition and Marginal Cost Pricing

3.2.3 Improvements in System Planning

3.3.0 Transmission, Environmental, and Market Power Issues

3.3.1 Transmission Pricing and Access Constraints

3.3.2 Fuel Choice and Environmental Constraints

3.3.3 Market Power

PART II (Sections 3.4.0 through 3.4.5

NOTES

List of Tables

Table 3.1: Size of Selected West Virginia Industries (Appendix)

Table 3.2: Distribution of Coal Mined in West Virginia (1995) (Appendix)

Table 3.3 West Virginia Utility-Owned Coal-Burning Plants, 1995

Table 3.4: Average Variable Costs ($/MW hour)

Table 3.5: Assets and Costs of Power Plants in West Virginia (Appendix)

Table 3.6: Stranded Assets of Power Plants in West Virginia, Historical Production Basis (Appendix)

Table 3.7: Stranded Assets of Power Plants in West Virginia, Historical Production Basis (Appendix)

Table 3.8: Stranded Assets of Power Plants in West Virginia, Assumed Production Basis (Appendix)

Table 3.9: Stranded Assets of Power Plants in West Virginia, Assumed Production Basis (Appendix)

Table 3.10: Stranded Assets Price Elasticities, Historical Production Basis (Appendix)

Table 3.11: Stranded Assets Discount Rate Elasticities, Historical Production Basis (Appendix)

List of Figures

Figure 3.1: Average Variable Cost ($/MW hour) (not yet available in electronic format)

Figure 3.2: Supply Curve for West Virginia Region (not yet available in electronic format)

3.0.0 Implications for West Virginia Electricity Producers

The deregulation of the electrical generation industry in the United States will affect electricity producers and their suppliers, marketers, consumers, and regulators of electric power. This report addresses changes that may be experienced by the electricity energy producers, their suppliers, and the affects these changes may have West Virginia economy.

This report begins with an assessment of the energy industry in West Virginia, and the potential impacts of restructuring on revenues, employment, and development. A description follows of the possible regional marketplace of power produced in West Virginia, the markets for energy and capacity, and regulatory and institutional constraints. The next parts of the report explains why marginal cost is the relevant measure of the competitiveness of an energy and capacity producer. This is followed by a discussion of the possible improvements that can be made in system planning in a deregulated environment. We then turn to a discussion of the constraints imposed by transmission, environmental concerns, and market power and how they are likely to affect the opportunities available to West Virginia producers.

One of the major problems in the process of restructuring the electricity industry is the disposition of stranded costs and assets. Section 3.4 (Part II) discusses the problems in determining stranded costs and makes suggestions on how the problem may be resolved.

3.1.0 The Energy Industry in West Virginia

West Virginia is a major producer and exporter of energy. This takes the form of West Virginia-generated electric power transmitted out-of-state, coal shipped to generating plants in other states and around the world, and moderate quantities of natural gas shipped out-of-state. West Virginia’s plentiful energy resources and power generating capacity put the state in a position to benefit from the broadening of energy markets brought about by restructuring and competition in the electric power industry. Investment, employment, employee earnings, and gross state product in the state could all grow in tandem with increased sales of electricity, coal, and natural gas. On the other hand, even West Virginia’s relatively low-cost power generators will experience new competitive pressures on the prices they can charge.

Decisions taken outside of West Virginia will have a major role in determining the extent to which markets will expand for power generated in the state. Federal actions establishing wholesale competition and open and equitable access to transmission (Energy Policy Act of 1992, FERC Order 888) are already creating new opportunities. Individual states are deciding if and how to introduce retail competition in their jurisdictions. Because West Virginia has excess power generating capacity with low marginal costs, the state’s power plants (and the coal mines supplying them) will be better off the fewer regulatory, institutional, and physical barriers there are to electricity sales to customers in nearby states.

There are 21 utility-owned electricity generating plants operating in West Virginia with a total capacity of 15,157 MW [1]. There are also 4 non-utility power plants with capacities of at least 10 MW each, totaling 322 MW. The 14 utility-owned, coal-fired steam plants account for nearly all the state’s generating capacity—15,039 MW. In 1995 these 14 plants generated over 77.1 million MWH while burning 30.8 million tons of coal and employing over 2,750 workers [2]. Power generation and the rest of the electricity industry also contribute substantially to employee earnings and gross state product (GSP) in the state. Table 3.1 shows that the Electric, Gas and Sanitary Services sector employed 12,173 and paid $640 million in employee earnings in 1996. The over $2.5 billion of GSP that the sector generated in 1994 equaled 7.2% of West Virginia’s total GSP.

Two-thirds of the electricity produced by West Virginia power plants is sold outside the state. Retail sales of electric power to West Virginia consumers totaled 26.0 million MWH in 1995, resulting in $1.4 billion in revenues [3]. This means that West Virginia’s net export of electricity to out-of-state buyers was approximately 51 million MWH. In addition, West Virginia indirectly exports electricity embodied in energy intensive industrial products produced in the state. Industrial customers were the largest class of in-state retail consumers by quantity of power purchased—10.8 million MWH.

As large as West Virginia’s electric power generation industry is, it could produce much more under competitive electricity markets. The capacity-weighted average of the utilization rates in the 14 utility-owned, coal-fired steam generating plants was only 58.5 percent in 1995. Under most circumstances, capacity utilization rates of at least 70 percent are operationally feasible. The marginal costs of generating additional power at coal-fired plants that are operating below capacity are quite low. At the state’s 14 major generating plants in 1995 the average operating cost was $17.45 per MWH of which $13.37 was for the coal burned [4]. While a couple of the plants (Rivesville, North Branch) have much higher costs, most of the state’s existing power plants could sell additional power profitably for less than $20 per MWH (before transmission and distribution charges).

Investment in new electricity generating plants is an additional economic development opportunity that electricity market restructuring will create for West Virginia. In the near term all these new generating plants are likely to use natural gas to drive turbines (including combined cycle). As new investments, natural gas generating plants have the advantages of lower capital costs and more flexibility in size without loss of efficiencies in scale. West Virginia has an ample supply of natural gas; in 1995 the state produced 186.2 billion cubic feet and had net exports of 53.1 billion cubic feet [5]. There is at least one proposal currently pending for a new, natural gas-burning generating plant in West Virginia.

West Virginia’s long-term prospects for investment and employment in electricity generation are much harder to predict. Eventually, as the quantity of electricity consumed grows and competition tends to drive down the price of electricity, the state will exhaust the easy opportunities to expand generation through higher capacity utilization of the coal-fired plants and new generating plants running on the state’s extra supplies of natural gas. In addition, the older coal-fired plants will reach the point where they will need major refurbishments to continue operating competitively. At this point, the economic criteria for continued growth of electric power generation in West Virginia will become more strenuous. In order to have an incentive to produce power, investors in new or refurbished generating plants will have to cover not only their operating expenses, they will also have to expect an excess of operating revenues over expenses great enough to cover their capital costs and a reasonable rate of return. Otherwise, the new investments will not be made. Whether these investments in West Virginia generating capacity continue in the long term will depend on future fuel costs, other operating costs including state taxes, developments in generating technology, environmental regulation, and competitive conditions in the regional (multi-state) electricity market.

The bulk of the employment opportunities that electric industry restructuring creates for West Virginians will be in coal mining rather than directly in the electric industry. Expanding generation at the under-used coal-burning generating plants does not require much additional employment because of the economies of scale in operating those plants. However, for every additional million dollars of coal purchased from West Virginia mines, 12.9 additional West Virginia jobs are created — 2.9 of them in coal mining and the rest indirectly from the multiplier effect of mine operating expenditures recirculating throughout the state economy [6]. Although employment in coal mining has been declining for many years due to gains in efficiency, it still accounted for 2.7 percent of total West Virginia employment in 1996, as well as 8.9 percent of GSP in 1994 (see Table 3.1).

Most of the coal mined in West Virginia is burned in utility power plants. Table 3.2 summarizes the shipments of coal from the state’s mines in 1995. Of the 165.2 million tons of West Virginia coal shipped that year, only 29.1 million tons stayed in-state. Other domestic customers received 91.8 million tons from West Virginia and 44.3 million tons were exported. Ohio and Pennsylvania are by far the largest out-of-state markets for West Virginia coal, but the mines also sold substantial quantities to many states in the South, Mid-Atlantic, and North Central regions of the country. Most of the international exports were sold to Europe and Canada.

Considerably more West Virginia coal is consumed in electric utility generating plants in the rest of the country than in West Virginia itself. Coal consumption at West Virginia utility power plants was 30.7 million tons in 1995 (6.0 million tons were imported into the state)—only a third of the quantity shipped to other states [7]. This means that the impact of electric industry restructuring on West Virginia’s economy will depend on what happens to coal-burning power plants throughout the region, not just in West Virginia. Demand for West Virginia coal from electric generating plants throughout the region is likely to increase for two reasons. First, competition will tend to drive down the average price for electricity in the region, which in turn will increase the quantity of electricity consumed and generated. Second, following the same logic that applies to the coal-fired plants in West Virginia, coal-fired generating plants throughout the region will be well positioned to increase the quantity of power they sell, because they generally have low marginal costs for producing additional electricity. On the other hand, the market for coal is already highly competitive, so the effects of electric industry restructuring on coal prices will be limited.

As a major producer and exporter of energy in the form of electricity, coal, and natural gas West Virginia’s economy stands to benefit from electric industry restructuring. The more open and the more competitive electricity markets are in the surrounding states, the better. Production and GSP will increase in the generating plants and the coal mines. Employment will also be greater than it would have been, especially in coal mining and the businesses that sell to the mines and their employees.

3.2.0 Potential for Growth in the Energy Industry

Competitive markets, while increasing efficiency, also create winners and losers. Low-cost producers always do well when markets are fair and competitive, and West Virginia is a low-cost producer of electricity. Therefore, with their location near higher-cost producers in Northern Ohio and the East Coast, West Virginia producers are well-positioned to gain from the move to more competition in the electricity industry. As we debate about the distribution of these gains, West Virginians should not lose sight of the central fact that restructuring of the electricity industry represents a significant economic opportunity for West Virginia. It is in West Virginia’s interest to promote vigorous competition in those markets.

Most of the gains to West Virginia producers in the short run will come from increased access to high value markets in other states. West Virginia already is an active exporter of power: about 70% of the power generated by plants in West Virginia is currently consumed in other states. FERC’s policy of open transmission access is likely to increase this figure with respect to wholesale markets, and the current movement toward retail wheeling is likely to increase it even further.

The market in which West Virginia power producers operate will be determined by the costs of their competitors, and the availability and cost of transmission services. West Virginia exports may displace production in other states in two primary ways. First, existing West Virginia plants with low operating costs will be able to underbid existing plants in other states that have higher operating costs. Second, system planners in other states looking for new sources of baseload power are likely to notice the cost advantages of generating plants located near fuel sources (and away from environmentally sensitive population centers) in West Virginia. Although new coal plants are not economically viable at present, increased utilization and repowering of existing plants in West Virginia could be the central pillar of the future electricity supply for the Mid Atlantic region.

In reality potential growth for export of power from West Virginia to Northeastern markets is currently limited due to transmission constraints in the APS/PJM/Virginia Power interface. At the present time, export of power from west to east at this interface is less than 4,500 MW. As discussed in more detail in a subsequent report, this limitation could be partially alleviated through the use of power electronics devices.

3.2.1 The Regional Marketplace: Extent and Constraints

This section of the report concerns the definition of the geographical region in which West Virginia generation is likely to be competitive. The geographical extent of West Virginia’s electricity market is largely defined by the area in which West Virginia producers have a cost advantage over other producers. Because of their proximity to fuel sources and East Coast load centers, West Virginia electricity producers should be very competitive in the regional power market. In practice, this market will be constrained at times by institutional features such as state regulatory practices, by unavailability of transmission services or by inefficient transmission pricing. For purposes of analysis we will ignore these constraints initially and focus on the geographical market that would be available to West Virginia producers if they were unconstrained in their ability to reach customers. Then in the next section we will consider the impact of transmission constraints and discriminatory regulatory or transmission pricing practices.

Moving from a regulatory model to a market model for the electricity industry requires moving the focus of analysis from average historical cost to marginal cost. Traditionally, regulation has pegged the price of electricity at embedded cost, which is the average total cost of electricity production, including historical capital costs. In a competitive market, however, prices are quickly bid to marginal cost. Marginal cost is the operating cost, or variable cost, of the most efficient incremental source of power.

(i) Defining the Product: Energy Versus Capacity

To understand the extent of the market for West Virginia electricity, it is necessary first to recognize that electricity consists of at least two separately identifiable, but closely related, products: energy and capacity. Capacity, usually measured in megawatts (MW), is the ability to meet the demand for power (in MW) imposed on the system at any given instant. Energy, usually measured in megawatt-hours (MWh), is the actual application of power over time. A megawatt-hour of electricity is simply a megawatt of power, sustained for an hour.

For example, electricity prices in the Mid-Atlantic / Ohio Valley wholesale market are low because wholesale electricity markets are competitive and there is excess generation capacity. In a competitive wholesale market where there is excess capacity, the marginal cost of capacity becomes zero, so price declines to cover no more than the variable cost of production. The payments of captive retail consumers in a regulated market assure a higher rate of return for the stockholders than they would receive in a competitive market, but they do not affect the willingness of producers to sell wholesale power and hence they do not affect the competitive price of that power.

Variable cost is the sum of all costs that a producer can avoid by simply not producing. A producer faced with the choice of selling at a price barely above variable cost, versus making no sale at all, will therefore make the sale, even though that price will not cover fixed capital costs. Consequently, when competition forces price downward to the lowest price acceptable to producers, it will fall to the variable cost of the marginal supplier, regardless of sunk (i.e., historical) capital costs. Capital expenditures already sunk into existing plants are therefore irrelevant in determining the potential geographical market for West Virginia electricity.

Capital cost does matter when considering the market for longer-term, firm sales of capacity and energy. But even in this case the market price is not affected by the historical cost of existing plants. What does affect the market price is the cost of providing additional capacity in the future. As in the case of energy, if no better price is available on the market, an owner of existing capacity will be willing to commit that capacity to a buyer, as long as the price offered equals or exceeds the cost of providing that capacity. As long as there is plenty of idle or excess capacity available to buyers, the seller will not have any alternative use for that capacity, and will therefore be willing to sell it at a price very near zero.

If the buyer wants a commitment of capacity far out into the future, however, the seller will take into account the possibility of a future capacity shortage. When capacity is short, there will be alternative buyers for that capacity, and its price will be bid upward. Both buyers and sellers will anticipate the risk and expense associated with future capacity shortfall. Therefore, for a capacity commitment over a term extending into a period of possible capacity shortage, the market price must be sufficient to reimburse the seller for the risk that he will have to build new capacity to fulfill his commitment.

The price of firm power, which is energy plus capacity, therefore typically exceeds the variable generation cost of energy alone. By the same token, in a period of capacity shortage the price of energy will also exceed its variable generation cost. This is so because when capacity is short, providing energy to one customer requires denying energy to another, and therefore the seller’s cost of providing energy to one customer is the price that the other customer would have been willing to pay.

Thus, when looking at the price of electricity and the extent of the market it is important to first clearly define the product being sold. If the product includes a commitment to set aside capacity (which will be so only if it commits to a delivery of energy in a period of possible or actual capacity constraint) then the market price of the product will exceed the variable generation cost of the market’s marginal plant. If the product is pure energy with no commitment to set aside scarce capacity, its competitive market price will equal the variable generation cost of the market’s marginal plant.

To the extent that prices available in energy markets equal or exceed the cost of building new capacity, sellers will build new capacity. Therefore, to determine the extent of the market for West Virginia electrical energy we should consider only variable generation costs of delivered energy. To determine the extent of the market for West Virginia electrical capacity during future periods of capacity shortage, we should consider the capital cost of new generation capacity. For both energy and capacity markets, we must ignore the sunk capital costs of existing generation plants in West Virginia and elsewhere.

(ii) The Price of Electrical Energy from West Virginia

In an energy market with excess capacity, the geographical extent of the market and the market price at each location are determined by the variable cost of generation plus transmission to that location. In such an environment, West Virginia’s electricity producers would be able to displace other sellers that have higher variable cost. Transmission costs and constraints are obviously important, but are a complex topic that requires separate treatment. In this section of the report, we will look at generation costs in the region near West Virginia, and deduce the extent of the markets in an ideal world in which transmission is unconstrained and the cost of transmission equals line losses only. In a subsequent report we will look at how transmission constraints and inefficient tariffs would modify the general shape of the markets outlined in this section.

Table 3.3: West Virginia Utility-Owned Coal Burning Plants, 1995

There is a general consensus that West Virginia is currently in a capacity-rich environment. West Virginia’s coal-fired, utility owned power plants operated at 58.5% capacity factor in 1995; that is, they produced only 58.5% of the energy that they could theoretically have produced in that year. (See Table 3.2.) Allowing for outages for maintenance and a reasonable reserve margin, the system could probably operate at a capacity factor of 70% or better. Availability could go considerably higher for some plants as their operators respond to market incentives; some independent power producers, who generally are paid only when they produce energy, report availability around 90% [8]. Therefore, there is reason to believe that significant additional energy could be sold from West Virginia power plants without significantly reducing the reliability of the system.

In a competitive market this excess West Virginia generation should be economically attractive, especially in states to the north and east. A general notion of the location of West Virginia’s potential customers and competitors can be obtained from Table 3.4 and Figure 3.1 (not yet available in HTML), which show the average variable cost of the electricity produced by utility-owned power plants operating in West Virginia and nearby states in 1995. Relatively expensive states that are clearly potential customers include Maryland, Pennsylvania, Ohio, Delaware, and New Jersey. Virginia is the major competitor for East Coast markets, while low costs in Kentucky, Tennessee and Indiana will tend to limit the market for West Virginia generation in the Midwest.

Table 3.4: Average Variable Cost ($/MW hour)

To compete, producers in West Virginia will have to obtain transmission access to lucrative out-of-state markets. Assuming for the present that there are no problems of transmission access, no transmission constraints, or even any transmission tariffs, transmitting the electricity to customers in other states will still involve costs in the form of line losses due to line heat loss and reactance. The amount of these line losses is variable, depending on distance, voltage, and loading. In 1989, the FERC Transmission Task Force surveyed a wide range of data and publications, and concluded, "For a typical 100-mile, 345-kV line, losses are roughly 1 to 3 percent of the power transferred," (losing about 50 cents per MWh for a typical West Virginia baseload plant), and will increase more than proportionally for longer distances [9].

From the center of West Virginia to the center of the PJM power pool is about 300 miles, so line losses are likely to increase the cost of West Virginia power by 10% or more (to about $19.50/MWh) in PJM, which is competitive with costs of steam generating power plants in Maryland (about $19.70) and Eastern Pennsylvania ($19.40), and far less expensive than similar plants in Delaware ($27.90) or New Jersey ($37.40). Although it is often assumed that transmission constraints will not allow West Virginia producers to reach the New York or New England Power Pools, it is interesting to notice that variable costs of utility-owned steam generating plants in New York ($27.50) are more than 50% higher on average than in West Virginia, which would put them within the West Virginia market area. Looking northwest, Cleveland Electric Illuminating has an average variable cost of about $24.50, which is more than 40% above the average cost of production in West Virginia, and 25% above the variable cost of the under-utilized Fort Martin plant in northern West Virginia. Ignoring transmission constraints, then, the most likely customers for West Virginia power plants are therefore in the PJM power pool and northern Ohio.

There are other generation sources in the region capable of serving PJM and Cleveland, of course. In a competitive regional market for electrical energy, the energy spot price at any location will be set hour by hour by the intersection of supply and demand, where supply is the sum of availability from all generating sources and demand is the sum of loads from all customers. Line losses will gradually increase the delivered cost of the power from any one generator, and along with other transmission costs and constraints, this will limit the area that it can economically supply. The same transmission cost considerations will also limit the area over which any particular customer will find it economical to search for a generator. Each generator would therefore see a demand curve unique to its location, and each buyer would see a unique supply curve as well. To speak of "the" overall supply and demand for electricity, therefore, is an abstraction. However, in order to get a general idea of the market facing a typical West Virginia producer it is useful to ignore transmission costs and constraints and look at supply in West Virginia’s market region.

Figure 3.2 (not yet available in HTML format) shows a supply curve for the West Virginia market region, again ignoring transmission constraints and line losses. On the horizontal axis is generation capacity (nameplate) in megawatts. Each dot represents a plant, and its horizontal distance from its neighbor to the left represents the nameplate capacity of that plant. On the vertical axis is the average variable cost associated with that plant, which is the minimum price required to induce its owner to turn it on. Thus, for any given level of demand, we can read the supply price from the height of the curve in Figure 3.2. Conversely, for a given market price, we can read the quantity that producers would be willing to supply from the position of the curve relative to the horizontal axis at that price. For example, if the competitive market price of power were $20/MWh (2 cents per kWh), then sellers in this region would offer about 60,000 MW of power. Since the supply curve is very flat at a price near $20, (i.e., prices near $20 correspond to a wide range of quantities supplied) we can assume that the market would clear at a price near $20 most of the time.

According to the Northeast Reliability Council (NERC), summer peak demand in the East Central Area Reliability Coordination Agreement (ECAR) region is about 90,000 MW. Adding the summer peaks of all utilities in the West Virginia market region also gives a value of about 90,000 MW. If all generation assets were available and ready to produce, (and no imports were available from other regions) the chart indicates that the competitive market price for 90,000 MW would be about $26/MWh. The peak price would be about $35/MWh if the supply curve overstates available generation by 10%, and around $40 if the supply curve overstates available generation by 15%. At winter peak (about 80,000 MW), the corresponding figures would be roughly $24, $26, and $28. Average production in the West Virginia market region (calculated by dividing total 1995 regional energy production in megawatt-hours by the number of hours in a year) was 60,000 MW, which, as mentioned before, corresponds to a price of $20. Thus, the shape of the supply curve suggests that the price of electric energy in West Virginia’s market region is likely to vary between $15 and $50 per megawatt-hour, but it can be expected to lie near $20 most of the time.

(iii) The Market for West Virginia Capacity

Electric energy is a basic commodity product that might be sold on a spot market. Usually, however, it is sold by contract along with some capacity; that is, the seller promises the buyer to provide up to a certain amount of power (MW) as needed for a given term. Such a firm commitment of capacity provides a level of assurance that is valuable, even essential, to most customers. The ability of West Virginia producers to provide firm capacity, and the willingness of out-of-state customers to purchase it, depends on two things: the availability of firm transmission capacity between West Virginia and major load centers, and the delivered price of the power at those load centers.

The price of firm capacity varies with the time length and period of the contract, the location of the load, the degree of firmness, and the amount of other services bundled with the service. Although several exchanges, including the Continental Power Exchange (CPEX) central U.S. forward market, the New York Mercantile Exchange’s western (California-Oregon and Palo Verde) futures markets, and the PJM interconnection, allow some price discovery for short-term sales, information about the prices and terms of contracts is sketchy. Currently, short hourly price histories for PJM are available for downloading from its website; they indicate that hourly market-clearing prices for short-term firm power range from near zero in the early morning to a high in the afternoon upwards of $60 (4 PM on 9 July 1997), although a high near $25 to $30 is more typical in summer 1997. Weighted average daily prices from March to May of 1997 ranged from $14 to $23, most days averaging between $20 to $23.

Thus, for short-term firm energy sales, the capacity charge is minimal on most days, even in the PJM system. This is because with the current abundance of generation capacity there is very little additional expense associated with assuring capacity availability for the short term. Transmission interconnections within ECAR (i.e., from West Virginia into Ohio and western Pennsylvania), have adequate capacity to serve current needs. However, the prices in this region tend to be low, so it is not a highly attractive market for incremental sales. For short-term contracts of up to a year in length, Allegheny Power recently stated that the market price for "round-the clock (7 days times 24 hours) annual financially-firm power purchases during 1997 in the eastern ECAR region is $18.00 - $19.00 /MWh" [10]. CPEX reports somewhat lower prices, but with wide variation in daily minima, maxima, and averages. CPEX daily average prices (which include transmission) most often are in the upper teens. Firm power coupled with ancillary services such as load balancing, reactive power, spinning reserves, etc, goes for $25 to $30 in this region, according to Allegheny Power. Although load growth is reasonably steady, most observers expect that capacity will tighten earliest, and higher prices will appear soonest, along the East Coast.

To reach East Coast markets, West Virginia power will need to flow through the APS-PJM-Virginia Power Interface. Firm contracts of annual or greater duration will need to be coupled with firm transmission capacity over this interface. Maximum interchange over this interconnection during peak load is about 2500 to 4500 MW in summer, and 2200 to 3200 MW in winter [11]. Although NERC expects this interface to "perform adequately" for now, it notes that "In the past this interface has been heavily loaded, requiring the establishment of a joint APS-PJM-VP Reliability Coordination Plan." Thus, there is some reason for concern that West Virginia producers may not be able to offer much additional firm power through this interface to the lucrative Northeast power markets. The application of recent advances in power electronics should relax this constraint to a certain extent, as is discussed in a subsequent report.

For the longer term, the situation is more problematic. There is little certainty as to when demand growth will outstrip the ability of the current system to serve it; there is even a vigorous debate at present as to how much demand the current system is equipped to serve. Open questions include how much capacity should be held in reserve, how much transfer capability exists, how strongly consumers will react to any price changes, and whether interruptible rates will entice some customers to reduce their peak demand.

There is more agreement as to the price range necessary to induce the construction of new gas-fired generation capacity. Most observers believe that the current generation of gas-fired combined cycle generators and combustion turbines can be built profitably at an electricity price below $35, perhaps as low as $30 per MWh. Recent technological advances have produced natural gas-fired combustion turbines that are small, light, transportable, clean, and very efficient. The installed capital cost of these plants is often at or below $300 per kW, according to UDI data and other reports in the trade press, which would make them competitive with spot market electric energy at a delivered price of $35 to $45 per MWh [12]. Of course, these costs are very sensitive to the price and availability of natural gas, and especially to the load factor of the plant. However, there is a strong technological trend toward lower costs and wider use of gas generation located near loads.

Distributed generation, defined as the production of electricity by small capacity generating units located near the load, is attractive for capacity additions because small units are financially less risky than large central stations, and they do not pollute much. Although West Virginia producers can easily compete with new gas-fired capacity using existing plants, a higher price would be required to entice new plants to locate in West Virginia. New greenfield coal-fired generation will require a higher market price (perhaps $40/MWh or more) to be profitable. On the other hand, repowering of some of the older existing coal plants is less expensive, since transmission lines are already in place and the sites are already established. However, new plants must comply with increasingly stringent clean air standards.

Market forces will gradually drive the price of electric energy higher until it reaches a level sufficient to induce construction of new generation capacity. As load growth and plant retirement occur, the demand for electric power will reach the right-hand side of the supply curve more and more often, increasing the average market price and increasing the frequency and severity of price spikes. As prices increase, there will be a transition period in which first the repowering of existing plants will be economic, and then new greenfield power plant development will become more and more attractive. Although new plants could in theory be built to supply the spot market, in a capacity-short environment large customers and aggregators seeking shelter from electricity price fluctuations will be willing to negotiate longer term firm power contracts with generation providers. The reluctance of producers to build at an unprofitable price, and the lack of alternatives for consumers, will drive the price of firm power contracts upward. Contracts will emerge that reflect the full cost of the new plants, and their assured revenue streams will make financing easier to obtain.

Overall market prices can therefore be expected to ramp up slowly as current capacity is increasingly utilized. But this price increase is inevitable regardless of whether or not the industry is restructured, and there are several reasons to expect that these future price increases will be smaller in a competitive market than in a regulatory environment. First, a regulatory environment’s assurance of cost recovery has fewer and weaker incentives for cost reduction and parsimonious capacity planning. Second, customers are likely to utilize existing capacity more efficiently in a market-based environment because of incentives from real-time pricing, interruptible rates, and other peak-shaving options. Third, producers are likely to utilize existing capacity more efficiently since (as experience with IPPs suggests) if a plant produces revenue only when it is actually operating, its availability increases.

(iv) Regulatory and Institutional Constraints

Federal or other State governments could implement policies that disrupt these emerging markets and discourage West Virginia’s electricity producers from reaching their customers. For example, a state could attempt to collect stranded costs through a discriminatory tax on out-of-state producers, although such an attempt would almost certainly run afoul of the Commerce Clause of the U.S. Constitution. With the amount of money at stake, however, there are likely to be creative solutions offered to keep low-cost competition out of currently high-cost states.

Environmental standards have become a weapon in the battle to exclude low-cost competition from high-cost utilities’ service areas. The desire to protect high-price electricity markets has increased political support, especially in the Northeast, for applying stricter clean air standards to power plants in the Ohio Valley. While the adverse environmental effects of increased coal burning are a legitimate concern, some unusual alliances have been developing between environmentalists and utilities with high operating and capital costs, notably Public Service Electric and Gas (PSE&G) of New Jersey. If implemented, the proposed new "new source performance standard" (NSPS) rules for NOx proposed by the EPA in July 1997 [14] (will reduce the competitiveness of new coal-fired generating plants relative to gas-fired plants. If a state were to apply NSPS rules to all sellers within its jurisdiction, as has been proposed by some utilities and environmentalists, it could effectively lock out West Virginia coal-based generation.

Stranded cost recovery in other states, if implemented in a nondiscriminatory manner, will be only a limited barrier to West Virginia producers. Most plans that are being proposed and implemented collect stranded costs in the form of a surcharge (called a Competitive Transition Charge, or CTC, in Pennsylvania and California) on distribution. If implemented nondiscriminatorily, this charge would be levied on all transactions that use the distribution system, and would appear on the customer’s bill as part of the charge for distribution. The generation portion of the rate would still be determined in a competitive market, and competition would force it to equalize across states. This could hurt West Virginia producers to the extent that this extra charge increases the delivered cost of electricity relative to its substitutes (such as conservation or gas) and therefore motivates consumers either to reduce their consumption of electricity, or to produce their own electricity on-site using distributed generation. However, the CTC in most states should be of limited duration, in most cases three to five years.

The transmission system and its tariffs could also be designed to discriminate inefficiently against West Virginia producers and reduce their ability to compete for high-value customers. If, for example, the transmission tariff were a single "postage stamp" rate within ECAR reflecting average costs for the ECAR region, West Virginia producers at its eastern edge would have to pay that cost, plus PJM transmission costs, to reach customers connected to PJM. There is no equity argument in favor of forcing buyers in PJM who want to reach producers in West Virginia to pay part of the costs of transmission lines located in Indiana. There is also no efficiency argument in favor of a westward looking postage stamp rate. On the contrary, the efficient transmission rate for a given transaction equals the additional cost imposed on the system by that transaction, and the West Virginia - PJM trade would not impose most of its costs on the Midwest. Thus, a "westward-looking" postage stamp rate could significantly and inefficiently reduce the ability of West Virginia producers to reach their natural customers on the Atlantic coast.

3.2.2 Greater Efficiency Due to Competition and Marginal Cost Pricing

The power of market-based incentives to motivate cost reduction and efficiency is well established, both in theory and in practice. Because these incentives are crucial to justifying a move to competition it is vital that policy makers design a market system that allows such incentives to function effectively. This section of the report describes these incentives, explains their source, and describes the extent—and limits—of their effectiveness.

There are three major mechanisms by which increased competition over a wide market region could lower costs and raise efficiency, relative to traditional regulation. First, prices in a competitive market are driven by marginal cost, which motivates efficient consumption, efficient short-run production decisions, and service innovation. Second, as West Virginia baseload plants increase their geographical service area to include their competitive market region they will increase and level out their production, allowing them to run more efficiently. Third, market prices efficiently signal producers where, when, and how to build new generation plants, and give producers an incentive to minimize the overall cost of production in the long run.

The significance of marginal cost pricing can not be overstated. In a competitive market, price is driven to marginal cost (cost of providing the next kilowatt-hour), which rises and falls with the current level of demand. Under traditional cost-of-service regulation, in contrast, most customers pay a rate that reflects average historical cost, which is capital plus operating cost, averaged over space and time. Because average cost rates are insensitive to the daily and seasonal fluctuation of production costs, they provide little or no incentive for customers to find a way to shift their demand away from the high-cost peak periods.

Marginal cost pricing under competitive conditions will motivate the introduction of innovative service options. When consumers pay, and producers receive, a traditional rate based on average cost of service, the incentive to curtail demand or augment capacity at peak periods is weak. Similarly, under traditional ratemaking the costs associated with reliability are averaged over customers, so customers tend to get the same level of reliability, regardless of its value to them. Competitive pressures will increase the incentive to implement time-of-day rates and other responsive pricing plans, truly interruptible contracts, and separable back-up power services to tailor reliability to individual customers’ needs, and also will increase incentives to search for creative new methods to reduce peak loading problems. Competitive pressures will also increase the speed of implementation of new metering and control technologies that will be required to support these services.

Second, wider markets will lower production costs by increasing capacity utilization. Large coal-fired power plants run most efficiently when their plant capacity factor is highest—that is, when they run near capacity most of the time, without much fluctuation in production. The marginal cost of West Virginia’s existing generating plants is low relative to that of other producers similarly situated in the Mid-Atlantic region; hence, West Virginia’s plants would most likely run at a higher capacity factor if the regulatory and transmission constraints on their ability to reach markets were removed. As plants produce more efficiently and spread their capital costs over more sales, the costs per kilowatt-hour will also naturally decrease.

Finally, cost-based regulation faces limits on its ability to motivate producers to reduce costs and invest wisely. It is very difficult for a regulator to assess whether or not a given expenditure is necessary, and a utility is more likely to make an unnecessary expenditure when it knows that revenues will increase sufficiently to recover it. A market is pitiless, however, and it will punish unnecessary expenditures. In the market a producer recovers the capital cost of a new plant, not by convincing a regulator to allow cost recovery, but by ensuring that its running cost is below the market price of electricity. Such a system, in which producers stand to gain financially from cost-cutting, is certain to lead to more efficient operating and investment decisions. Markets will therefore motivate producers to reduce operating costs in all plants, to retire uneconomic plants, and to invest in new plants only when they are economically viable and therefore needed.

It must be emphasized that these benefits from a competitive market will accrue only to the extent that the market is truly competitive. Competition motivates a producer to make each sale profitable, and to make every profitable sale -- which is to say that competition motivates a producer to cut costs to the bone and to produce without discrimination for all customers who will pay the market price. Benefits will be less if institutional factors prevent free competition, or if producers and transmission owners are able to exercise market power.

3.2.3 Improvements in System Planning

Much of the rationale for electricity industry restructuring centers around concern about perceived shortcomings in the regulated industry’s performance in planning and building generating plants. Why might the market be expected to do a better job than the regulated system in this regard? Some perspective on this question may be gained by looking at the history of the industry.

Until the early 1970’s, energy prices were low and stable, concern about pollution was overshadowed by trust in economic progress, economies of scale in power plants appeared to be endless, and demand for electricity followed an easily predictable path. Predictability of demand kept the risk of building new generating plants relatively low, regulators helped keep capital costs low by promising cost recovery from captive customers, and so ever larger power plants were built. Despite some doubt among academic economists [15], it was widely believed that the entire electricity supply system was a natural monopoly, and that competition in any phase of it would be impossible. The "regulatory compact" was intact and working well, but it had not been tested by adversity.

All of these factors came to an end in the 1970’s. Sudden increases in oil prices, newfound insecurity about energy supply, and economic stagnation meant that demand for electricity began to fall short of expectations. At the same time, a new generation of baseload nuclear power plants was being completed and brought online, setting the stage for the surplus capacity that we are experiencing today. The Three Mile Island accident in March, 1979 spurred new and expensive regulations on nuclear power while the Clean Air Act imposed increased costs on coal-fired generation. The disappointing availability record of the new generation of "supercritical" steam plants made it clear that economies of scale in generation were being fully exploited [16].

Amid a widespread public fear of energy shortage, rising energy bills, and a newfound distaste for large power plants, Congress passed the Public Utility Regulatory Policies Act (PURPA) in 1978. No legislation since the Federal Power Act has had greater impact on the industry, both as a predictor and catalyst of future trends. The largely forgotten Title I of PURPA called for marginal cost pricing of electricity, which we are beginning to see twenty years later. Title II of PURPA opened up the electricity market to entry by certain classes of small generators (renewable fuels and cogeneration "qualifying facilities" or QFs), and mandated that utilities purchase their energy and capacity at a price ("avoided cost") that was intended to approximate marginal cost. The states implemented PURPA unevenly, some (notably California and New York) setting the avoided cost price at a level well above any reasonable calculation of marginal cost. Despite dire warnings from utilities of reliability problems due to PURPA power, the integration of PURPA generators onto the previously tightly controlled monopoly system went smoothly, if expensively.

While PURPA was demonstrating the technical feasibility of incorporating non-utility generation, events conspired to make small generators more economically attractive as well. First, due to environmental regulation and engineering problems, the cost of large (especially nuclear) generation plants increased. This additional expense, together with a chronic shortfall of electricity demand relative to expectations, led to the regulatory disallowance of generation construction costs in many cases across the country. This trend culminated dramatically in the bankruptcy of Public Service Company of New Hampshire (PSNH) due to disallowed expenses of the Seabrook nuclear power plant. The demise of PSNH sounded the death knell for the traditional regulatory compact. It was now graphically clear to utility executives and investors that ratepayers would not assume all significant risks of construction cost overruns or capacity overhangs.

Nearly simultaneously with the end of the PSNH debacle, the price of oil and natural gas plunged in 1986. Steady improvements in the technology of gas-fired combustion turbines and combined-cycle plants, along with the lower risk of overcapacity associated with the small capacity increments they provide, made them increasingly attractive relative to traditional large coal-fired and nuclear plants. It should not be surprising therefore that although 95 large (greater than 400 MW) utility-owned power plants either were completed or received their most recent additional units from 1980-1985, only 11 did so from 1990-95. Among non-utility generators, 50 units larger than 100 MW were completed from 1990-95, whereas only 15 were completed from 1980-85 (no non-utility built a plant larger than 360 MW) [17].

The trend is clearly toward smaller, non-utility generation, and for four good reasons: a more open transmission system means that the electricity marketplace is more open to independent generation than ever, large capacity additions are riskier than small ones, the regulatory system has demonstrated the limits of its ability and willingness to guarantee recovery of large capital expenditures, and there are currently diseconomies of scale in generation. On the other hand, information about system needs may flow better within a vertically integrated traditional utility [18], and vertically integrated utilities may perhaps have a greater incentive to build their generation and transmission equipment to ensure system reliability [19].

Is the era of construction of new coal-fired central power plants over? Despite investment patterns of recent years, and despite proposed changes in environmental regulations [20], the answer is almost certainly no. Larger power plants have a larger share of their costs arising from capital expenditures, and are therefore less sensitive to fuel price fluctuations than smaller plants. Thus, if and when fuel prices (especially natural gas prices) rise, large plants will become more economical. The riskiness of these investments can be controlled in several ways; for example, as capacity becomes more scarce electricity buyers will be more willing to commit to longer-term bilateral contracts with plant developers at a fixed price. We can expect that the market will provide incentives for the construction of new plants when there is a high likelihood that consumers will be willing to pay for them.

There is little doubt that patterns of investment will be different under a market system than under the traditional system. Will the market bring forth sufficient investment in new generation capital? Under a market system, cost overruns are less likely because profit is tied to performance. The regulatory system’s attempts to replicate this function of markets, through prudency reviews and other administrative oversight, have a spotty record during the last twenty-five years of price and demand instability. Many utilities have complained that their shareholders have been made to take a loss when a plant is less useful or more expensive than expected, but may not retain extraordinary profits when a new plant is more valuable or cheaper than expected. This regulatory limit to the upside potential of a new investment deters investment in plants, and it will be removed as generation moves to a competitive model.

Will the new generation be built in time to avoid reliability problems? Some observers have suggested that market pressures will cause generators to cut costs by avoiding building new plants until the reliability of the system breaks down. This is a significant risk if those who make the decisions about building new capacity are insulated from financial risk in the event of power failure. To avoid this outcome, it is probably sufficient that regulators and other policy makers do not provide government insurance against liability in the event of power failure. As we saw in the Savings and Loan debacle of the late 1980’s, when the government assumes financial liability of failure, it will increase the probability of the failure occurring, due to the phenomenon known as moral hazard. If some party in the private sector takes on the liability for failure, that party will take responsibility for the continued reliability of the system, and will have an incentive to do a superior job of weighing costs and benefits to decide upon the efficient level of reliability.

3.3 Transmission, Environmental, and Market Power Issues

3.3.1 Transmission Pricing and Access Constraints

Transmission pricing will remain regulated, and the details of its regulation will have profound implications for the competitive generation market. Transmission pricing will strongly influence, even determine, the patterns of electricity trade, the location of new generation facilities, and even the viability of large central generation stations. The ideal transmission pricing system will create pricing incentives that minimize the system cost of serving market demand for energy and capacity.

Several transmission pricing plans have received widespread attention in the academic and trade press. These methods can be divided broadly into three categories: contract path methods, short-run marginal cost methods, and postage-stamp methods. The "Report on Wheeling Costs" [21] summarizes these categories and their relative advantages and disadvantages, and names some proposals that fit broadly within each of these categories.

The traditional method of transmission pricing involves first specifying a contract path for a given transaction, then charging a transmission tariff for every system along the contract path. This method, though familiar, has some serious drawbacks, both because the contract path has little or no resemblance to any physical reality, and because transmission tariffs do not reflect the costs associated with the transaction.

Power flows over AC transmission lines according to physical laws, not according to contract. Power produced by a generator at one system node affects the voltage and flows at every other node on the system, and the effects are difficult to model or predict. Therefore, the transaction path pricing method may reimburse some system owners who are on the contract path but relatively unaffected by the transaction while ignoring owners of facilities located off of the contract path but on whom the transaction has a large effect. This is the problem of "loop flows."

Even if the contract path corresponds exactly to the path of the physical and financial effects of the power flows, there is a problem with the contract path method under traditional embedded-cost ratemaking methodologies. Under traditional regulation, owners of transmission facilities charge rates that are sufficient to recover their system average costs, regardless of the actual opportunity cost imposed on the system by any particular transaction. A bulk power transaction will accumulate a new charge for each utility’s service area that its contract path crosses, and these embedded cost charges will be stacked up, like pancakes, on top of one another. "Pancaking" of embedded cost rates can therefore result in an uneconomic discouragement of transactions. Obviously, the pricing signals produced by the contract path method do not provide an incentive for efficient control or enhancement of the transmission system, nor do they provide incentives for efficient location of new generation facilities.

One alternative to the contract path is to charge prices that reflect the costs imposed on the system by the transaction. This is an ideal favored by many economists, and it finds its best-known expression in the work of William Hogan [22]. Because of the network characteristics of the grid, costs imposed by any given transaction vary minute-by-minute, along with the network configuration of load and generation. The "efficient locational spot price" of a megawatt of electric power at any point (node, or busbar) on the grid will equal the full system marginal cost of supplying it. The efficient price of transmission between points A and B would be set equal to the difference between the spot prices at those two points. These spot prices will differ in proportion to the amount of transmission constraints between the points, which will provide an efficient incentive to relieve the constraint in the most cost-effective way, by building or enhancing either transmission or generation facilities.

The conceptual advantages of the short-run marginal cost transmission pricing method are legion. Generators and consumers will be motivated to make transactions that maximize the total gains from the system, and that will minimize the total system cost of serving the load. As in any competitive market, all decisions would be made freely by market participants, based on offers and bids for energy, and on transmission prices that reflect physical realities as measured by the transmission system operator. The timing and location of new transmission and generation facilities would be based on the same prices, and there would be no incentive to build more or fewer new facilities than are needed.

The difficulties of implementing the marginal cost transmission pricing method are also legion. To set the prices, the transmission system operator would require constant real-time information about all loads, generators, the condition of all transmission and other equipment, and all bid and offer prices of energy. Integrating this information on a large scale would require an enormous computer and highly sophisticated software that could take account of the nonlinearities inherent in an alternating-current network. Furthermore, the system operator would carry an extreme burden of independence and integrity, since it would be required to gather, process, and publish all the relevant information used to set prices. Such an omnipotent, omniscient, and benevolent central planner strongly resembles the Soviet model of production, as the opponents of this pricing method are fond of pointing out.

Although most regulators and market participants have concluded that a full-blown short-run marginal cost pricing method is too complicated for real-world implementation, some systems have moved to implement pricing systems that reflect marginal costs more accurately than the contract path. For example, the General Agreement on Parallel Paths (GAPP), which is advocated by Allegheny Power Systems, is a pricing method aimed at reimbursing transmission system owners for the costs imposed on them by the physical path actually taken by transactions. Also, the nodal pricing method countenanced in the California restructuring plan attempts to take into account differences in the locational prices. Closer to home, the PJM interconnection uses a pricing model that attempts to track marginal cost.

The postage-stamp pricing method’s chief advantage is its simplicity: every transaction pays the same rate per megawatt, regardless of the location of the buyer and seller. It is the most common method in traditional ratemaking, usually forming the basis for the system charges assessed by the contract path method. More recently, a postage stamp rate for the entire Eastern Interchange has been aggressively advocated by IPALCO (parent company of Indianapolis Power and Light Co.) [23]. A postage-stamp rate covering the Midwest region is also an important part of American Electric Power’s model of the restructured industry.

The postage stamp method is usually justified with reference to the "lake" model of the transmission system. This model emphasizes the physical reality that in a power transaction electrons do not actually travel from the seller to the buyer; rather, they are displaced. The entire system may be thought of as a lake, and the power in the system is like the water in the lake. "Water" flows into the "lake" from generators, and is taken from the lake by consumers. For the privilege of taking water from the lake, it is sufficient for the consumer to pay a generator to replace that water with an equal amount (plus a little extra to make up for "evaporation" -- line losses and other system-wide costs). For the system to balance, it is not necessary to pretend that the seller put the same molecules of water (electrons) into the lake as the buyer removed, nor is it necessary to speculate about the fictional route that these fictional molecules took.

This is a good model of a static system that has no serious constraints, and in which loads and generators are fairly uniformly spread about the grid. The model illustrates that the cost imposed on the system by a bulk power transaction may not always increase with the distance between buyer and seller. It runs into problems, however, when there are significant constraints on the system, or when the problem of optimal location is taken into account. IPALCO’s transmission pricing plan deals with the problem of constraints by suggesting a competitive auction for transmission that would go into effect when transmission congestion appears. The Independent System Operator (ISO) would call the auction and somehow weight the offers according to their effect on relieving the constraint before declaring a winner. In areas where the transmission system is often constrained, these auction prices would strongly resemble the Hogan short-run marginal cost prices.

The postage stamp rate, when implemented over a wide area, offers the significant advantage of increasing the number of competitors that can economically reach any given customer, thereby reducing the risk that any seller could exercise monopoly market power. To the extent that generation market power is an overriding policy concern, this is a legitimate advantage of the postage stamp rate. However, it achieves this competitive market structure by giving an unfair and inefficient advantage to producers located far away from loads. From a West Virginia perspective, the postage-stamp rate is therefore suspect because it would negate West Virginia’s advantage due to its proximity to East Coast markets.

This is not just a parochial concern of West Virginians; it is a problem of potentially serious system inefficiency due to incentives created by a postage stamp rate. If a postage stamp rate went into effect, power plants with the lowest operating cost would tend to be dispatched first, regardless of their location. A postage stamp covering the entire Eastern Intertie would therefore (ignoring transmission bottlenecks) cause much of the generation in New England, New York, and New Jersey to be displaced by lower cost power in the Ohio Valley and westward. West Virginia producers would compete for East Coast markets on an equal basis with producers located in Illinois, Kentucky, Tennessee, and, of course IPALCO’s native Indiana. (The Midwest region postage stamp rate contemplated in the AEP model has essentially the same problem, since West Virginians would pay the same transmission rate as producers in the western part of the region.)

This situation, while possibly preferable to the industry structure produced by traditional regulation, would not be efficient, nor would it be in the interest of West Virginians. Line losses would certainly increase; in the model’s own terms, increasing the average distance from the system’s generators to its consumers widens the "lake," which increases its "evaporation rate." And the widening of the lake would be caused artificially by the insensitivity of the postage-stamp pricing method itself. A fair and efficient transmission pricing method should take proximity into account when proximity reduces cost.

There are many possible ways to design a rate structure that is efficiently sensitive to distance. The short-run marginal cost rate is the ideal, but may be too cumbersome to administer. Its attractiveness increases with the number and severity of transmission constraints, as well as with the average distance from generation to load. Most likely a compromise will emerge, perhaps one that uses many zones, or subregions, each with its own rate. The details of the transmission pricing system, especially the "pancaking" of rates, will affect the ability of West Virginia generation to compete in the competitive electricity marketplace.

3.3.2 Fuel Choice and Environmental Constraints

Absent much more stringent environmental regulations, the introduction of a competitive market place for electricity will likely favor West Virginia’s existing low cost coal-burning generation plants. West Virginia’s coal reserves and strategic location could make it the premier supplier of electric power for coastal population centers. Coal is available domestically in large quantities, and the technology of its extraction and combustion promise continuing cost reductions in the future. Because of its low price and the small size of combustion turbines, natural gas has recently led all other fuels in the rate of increase of its usage for electricity production. But coal is still the leader in total production of megawatt-hours (55% of U.S. net generation in 1995, versus about a 10% share for gas), and it is likely to continue to be the leader because of the amount of existing coal-fired generation capacity and its low associated production costs.

But it is increasingly difficult to disentangle fuel choice issues from environmental issues, and environmental considerations darken this rosy view of the future of coal in West Virginia. In particular, the issue of global warming caused in part by greenhouse gases emitted by human activity is receiving increased scrutiny [24]. Scientists disagree about whether or not global warming is severe enough to cause a problem, but many observers urge that we not wait for proof before taking action to limit greenhouse gas emissions. Even the Chief Executive of British Petroleum, John Browne, recently stated, "The time to consider policy dimensions of climate change is not when the link between greenhouse gases and climate change is conclusively proven, but when the possibility cannot be discounted and is taken seriously by the society of which we are a part" [25].Public action to limit greenhouse gases is therefore increasingly likely. The greenhouse gas carbon dioxide is an unavoidable byproduct of coal burning, and any attempt to limit emissions of carbon dioxide would reduce the economic attractiveness of coal-burning electric power plants.

But environmental issues arise not because of the move to competitive markets; but because of result of the public’s concern for air quality. It is true that the cost of the installation of scrubbers in the Harrison plant to favor the use of coal was financed through an increase in regulated rates, and that particular financing option would not be available in a free market system. However, traditional regulation has not prevented the loss of market share by high-sulfur coal due to SOx standards and it would not prevent further losses if environmental standards tighten further. But in a competitive market system the state government could if it wished still subsidize scrubbers and other coal-favoring technology through tax policy, or by backing bonds for the purpose with taxpayer dollars.

3.3.3 Market Power

Although most discussions of market power center on the potential for producers to exercise market power upon consumers, an insufficiently competitive generation market could be harmful to producers as well. There are large practical difficulties in enforcing truly open access to transmission facilities. If owners of transmission facilities wish to benefit their generation subsidiary by preventing entry by new competitors they may be able to do so. Also, to the extent that the owners of transmission and distribution facilities are also aggregators in the generation market they may be able to shut off small potential competitors from access to that market. Therefore, the Commission will need to monitor complaints by potential generators. State government may also wish to consider a policy of helping potential new generators find markets for their product both within and outside the state. This would be in line with other policies that encourage the production and export of the state’s products.

CONTINUE TO PART II

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