The above enactments paved the way for the industry's transformation by effectively eliminating barriers previously existing in the domain of power generation. Opening electricity generation to competitive market forces represents the core for the transformation and restructuring activity that has been implemented. In the process, new entrants, generating and selling power, have made inroads in an industry previously closed to outside participants. Because of this array of changes, the industry is now more commonly called the electric power industry rather than the erstwhile electric utility industry. Opening the transmission system for competitive market access is now ongoing and represents the next aspect of restructuring the industry.
Actions initiated during the recent past by the Federal Energy Regulatory Commission (FERC) contributed in no small measure to the change in industry nomen-clature.(7) FERC modified its regulatory requirementsto permit business entities to file for rate tariffs in order to buy and sell electricity at wholesale among all electric utilities.(8) These new entities are called power marketers--members do not own or operate generation, transmission, or distribution facilities, but are considered electric utilities. Thus, the combined entry of new power generators and marketers constitutes a change that not only establishes milestones but also propels the industry on its path to competition.
This chapter provides background information and data on various components
of electricity trade, their interactions in the market, and their growth
and changing roles. Relevant data on retail and wholesale trade in conjunction
with data on generating capacity and the transmission network are analyzed.
Emerging trends in trade patterns during the period from 1990 through 1996
are presented.
U.S. generating capability consisting of utility and nonutility facilities
totaled 776,199 megawatts at the end of 1996 (Table
2).(9) Of this, utility capability represents
slightly over 90 percent of the total. Utility capability (which
is a mix of fossil and nonfossil fuel sources) is used to generate more
than 90 percent of the Nation's electricity sold to end-use customers.
Of this, the investor-owned utilities account for nearly 75 percent of
the total sales (Figure 2). They also purchase nearly all the power sold
by nonutilities (Figure 3). Each of the other three classes of utilities
has less than a 10-percent share of generation, accounting for the remaining
25 percent of sales. Their purchases from nonutilities are about 2 percent
in the aggregate. However, the mix of renewable and fuel-burning capacity
varies among classes of utilities.(10) These
characteristics indicate the relative dominance of the investor-owned utilities
in the makeup of the electric power generation sector.
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The U.S. electric transmission system represents a unified electrical
network with most of Canada and part of Mexico. The major networks consist
of extra-high-voltage connections that serve as the backbone of electrical
operations. These integrated power lines have been designed for system
support and to permit the transfer of electrical energy from one part of
the network to other segments.
Power transfers are, however, not completely free-flowing. Various factors set limits on the extent of the operations. These include restrictions based on lack of contractual arrangements, absence of approved tariffs, reliability considerations (protection of the adequacy of supply and security of operations), and inadequate transmission capability that limits electrical operations. Of the five power grids (electrical networks), the three that serve the United States are (Figure 4): (1) the Eastern Interconnected System, consisting of the eastern two-thirds of the United States and the Canadian Provinces of Saskatchewan, Manitoba, Ontario, New Brunswick, and Nova Scotia; (2) the Western Interconnected System, consisting of the 12 States west of the Rocky Mountains, the western tip of Texas, the Canadian Provinces of Alberta and British Columbia, and the northern portion of the Mexican State of Baja California Norte; and (3) the Texas Interconnected System. Both the Western and Texas Interconnects are linked with different parts of Mexico. The Eastern and Western Interconnects are completely integrated with most of Canada or have links to the Quebec Province power grid. Virtually all U.S. utilities are interconnected by these major power grids. The exceptions are in Alaska and Hawaii.
Transmission Network Operating Characteristics
Interconnected utilities within each power grid operate under coordinated operational and system planning guidelines. The industry-sponsored North American Electric Reliability Council (NERC) and its 10 regional reliability councils are responsible for the establishment of standards, policies, and guidelines for coordination of the bulk power supply. These criteria establish the requirements for adequacy of supply and security (reliability) of the electrical system or, from another perspective, the adequacy of all integrated transmission services operated above distribution-level support needed for customer load. These councils must regularly exchange operating and planning information among regions and the utilities that maintain control of electrical dispatch and have system operational responsibility.
The boundaries of the NERC regions follow the service areas of the electric
utilities in the regions. Neither the NERC regions nor most service areas
for electric utilities follow State or even national boundaries. Instead,
the boundaries are defined by what should be described as electrical geographics
of different control operations. As a result, data for interconnected system
flows are not available by State. When these data are shown, they are represented
by NERC regions.
The domestic power market has two distinct segments--the markets for wholesale power and for retail power. The wholesale market covers the actual purchase and sale of electricity to resellers (who sell to retail customers), in-kind exchanges of electricity, and transmission services along with ancillary services needed to maintain reliability and power quality at the transmission level.(11) Wholesale electricity trade is discussed in the next section of this chapter. The retail energy market may be viewed as a market in which electricity and other energy services are sold directly to all end-use customer classes (i.e., residential, commercial, industrial, and other).(12)
In accordance with the provisions of the Federal Power Act, oversight for regulating the wholesale electric market rests with the FERC. State public utility commissions have the primary jurisdictional responsibility for retail sales to customers served by investor-owned utilities. Oversight of the sales of other utility segments is far from uniform.(13)
Retail customers use electricity at different consumption levels and have other differentiating characteristics (similar demand patterns or load usage, distribution voltage level, groupings by social and economic considerations). These characteristics are used to differentiate and group them into residential, commercial, industrial, and "other" customer classes.
Classifying customers, as indicated above, is a regulatory procedure that allows for multiple oversight applications. Allocating the cost of service to each customer class and estimating future growth in demand are two critical functions that hinge on using this classification as the starting point. As different suppliers begin competing for customers in open retail markets,the prevailing classification (residential, commercial, industrial, other) may be revised.
Under the prevailing system of assigning billing tariffs to customer classes, all customers pay for electric energy delivered to them under a bundled fee that includes the cost of energy, transmission, distribution, and other charges (taxes, environmental surcharges, fuel adjustment costs, and others).(14) As markets in States open to competition, this billing practice will be subjected to radical changes requiring that all charges be shown separately, or "unbundled."
Investor-owned utilities dominate sales to ultimate consumers. For the
period 1990 through 1996, they accounted for 76 percent of the total sales
to ultimate consumers, compared with 11 and 8 percent for municipal and
cooperative utilities, respectively. Utilities owned or sponsored by State
governments and Federal utilities accounted for the remaining 5 percent
(Figure 5).
The Customer Base
Retail sales volumes and customer base levels have continued to grow during the 1990-1996 period. The electric power industry has gained more than 9 million new customers since 1990. Of these, new residential customers (approximately 8 million) account for 88.3 percent of the growth. New commercial customers account for nearly 11.6 percent (or over a million customers). The balance is distributed among the industrial and other categories (Table 3).
Sectoral Consumption and Prices
Total retail sales of electricity to ultimate end-use consumers stood at 3.1 trillion kilowatthours in 1996, reflecting an annual average growth of 2.2 percent since 1990 (Table 4). Residential customers accounted for about 34.9 percent of total electricity consumed in 1996,up from 34.1 percent in 1990. The commercial and industrial sectors accounted for 28.6 and 33.3 percent of total consumption during 1996, with the corresponding shares for 1990 being 27.7 and 34.9 percent, respectively (Table 5). These data indicate that consumption in the residential and commercial sectors increased by about 2.7 percent per year during the 1990-1996 period, while industrial consumption increased by an average of 1.4 percent per year during the same period. These differing growth rates partially explain the decline in the industrial sector share of total sales (about 4.6 percent from 1990 to 1996) (Table 5).
Changes in consumption shares have led to changes in the relative contributions of the sectors to revenues in the aggregate. The data indicate that revenue from the residential and the commercial sectors increased annually by about 3.8 and 3.5 percent, respectively, in tandem with the increases in consumption for these sectors. Both sectors increased their share of total revenues coming from all end-use customers, whereas the industrial sector share declined by nearly 11.4 percent, in comparison with a 4.6-percent decline in the share of sales.
An examination of regional prices by sector (Appendix B) indicates that industrial electricity prices (within the contiguous United States) declined in all regions after the enactment of EPACT in 1992.(15) The national average electricity price for the industrial sector declined from 4.8 cents per kilowatthour to 4.6 cents per kilowatthour from 1992 to 1996. In contrast, residential prices increased in most regions from an average of 8.2 cents per kilowatthour to 8.4 cents per kilowatthour during the same period. Prices in the commercial sector also declined in most regions, with the exception of increases in the New England and Mid-Atlantic regions; the national average (for commercial sector prices) declined from 7.7 cents to 7.6 cents per kilowatthour. These sectoral price trends, with the industrial sector securing relatively lower prices in comparison with the residential and commercial sectors, are also confirmed by an examination of average prices (revenues) contributed by various utility groups (Table 5).
It is possible that industrial end users have been able to secure price concessions from their incumbent utilities in anticipation of lower rates becoming available with the advent of competition in generation. Industrial customers, as a rule, are well organized, consume more (on average), and are capable of securing concessions from utilities that smaller customers usually find hard to obtain.
State public utility commissions have an abiding interest in maintaining the State's economic viability and often concur with special discounts awarded to industrial users in the hope of retaining them within State boundaries. Incumbent utilities are also likely to offer discounts in attempts to retain market shares in their franchise area and discourage forays by outside service providers. Alternatively, there may have been efforts to realign all rate schedules with the costs of supplying power to each customer group and eliminate any existing cross-subsidization in rates.
Sectoral Prices by Different Classes of Utilities
When utility service is grouped by end-use sectors, traditional differences associated with utility ownership are evident (Table 6). As an example, the cost of debt differs for investor-owned and publicly owned utilities, due to different tax treatment. Dividend payments are required for investor-owned utilities, and repayment of public debt and bonds is an obligation for Federal and public utilities. Not all Federal utilities have retail customers (or they have very few if they are power marketing authorities), and some cooperative utilities service only the needs of their member utilities and end- use customers. At least some of these and other traditional characteristics may be expected to change with the advent of competition. Existing price differences are likely to be scrutinized more carefully as markets open for competition.
Retail Price Differentials Between Requirement and Non-Requirement Utilities
Many electric utilities have no generating capability. Because they buy capacity and energy from other utilities in order to meet the requirements of their retail customers, they are known as requirement utilities.(16) Electricity is sold to requirement utilities on the basis of firm commitments for all energy or for some minimum level of demand all year around. Such sales are among the most common types of utility-to-utility wholesale transactions. Non-requirement utilities are those that have the capability to meet some or all of their customer demand loads from their own generating resources. Partial requirement utilities can meet some, but not all, of their customer loads.
Requirement utilities negotiate long-term, firm power contracts in which the terms and conditions obligate the selling utility to provide the buying utility a level of service equivalent to the seller's requirement for service to its retail customers.(17) About a third of all retail sales are made by utilities with no generating capability. Such utilities comprise two-thirds of all electric utilities.
Price differences among the three categories of utilities--full requirement, non-requirement, and partial requirement--are to be expected. One might expect that retail customer prices of non-requirement utilities (mostly large investor-owned electric utilities) would be lower than those of the requirement utilities (most municipalities and all distribution-only cooperatives), which must buy all the power they sell. However, data reveal that the average price for retail sales by non-requirement utilities is invariably higher than those charged by full requirement or partial requirement utilities (smaller utilities that can generate some of their own electrical energy) when examined at the national level (Table 7). Factors that contribute to this counterintuitive result may include interutility differences in the cost of capital (resulting from the tax treatment of debt acquisitions), the nonprofit status of some utilities, access to Federal preferential power allocations, and/or differences in fuel costs.
Similar difficulties arise in explaining the prevailing price differentials between full and partial requirement utilities. However, one of the key reasons for the existence of partial requirement utilities points directly to why there is a price difference. Better rates can be negotiated because these utilities limit the amount of power that they buy from the supporting utility. The reason for this is that the supplying utility knows in advance a ceiling amount that it is obligated for and can plan accordingly; it is not faced with an unlimited requirement during times of tight availability of supply. The limits established for these contracts usually have one of the following conditions: a contract demand cap; an average monthly maximum demand level; or an annual maximum demand level. Partial requirement utilities can do this, because they may have negotiated multiple contracts with different supplying utilities, or the partial requirement utility may own a generating power plant that is utilized when end-use demand reaches a specified level. Detailed retail trade statistics are provided in Appendix C.
Wholesale Trade
The factors that lead to wholesale (interutility) trade in electric power include differences in resource availability, input costs, and comparative advantage in production. For example, abundant water resources to produce hydroelectric power in a given region may make hydroelectricity in that region less expensive than other sources of electricity, especially if the other fuels have to be transported over long distances. In addition, the wholesale market is also governed by considerations of system reliability. Technical details with respect to the fundamentals of power transmission are provided in Appendix D.
Wholesale power transactions include purchases, sales for resale, exchanges, and wheeling (i.e., transmission services) (Figure 6). These wholesale power transactions involve the buying of power and energy from electric utilities according to the tariffs approved by the FERC and its regulations under the Uniform System of Accounts. Purchases from nonutilities follow the requirements of PURPA and EPACT with the result that the generation sales made by nonutilities are only accounted for by electric utilities in the cost account of purchased power and are not considered to be sales. Nonutility generation sold to utilities is accounted for under the category of purchased power. Sales for resale by electric utilities refer to power sold by a utility to one or more utilities for distribution to ultimate customers.
In the changing electric power industry, complete coverage through capture of all transactions poses a problem. As an example, power brokers do not take ownership of electricity purchases or sales, and the transactions they facilitate are not identified in the data collection process. Nor are all the intermediate transactions (purchases and sales) of a power marketer--who does take ownership of electricity and moves it from the point of origin to final delivery to the end-use customer--identified. In the new market for electricity, a single electricity transaction may be resold several times without being reported. Also, the change in value and repackaging of the electricity enables it to be marketed as a differentiated product (in order to meet the hour-by-hour market or achieve a daily balance on all transactions). The prevailing data collection approaches do not capture all these variances. Specifically, data on the market for purchased power (in the aggregate) do not necessarily match data on the market for sales for resale, even though all transactions can eventually be equated to a buyer and seller.
Accordingly, care needs to be exercised in analyzing historical account data by recognizing its limitations in
fully capturing all sales transactions in the electric power industry.
Exchanges involve trading power (in-kind) when supply and demand conditions are mutually advantageous and reversible for the participants. Many exchange trades are based on seasonal excess capacity or diversity in generating resource requirements.(18) Exchange-related monetary transactions or replacement of energy can extend over several years; currently, most exchanges seem to be concluded within one year. If a balance cannot be reached at the end of the year, cash compensation may be provided. The volume of exchange transactions has dropped since 1990 (Figure 7), partly because barter (in-kind) transactions have lost their luster. The advantage of in-kind exchanges as a technique to reduce overall dollar payments under cost-of-service regulation is not as important in a competitive market.(19)
Characteristics of Wholesale Trade
Nearly 55 percent of all the electricity consumed in 1996 was purchased by utilities from other utilities and nonutilities.(20) In addition, electric utilities sold to other electric utilities for their
resale to retail consumers just over 46 percent of the total energy purchased
by those consumers.(21) These
percentages make it clear that purchases and resales of electricity
within the wholesale markets represent a market force in which the prices
affect both the source and end-user (generation and retail markets).
As shown in Figure 8, sales to the ultimate consumer have become larger than total utility generation. Electricity purchased from nonutilities must be included in the total sources
of electricity supply. Nonutility power supply sources have become integral
in meeting the total power demand in the country.(22)
In addition to this trend, the recent increase in activities by power marketers
has resulted in a relative shift in sales for resale. The reason
is threefold. First, both the purchased power and sales for resale
markets have been altered by the addition of competition as another aspect
of trading, and the two markets are no longer in tandem. The market for
purchased power is affected by nonutility generation and is oriented
toward supplying utility needs (Figure 9), whereas the sales for resale market, which is influenced by power marketers, is directed toward end-use
customers (Figure 10). Second, more transactions are conducted with an
increasing number of trading participants involving trade over longer distances.
Third, information on power marketers is not collected at the same level
as information on electric utilities, nor are all the power marketers'
transactions identified. What is known about the new sales for resale market
is that many transactions can go through a dozen or more parties
before electricity markets become more competitive, this trend is likely to become more pronounced.(23)
Coordination and Requirements Wholesale Contracts
Wholesale trade transactions are also categorized in another fashion, as coordination and requirements contracts. Coordination service generally involves the purchase, sale, exchange, or transmission of electricity between two or more electric utilities that typically have sufficient generation and transmission capacity to supply their customer load requirements under normal conditions. These transactions are usually entered into because of advantageous prices, to sell surplus electricity, and/or to use a lower cost generation resource. Requirements transactions involve electric utilities that do not generate or have sufficient generating capacity to meet their customer load; in addition, these utilities may not have sufficient transmission capability to carry the electrical energy to the point where it would be transformed to a lesser voltage for distribution to consumers. Thus, in reality, requirements transactions involve handling part or all the firm service needs of another electric utility.
Requirements utilities (see above) usually enter into long-term contracts that identify the designated load level (partial obligations) or all current and future load (full obligations) of customers in their service territories.
Magnitude of Requirements Contracts
Requirements contracts are critical, because fewer than 1,000 of the 3,195 electric utilities in the United States are engaged in power generation.(24) Thus, more than two-thirds of utilities must acquire their electrical energy through long-term contracts to meet their end-user customer loads. In finalizing contracts, the most critical element is the certainty for delivery of power.(25) This certainty or the degree of assuredness (of power supply) determines the price formulation that a utility will be called upon to pay.
Price Determination in Requirements Contracts(26)
Where assuredness of power delivery (also known as firm power) is a must, transactions command premium prices, in comparison with contracts that do not require such a commitment. The premium on prices for requirement contracts depends on the degree of assuredness a supplier offers (all other conditions being equal). Within the class of requirements contracts, if a utility places a requirements wholesale customer (another electric utility) before its own end-use (retail) customers, then that level of contract service will be valued at the most expensive price level and will command the highest price premium. The next tier is where almost all requirements contracts are found. The utility that is providing the service will put serving its own retail customer base and the receiving retail customer base on the same level. This implies that the customer base of a wholesale requirements utility will not be cut before the supplying utility cuts its own retail customers. Instead, other transactions (i.e., spot or economic sales) are cut first, then interruptible retail customers are cut next, and finally a rolling blackout is initiated to reduce the impact on all retail customers. Structuring the contract somewhat differently brings about a different set of conditions together with variations in price premiums.
Other categories of customers are also included. Partial requirements customers (electric utilities) are those that have only a portion of their end-user load protected. They have a set block of power and energy allocated for their use. Finally, there are utilities with plants that are run only when the utility is approaching its prior system high usage level. This lowers the system demand level (peak load) to avoid setting a high usage power value. That value or peak load is used as the basis for setting the requirements contract price for the rest of the electrical energy and power sold during other times of the year (or contract period). Overall, requirements contracts usually contain a reservation of capacity that is on-call (sometimes called a demand charge), which must be paid, and then a separate charge for the actual energy used. Transmission costs and other electrical system charges are included in the bundled cost.
There are other firm transactions that involve electric utilities with adequate generation and transmission capability. These transactions include a capacity reservation charge and an associated energy charge. They are often entered into to provide or add additional electrical system support for the utility's own customer base. Each utility is required to have spinning and standby generation capacity on-call that would be used to replace operating power plants that suffer a forced outage and go off-line, or is needed to reinforce another part of the electrical system if a transmission line is lost. It is often more economic to purchase and/or join with other utilities in sharing backup capacity than to operate additional generating capability alone. Scheduled or forced plant maintenance of one of its power plants can also cause an electric utility not only to purchase reserve capacity but also to acquire the produced electrical energy. In addition, there are operating periods during which it is cheaper to purchase or sell firm capacity in order to keep a power plant operating at its most efficient cost levels.
Coordination Contracts
Coordination contracts--economic, interruptible, or non-firm sales and purchase contracts--are next on the price scale, followed by dump power transactions. Non-firm sales rarely
have a demand or capacity charge included in the price of the transaction.
These transactions are typically for short periods and are subject to curtailment
or cessation of delivery by the supplier in accordance with prior agreements
or under specified conditions. Utilities engage in these transactions in
order to gain operational savings, such as avoiding the use of more expensive
fuels. Dump energy is the cheapest priced electricity. The opportunity
for this sale develops when electricity is generated by the spillage of
excess reservoir water (and also for run-of-river dams) through a water-driven
turbine-generator. This happens because there is no way to store the excess
moving water behind dams, and if the turbines are not run, then all the
potential energy is lost. These transactions are thus low priced, depending
on what the supplier can obtain at a given point in time in the market
(Figure 11).
Regional and Interregional Trade
A significant portion of the electricity generated in the United States is traded under wholesale purchases and sales for resale contracts. The vast majority of wholesale transactions for investor-owned, Federal, and cooperative utilities involve utilities within existing NERC regions (Figure 4). Existing differences between intra- and interregional wholesale trade are attributable to the historical development of multiple transmission links among clusters of neighboring utilities.
Investor-owned electric utilities have led other ownership classes in total purchases and sales for resale, accounting for more than 40 percent of purchased power and sales for resale. The different shares of the wholesale market by other classes of utilities are shown in Table 8. Of this total, transactions with municipalities and power purchases from nonutilities are a dominant part of investor-owned trade.
The remaining categories of miscellaneous and other sales and purchases account for a wide range of trade covered by the terms and conditions in specific tariffs filed with the FERC. Many of these trades are associated with agreements that include transmission line capacity and equipment rental charges that grew up with the electric utility industry. These transactions are likely to continue until institutional changes, such as the formation of independent system operators (ISOs) and the Open Access Same-Time Information System (OASIS), become fully operational (or become part of a revised version of an open access to the wholesale/retail transmission system).
Quantity, Cost, Revenue, and Average Price
Table 9 shows the quantity of purchased power and sales for resale that investor-owned electric utilities have made since 1990. Overall, the quantity of purchased power has been increasing each year, from 563.4 million megawatthours in 1990 to 843.4 million megawatthours in 1996, reflecting an increase of nearly 50 percent overall. The proportion of firm to non-firm power purchases has also been changing during this period. In 1990, 57.6 percent of power purchased was on a firm basis, and only 39 percent was from non-firm sources. These percentages changed to 43.2 and 54.1 percent, respectively, in 1996. These statistics reflect the shifting character of the purchased power trade as utilities proceed to open electricity markets to competition (non-firm power purchase prices are invariably lower than the prices for firm power purchases, with an appropriate tradeoff for assuredness of supply). The shares of firm and non-firm power in the sales for resale category have followed a similar directional change.
An analysis of the cost of firm and non-firm power purchases by investor-owned utilities (Table 10) shows the following. First, demand charges, which constitute a fraction of the total firm cost (about 1 percent), have been growing rapidly, indicating that firms are willing to pay for reservation of capacity rights. Second, nearly 57 percent of the cost of purchased power in 1996 represented firm demand charges and firm energy costs. Third, the cost of firm energy has consistently been more than the actual firm demand charge.
In sales for resale, firm sales provide a major share of the total revenues (Table 11). The value of reservations (i.e., demand or capacity charges) has risen sharply, even though these charges are a small fraction of the total. It is also interesting to note that firm demand (or capacity) charges are higher or about the same as the cost of firm energy, in contrast to their shares of purchased power transactions. Non-firm sales have held relatively constant, indicating that there is willingness prevailing in the markets to pay a significant premium for assurance of supply. Even as trading practices change--and assuming that utilities are able to secure supplies from alternative sources in a competitive environment--it is not clear whether there would be a perceptible decline in the premium paid for firm power. For the spread between firm and non-firm prices to narrow, the requirement that excess capacity should invariably exist in a competitive market is not yet a given (a surplus puts a damper on price increases). In addition, there could be other constraints as well. As a result, the spread between firm and non-firm prices will continue to exist for the foreseeable future.
For the most part, average purchased power and sales for resale prices have remained steady or have beencontained since 1992 (Table 12). It is, however, interesting to note that the average prices paid by the industrial sector during the same time period are nearly the same as the wholesale prices for firm power. For any additional savings that this sector may seek, oppor-tunities may lie in purchasing non-firm power (or interruptible power) or in getting the same terms as embodied in requirements contracts. Should the industrials choose to adopt this option, some measure of protection would be necessary to guard against the possibility of actual power interruptions and other risk uncertainties. Additional advantages that this sector may be able to secure in the future as marketing opportunities open up are difficult to predict.
Table 13 provides a cross-sectional representation of the average prices paid and received by investor-owned electric utilities among the different competing utility ownership classes. Federal utility prices (Table 14) are generally lower. The prevailing lower price of power sold by Federal and State utilities at wholesale makes it a valuable commodity. Most of it is based on hydro-electric generation, which has traditionally been an inexpensive source of energy. Potential changes may occur if Federal utilities are no longer required to sell power at cost, or if it commands a premium because of its environmentally benign character. The willingness of retail customers to pay a premium for renewable energy (a large part of which will be hydro-based) in order to spur the development of more renewable energy sources could very well change the pricing of wholesale energy produced from hydroelectric resources.
The "other" category represents a collection of different markets. It includes power pool transaction trades, international electricity trade with Canada and Mexico, and nonutilitygeneration purchases. The sales for resale side represents more of the power pool, firm, and non-firm international trade transactions; the purchased power side includes nonutility purchased generation.
Table 13 shows that there are pronounced differences among the average prices paid and received for firm, non-firm, and the residual miscellaneous energy categories. As new markets develop, the differences in average wholesale prices to utilities, nonutilities, and retail consumers will narrow. Participants in the new markets will include electric utility traders, power marketers, industry, other retail groups, and members of the financial markets. These new and old participants will alter what must be taken into account to determine the true price of electricity, even as they change the existing framework of the retail and wholesale markets for electricity.
Competition is viewed as the means to open the wholesale and retail electricity markets. The expectation is that market forces will lead to lower rates for customers. This transition will induce many far-reaching changes in the structure of the industry and the institutions that regulate it. The transition will also raise many issues of reliability as new players, such as power marketers, begin operating and the responsibilities held by electric utilities are altered.
Views on how the emerging issues should be treated remain divided. There are those who would let the market find solutions. Others wish to impose strict, mandated regulatory measures. As a result, the search for consensus is difficult. Some of these emerging issues are stated below.
Planning for new demand and generating capacity, in the past, has been undertaken by the electric utilities serving a franchised area. The experience of investor-owned utilities in planning and building capacity in the aftermath of the oil embargo of 1973 turned out to be a serious financial problem as demand failed to materialize.(27) With many providers selling power at wholesale or retail level in the future, utilities could exercise the option of either being distributors (implying complete divestiture) with only an obligation to connect or being competitors but without the obligation to be the supplier of last resort (i.e., to serve). Thus, who will plan for new generating and transmission capacity to satisfy future demand--so vital to reliability--becomes a critical issue.
The above issues do not lend themselves to a market-devised resolution in the initial stages. For example, the task of requiring the present transmission owners to build and hand over transmission facilities to independent managers may prove difficult to implement. States are grappling with these issues.
Over two-thirds of the electric utilities in the United States do not generate electricity and depend upon other utilities for their supply of electricity. These utilities, known as requirement utilities, have historically shown a willingness to pay significant premiums for assurance of supply (that is, for requirements service). Even with electricity markets opening to competition and with changes in trading practices, these utilities will be operating under the terms of existing long-term contracts. Accordingly, it is not certain that the premium for firm power supplies (for requirement contracts) will decline in the immediate future. To the extent that firm power purchases represent a unique market product, premiums for firm requirement contracts (other things being equal) may continue to exist for the foreseeable future.
Non-firm electricity sales and purchases are priced lower than firm energy because of the limited availability of this category of electrical energy and the interruptible nature of the power supply. As part of the managed acquisition of future energy supplies, and as a means to cap the overall price paid for electrical supply, the acquisition of both firm and non-firm supplies of electricity can be expected to continue.
Industrial customers, in the aggregate, have secured price reductions during the 1992-1996 time frame, paying prices that are approximately equal to the wholesale prices for firm power. During the same time period, the per-kilowatthour price for retail customers in the residential and commercial sectors has increased. The large investor-owned electric utilities have also responded by cutting internal costs, and the average wholesale selling price has shown a corresponding decline.
Regional electricity markets are characterized by price differences. The competitive push to acquire cheaper electricity will result in more trade among divergent price regions. This development may strain wholesale transmission carrying capability, with associated impacts on reliability standards. If competitive electricity markets are unable to resolve these issues, alternative methods of resolution may become necessary.
7. FERC played a critical role in promoting competition in wholesale power even before the enactment of EPACT in 1992. See Energy Information Administration, The Changing Structure of the Electric Power Industry: An Update, DOE/EIA-0562(96) (Washington, DC, December 1996), pp. 51-52.
8. On May 19, 1986, the FERC approved the rate tariff for Citizens Energy Corp (EL86-2-000), which thus became the first power marketer. Only 3 more authorizations were granted before 1990. As 1993 ended, Enron Power Marketing was authorized under ER94-24-000, and that approval raised the total to 11 power marketers. At the end of 1996, EIA identified 80 active power marketers, and more than 200 had approved tariffs on file with the FERC.
9. This table contains the capability of only those facilities connected to the transmission system. It excludes industrial and other forms of self-generation.
10. Energy Information Administration, Form EIA-860, "Electric Utility Generator Report."
11. Ancillary services are those services necessary to support the transmission of energy from generation resources to loads while maintaining reliable operation of the transmission provider's transmission system in accordance with "good utility practice." In Order 888, FERC identified six major ancillary service groupings.
12. The "other" category includes public street lighting and highway lighting, railroads and railways, government use under special contracts, and other utility department usage as defined by the pertinent regulatory agency and/or electric utility.
13. Federal electric utilities, for example, are parts of several agencies within the U.S. Government. Their generation is sold primarily to municipal and cooperative electric utilities. Since most of their power is sold on a nonprofit basis, the prices they charge are designed to recoup costs incurred. Approximately 20 States regulate cooperatives, and 7 States regulate municipal utilities; many States defer to local municipal officials or cooperative members. See Energy Information Administration, Electric Sales and Revenue 1996, DOE/EIA-0450(96) (Washington, DC, December 1996).
14. This is an oversimplification of the actual process of paying for producing and delivering electricity to an end-use customer. There are many technical aspects involved in the process that are being assumed away. With the opening of electricity markets to competition, customers will find that their future bills contain line items for various services that are charged separately. The line items may also vary among and within customer classes.
15. Public discussion in regard to bringing the electric utility industry into a competitive framework preceded the passage of EPACT. Afterwards, attention shifted to retail issues.
16. Full requirement utilities are those that have no capability to meet customer demand because they own no generating resources.
17. See the next section for a more detailed discussion of wholesale transactions and firm power trade.
18. For example, a summer peaking electric utility sells surplus capacity in the winter to a winter peaking utility and receives in-kind trades when the seasons reverse.
19. The 1990 to 1991 drop represents the FERC enforcement of a statistical cleanup of informational filings. Prior to 1990, the requirements of the Purchased Power Account were fulfilled by the filing, on two separate but very different forms, of information on these transactions. From 1991 onward, competition affected this account.
20. A total of 3.1 trillion kilowatthours was consumed in 1996. Energy Information Administration, Electric Power Annual 1996, Volume 2, DOE/EIA-0348(96/2) (Washington, DC, February 1998), p. 61.
21. Energy Information Administration, Electric Power Annual 1996, Volume 2, DOE/EIA-0348(96/2) (Washington, DC, February 1998), p. 61.
22. This argument can be countered by positing that existing regulations require all nonutility generated power to be bought.
23. Power marketers balance their hour-by-hour and daily exposure on contract commitment. Surplus power and energy (or shortages) along with new opportunities need to be addressed daily. (Information developed based on conversations with industry representatives and system operators.) Industry analysts contend that the volume of commodity trades in electricity will soar to $2.5 trillion by the year 2003. This estimate is based on the experience of the natural gas industry, where trading is 10 times the value of physical sales. For more information, see the Electricity Journal (March 1998), p. 6.
24. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report."
25. Other elements (for both coordination and requirements contracts) in determining the type and value of transactions are the duration of the purchase/sale, the amount of energy, and the type of generating capacity sold, excluded, or reserved.
26. The capacity charge represents an element in a two-part pricing method used in capacity transactions (energy charge is the other element). The capacity or demand charge is assessed on the amount of capacity being purchased. The terms "capacity charge" and "demand charge" are used interchangeably in the text.
27. This is not to deny the role of integrated resource
planning activities with participation of public utility commissions and
the stakeholders, including nonutilities. Given that there will be many
providers serving a given area, the future of integrated resource planning
is unclear.
