Abstract
Two elements enter into the determination of the price of every component exchanged in the economy: the costs of producing, transporting, and delivering it, on the one hand, and its value to the buyer, on the other hand. Under price regulation, these two individual elements are the subject of highly developed formal processes and strictures, particularly as to costs. Chapters 2, 3, and 4 explore the economics of various aspects of the cost approach. Chapter 2 emphasizes one central principle–that prices tend to follow the direction of costs. To determine this direction, costs are examined from their fundamental role as either fixed or variable, and whether in combination they lead to decreasing, constant, or increasing per-unit costs. For capital-intensive industries, such as the energy utilities, the direction of unit costs is downward as plant is utilized more extensively with growth. Comparative scenarios are presented which analyze growth in its several stages, even or erratic, constant or interrupted, with resulting changes in the firm’s prognosis.
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Notes
- 1.
The “signal” enigma introduces at least three uncertainties: what message is to be signaled? How should the message be couched in terms of present prices? And, will the message be recognized by the buyer, motivating the buyer to adjust buying habits to correspond to the signal?
- 2.
Fixed or overhead costs are called “constant” costs by some writers. Martin Glaeser, an outstanding utility authority of an earlier era, recommends that they be called “capacity” costs. This is a useful concept inasmuch as most fixed costs are associated with the provision of capacity. Glaeser calls variable costs “out-of-pocket” costs. Glaeser, M.G., Outlines of Public Utility Economics, The Macmillan Company, New York, NY, 1931, Ch. XXVIII, p. 623.
- 3.
There are other ways of classifying costs for this purpose, depending upon the degree of refinement desired. An example of a three-way classification (given by Thompson, D.W. and Smith, W.R., Public Utility Economics, McGraw-Hill Book Company, Inc., New York, NY, 1941, Ch. 5) is (1) capital costs; (2) fixed operating costs; and (3) variable operating costs.
- 4.
The term plant is used in this chapter in a very broad sense to mean all or any part of the physical facilities, including land, equipment, machines, tools, buildings and grounds, etc., which are necessary to provide the utility service. Major additions to plant might mean, in the electric industry, an additional generating station, an important transmission line, or a large substation; in the natural gas industry, looping a pipeline main, a new compressor station, an additional city gate, storage, etc. Such additions may be made in any phase of the utility’s operations (production, transmission, or distribution) or may, for balanced development, encompass all phases. Often the latter will be the case.
- 5.
Within the limits of ranges of output and periods of time previously mentioned. Also, accounting treatment of investment costs may cause annual booked costs to vary as depreciation changes the spread between gross and net plant; return requirements may change, as may property taxes, etc. But investment costs must be met in any event.
- 6.
“Use of service” costs are often expressed in the specific terminology of the utility under consideration. In the electric industry, “use of service” costs are called “energy” costs and in the gas industry, “commodity” costs.
- 7.
Average costs are the result of dividing the number of units produced into total costs (fixed and variable). In the electric utility, the most common unit is the kilowatt-hour; in gas, either the cubic foot or the therm.
- 8.
Historically, utilities have been seen as characteristically operating under decreasing cost conditions. It has been generally true that utility firms experience decreasing average unit costs as their output increases. If so, often this is due to one or more of the following: first, a longer term circumstance, it may be due to the fact that most utility firms have not yet reached optimum size, i.e., the point where further increases in size would result in higher costs of operation; second, a short-term condition, it may be because utility firms have unused capacity so that output may be increased without a proportionate increase in fixed costs; or, third, an intermediate situation, utilities may be able to expand major plant units at costs comparable to existing units.
- 9.
Theoreticians may treat conditions of decreasing costs as always being applicable only in the short run. The important reason for putting a time limit on such conditions is that over a longer period major additions to plant may be necessary, and since such additions are in the future their costs are unknown or at least speculative. This is a good point, but is an unnecessary refinement for our discussion.
- 10.
An example of an average variable cost of about 1 cent per kWh for a utility company with a mix of fuels is the 1993 experience of Kansas Gas and Electric Company. Its cost as reported in its 1993 Form 10-K was:
Weighted average cost of fuel, per million BTU
Nuclear
$0.35
Coal
0.96
Gas
2.37
Oil
3.15
Cost per kWh generated: 0.93 cents.
Many utility operations are most efficient at or near capacity or name-plate output. For this reason, variable costs will change per unit as well as in total for different amounts of production, frequently being lowest near the point of capacity output. When this is true, it reinforces the trend toward decreasing unit costs. Variable unit cost changes, however, are minor as compared with changes in fixed costs per unit and are accordingly disregarded in this illustration.
- 11.
The reader is requested to note, and put in the back of his mind for later reference until marginal cost pricing is discussed, that the marginal cost per unit for any expansion of output along all of the ranges of output illustrated in Figure 2.1 and Table 2.1, except beyond the last increment reaching to 20 billion kWh, is 1 cent. For example, output can be increased from 10 billion kWh to 18 billion kWh at an additional cost per unit – marginal cost – of 1 cent.
- 12.
Changes in load shapes from one stage of production to another are not integrated into this factor, which, as used here, assumes a generally consistent load shape but without specifying a given sales load factor or factors.
- 13.
Davidson is director of power generation and transportation systems, Gas Research Institute, and Braun is director of advanced energy systems research, Pacific Gas and Electric Company.
Davidson, K.G. and Braun, G.W., “Thinking Small: On site Power Generation May Soon Be Big,” Public Utilities Fortnightly, July 1, 1993.
- 14.
In 1967, in a report prepared for the Bonneville Power Administration, the writer suggested the use of gas “in relatively small (20,000 kW to 50,000 kW each) gas turbine plants at the perimeters of electric transmission lines,” for system reliability, peak shaving, supplementing hydro storage, or system reserve.
Conkling, Inc., “The Potential for the Natural Gas Industry in the Pacific Northwest,” US Dept. of the Interior, Bonneville Power Administration, 1967.
- 15.
In fact, the Division of Ratepayer Advocates of the California PUC, in its “Comments” of June 8, 1994 on the Commission’s April 20, 1994 OIR and OII, R.94-04-031 and I.94-04-032, expresses a “preference that utilities ultimately be completely out of the generation business …. [when there is] a healthy wholesale generation market that can provide for all the utility’s generation and reliability needs.” California PUC, Division of Ratepayer Advocates, “Comments” on the Commission’s April 20, 1994 Restructuring Order, June 8, 1994.
- 16.
“Wholesale wheeling” or “transmission access” is already required by the Energy Policy Act of 1992. FERC can require a utility to transmit power from an EWG to a purchasing utility (a wholesale customer of the EWG). But “retail wheeling,” to an end-user customer, is still to be mandated. Public Utilities Commission of the State of California, Order of April 20, 1994, op. cit.
- 17.
It also offers system control and delivery arrangements satisfactory to the utility (deliveries to fit the utility’s load shape, an appropriate share of reactive, scheduling, etc.).
- 18.
The writer is tempted to quote the question which appeared in a different context in bold type on the cover of the May 16, 1994 issue of Business Week: “Why are we so afraid of GROWTH?”
- 19.
This problem is discussed in relation to price elasticity in Chapter 5.
- 20.
With due consideration, of course, to the terms and conditions of sale—volumes, duration of contract, minimum and maximum takes, dependability, etc.
- 21.
Studness, C.M., “The Pressures of Competition,” Public Utilities Fortnightly, June 15, 1993.
- 22.
Time-of-day or “Real Time Pricing” rates, if spelled out on the customer’s bill, are effective in advising the customer that it is cheaper or more expensive to use energy at one time period or another, and thus may influence the customer’s usage pattern. But the signal they send is a current message. They tell nothing about the level of future rates. Even rates with inverted blocking do not signal the future.
- 23.
Smith, R., “NRG After Rejection, Ends Calpine Effort,” The Wall Street Journal, June 1, 2008.
- 24.
Denning, L., “Energy Prey Can Find Partners,” The Wall Street Journal, November 14, 2008.
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Conkling, R.L. (2011). The Cost Approach to Pricing: The Direction of Cost. In: Energy Pricing. Energy Systems. Springer, Berlin, Heidelberg. https://doi.org/10.1007/978-3-642-15491-1_2
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