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2011 | OriginalPaper | Chapter

11. Tools of the Trade

Author : Dr. Roger L. Conkling

Published in: Energy Pricing

Publisher: Springer Berlin Heidelberg

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Abstract

Chapter 11 is aptly termed “Tools of the Trade.” It opens the door to measures that are essential for an understanding of the economics of all industries, particularly capital-intensive industries as are the energy utilities. The factors of measurement are fully explained for the beginner, and their implications are developed for the practitioner. Load factor gauges whether facilities are heavily or lightly loaded, and gives insight into the impact of these conditions upon the economics of operations of the concerned firm. Diversity factor, the second most important measure, assesses the variety of uses to which a facility can be put simultaneously, the greater the number, the greater the efficiency. Other factors—capacity factor, utilization factor, demand factor, and for the electric technician, power factor—are also covered in Chap.​ 11.

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previous chapter Traditional Types of Rate Forms
next chapter Matters of Judgment
Footnotes
1
For base-load PG&E utilizes its nuclear and geothermal capacity, conventional thermal units at minimum operating levels, energy from QF’s and other scheduled purchases, and hydro. For peaking, PG&E can call upon pumped storage and other hydro, purchases, and combustion turbines. The turbines can go from a cold start to full load in 10 min or less. Intermediate loads are met by various mixes of resources.
 
2
For most of us, system frequency is notable because it guides the accuracy of our clocks: if frequency sags, our clocks run slow; if it gains, our clocks run fast. The objective is to maintain frequency at an even level, correcting for slow or fast. Unexpected heavy loads may cause a sag; unexpected light loads, a gain. The trick is in the balancing. The generation dispatcher must be on the alert.
 
3
Bear in mind that the load-serving requirement may be either gross (total energy input into the system) or net (a lesser amount, total energy delivered to customers). Illustrative charts do not require this distinction.
 
4
Peaks sometimes are described as either “needle” or “broad-based” peaks. If sharp, infrequent, and of short duration, they will be of needle type, while if they extend over a longer time span and are more consistent one to another, they will be described as broad-based.
 
5
The utilizations shown in Fig. 11.3 are not rules-of-thumb. They will differ from year to year for the same company, and will be different for different companies as well as for different service areas or regions. Also, forecasts will differ from actual experience.
 
6
Sunk or embedded costs are irrelevant, since these costs must be met whether or not the capacity is operated.
Any fixed operating costs which do not fluctuate with the utilization under consideration also are irrelevant, since these also will be incurred even if the plant is not put on line.
The “least expensive” criteria refers to short-run incremental or marginal costs. In most cases these will be only the additional cost of fuel, plus some minor increment for possible increased maintenance and staffing. For a hydro plant, incremental costs may approach zero.
 
7
This point is true whether the distributor is selling its own gas, or transporting for the customer. While some distributor mains supply only residential and other firm customers, many facilities are joint to the service of all customers, including interruptible.
 
8
Historically, many gas companies have required that interruptible customers for whom they are “merchants” maintain a dual-fuel capability, so that the customer can shift to oil when gas deliveries are curtailed, thus not having to shut down their plants and avoiding a resulting loss of production and worker lay offs. It appears that the trend toward “transmission service” in lieu of merchant service for industries may result in the elimination of duel-fuel requirements.
Our explanation of pipeline formulae for cost allocation shows that the costing and pricing of interruptible gas is a ticklish business.
 
9
Other types of diversity are inter-system diversity, which may exist between two or more utility systems because of differences in the predominant types of load they serve, which makes peak and energy exchanges between such systems of value; for hydroelectric systems, watershed diversity between two or more hydroelectric plants located on rivers or streams of different flow characteristics; and interregional diversity, the difference between load patterns of adjoining regions.
Obviously, there also is diversity within each customer class. A residential customer who uses electricity for house heating will have a different use pattern than one who heats with gas. An industrial customer using electricity in processing (such as a 24 h, 7 days a week electro-process aluminum smelter) will not have the same usage characteristics as an industrial customer needing power only for motors and lighting.
Diversity of whatever nature when incorporated into system planning or rate designs is a gamble on likelihoods, some high risk, some low. Future diversity is a shifting target. Of course, this statement is true of all planning.
 
10
From the standpoint of the non-utility operator, the uncertainties promise to loom very large indeed. Except as all deliveries it makes are guaranteed by contract as mandatory customer takes, it must rely upon (informed?) speculation as to the degree of diversity upon which it can depend. This may not be too important for large-volume industrial sales, but it may be critical for aggregated smaller-customer sales.
 
11
If daily/hourly consumption records were available, it would be necessary to restate the average monthly consumptions (the numerator) to a daily/hourly basis so as to match the maximum peak day or hour (the denominator). For gas, the total years consumption would be divided by 365, the number of days in the year; for electric, the total years consumption would be divided by 8,760, the number of hours in the year.
 
12
That is even though the customer’s actual usage was at a lower-load factor, the billing would not be less than the equivalent of the higher-specified load factor.
 
13
Connected load is seldom calculated in today’s practices, except for large industrial customers. Nonetheless, connected load is a fact for all customers and all customer classes. The circumstance that an individual customer’s demand (or a class demand) will fall below its connected load is the result of customer’s timing—diversity—in the use of energy appliances.
 
14
From pamphlet “Electric Terms.” September, 1947, by Mr. Vennard.
 
Metadata
Title
Tools of the Trade
Author
Dr. Roger L. Conkling
Copyright Year
2011
Publisher
Springer Berlin Heidelberg
Book
Energy Pricing

Print ISBN: 978-3-642-15490-4

Electronic ISBN: 978-3-642-15491-1

Copyright Year: 2011

DOI
https://doi.org/10.1007/978-3-642-15491-1_11