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ELECTRICITY COST MODELING CALCULATIONS
By MONICA GREER
Academic Press
Copyright © 2011
Monica Greer
All right reserved. ISBN: 978-0-08-096135-4
Chapter One
Introduction
The issue of global climate change and its consequences has become one of growing concern in recent years. As a result, there has been an increased focus on energy efficiency and the development of alternative sources of energy, particularly renewable resources but also nuclear and clean coal technologies, such as carbon capture and storage (CCS). "Going green" has become the buzzword of the early 21st century.
As a result, much of the work being performed at utilities is focused on the potential impacts of conservation and energy efficiency on load forecasts, resource planning that includes renewable resources and, in the case of investor-owned utilities, shareholder value. What seems to be missing are well-designed rate-setting mechanisms that provide the proper incentives to consumers to make the appropriate choices in energy efficiency; in other words, the majority of the methodologies by which electric rates are set in the United States (and some other countries that regulate the rates paid by end users) provide neither the proper incentive to consumers nor the reward for "doing what is right." The bottom line is that rates are not based on economic efficiency, which occurs when fixed costs are recovered via fixed charges (i.e., customer- or demand-related costs) and variable costs via the energy charge. Instead, other motivations tend to guide the rate-making process, politics being among them (these are detailed later and in Chapter 10, "Pricing").
In the Preface, Figure P.3 displays a market in equilibrium in which the market clearing price (P*) and output (Y*) are set by the interaction of the demand and supply (or marginal cost) curves. In this situation, it is clearly the case that
P* = marginal cost
which, as the introductory economics text books tell us, is both allocatively and productively efficient. In addition, marginal cost pricing yields a welfare-maximizing outcome in which both the consumer and producer receive the maximum benefit possible. This is discussed in much more detail in the chapters on pricing and regulation. But for now, an excerpt from the section "The Marginal Cost Pricing Doctrine" of Marginal Cost Pricing for Utilities: A Digest of the California Experience makes this point well.
1.1 THE MARGINAL COST PRICING DOCTRINE
The "marginal cost pricing doctrine" is shorthand for the proposition that utility rates should be predicated upon marginal costs for the purpose of attaining economic efficiency by means of accurate price signals. The doctrine stems from Professor Alfred E. Kahn's hugely influential two-volume book, The Economics of Regulation (1970 and 1971). Kahn espoused marginal cost pricing as a means of bringing "economic efficiency" to regulated utilities. This pricing would result in "price signals" to consumers of sufficient accuracy that they could evaluate the appropriate economic level and timing of their use of utility services. Thus, the buying decisions of consumers is the means by which the end purpose of economic efficiency would be reached.
Quoting Professor Kahn, normative/welfare microeconomics concludes that "under pure competition, price will be set at marginal cost" (the price will equal the marginal cost of production), and this results in "the use of society's limited resources in such a way as to maximize consumer satisfactions" (economic efficiency) (vol. I, pp. 16–17).
The basis for the theory is clearcut: Since productive resources are limited, making the most effective use of these limited resources is a logical goal. In a competitive economy, consumers direct the use of resources by their buying choices. When they buy any given product or buy more of that product, they direct the economy to produce less of other products. The production of other products must be sacrificed in favor of the chosen product.
From this point, marginal cost theory takes a giant step. In essence, it states that, if consumers are to choose rationally whether to buy more or less of any product, the price they pay should equate to the cost of supplying more or less of that product. This cost is the marginal cost of the product. If consumers are charged this cost, optimum quantities are purchased, maximizing consumer satisfaction. If they are charged more, less than optimum quantities are purchased: The sacrifice of other, foregone products has been overstated. If they are charged less, the production of the product is greater than optimum: The sacrifice of other, foregone products has been understated. A price based on marginal costs is presumed to convey "price signals" that lead to the efficient allocation of resources. This is the theory, drawn from the microeconomic model of pricing under perfect competition, upon which the doctrine rests (Conkling, 1999).
To be fair, the reticence to adopt marginal cost pricing is due in large part to the thus far inability to accurately estimate or calculate the marginal cost of distributing electricity to various types of end users. And this aspect of the puzzle has been ignored thus far and is the primary motivation of this book: How do we accurately estimate the true cost of providing electric service so that rates can be set in an efficient manner, which provides the proper incentives to both producers and consumers to make the appropriate investments in energy efficiency, demand-side management, and conservation in general. (This is discussed in more detail in Chapter 10, "The Efficiency of Pricing Electricity.") Note: I am not ignoring the "naturally monopolistic" nature of the electric industry, which is discussed in detail in Chapter 2.
But first, I would like to provide a brief overview of the U.S. electric power industry, including the types of players (i.e., suppliers) and a general overview of the regulatory environment and its relationship to greenhouse gases.
1.2 A BRIEF OVERVIEW OF THE U.S. ELECTRIC MARKET
The structure of the U.S. electricity industry
The majority of the electricity that is distributed in the United States is by investor-owned utilities, which tend to be vertically integrated, which means that the same entity generates, transmits, and distributes electricity to the end users in its service territory. In the case of such investor-owned firms, traditional rate making is that a return to investors is earned on every kilowatt-hour sold, thus providing the incentive to sell as much as possible. Figure 1.1 displays the structure of the electric industry in the United States in 2006.
The players and their incentives
To assess the impact of various policies and rate-making schemes that are intended to affect climate change, it is necessary to distinguish each type of electric supplier and examine the incentives that each type faces. Unlike investor-owned utilities, whose objective is profit maximization, publicly and cooperatively owned utilities face their own set of circumstances and have their own objectives. Nonetheless, the ability to accurately estimate the true cost of providing service to various types of customers is tantamount to designing effective legislation despite the different objective functions faced by each, which are described here.
First and foremost, all utilities in the United States have an obligation to serve that is part of their franchise agreement, which means that they have been given an exclusive right to supply utility service to the customers that reside within that service territory. Whether a supplier is subject to certain types of regulation depends on the type of supplier, the state in which it operates, and whether it is vertically integrated or not. Each has its own objective function, which is discussed in the next section.
Objective functions: The players
Investor-owned utilities: Profit maximization
All investor-owned utilities in the United States are subject to some type of regulation, typically price and performance (for example, an obligation to serve native load and reliability in providing service). The objective function of the regulated investor-owned utility is to maximize profit (π), which is equal to total revenue (TR) less total cost (TC), subject to a break-even constraint under a regulated price, Pr, while procuring (or generating) enough electricity to satisfy market demand, Ym. That is,
Maximize π = TR(Pr, Ym) - TC(pi, Ym) (1.1)
subject to
TR ≥ TC
and
Y ≥ Ym
where Y = total output and pi = the prices of inputs.
Under the type of regulation to which the utility is subject, which is discussed in more detail later (and in subsequent chapters), the price allowed by the regulator (Pr) includes an appropriate rate of return to investors. The intent here is to compensate the shareholders for the risks involved in holding the stock issued by the utility.
Publicly owned firms
Under the umbrella of publicly owned utilities are nonprofit organizations established to serve their communities at cost. While some generate their own electricity, many others serve to transmit and distribute power purchased from other wholesale generators, which are mostly federally owned entities such as the Tennessee Valley Authority (TVA) and the Bonneville Power Administration (BPA). (Some other power administrations include the Southeastern Power Administration, SEPA, and the Southwestern Power Administration, SWPA). This being said, some publicly owned entities do purchase from investor-owned or cooperatively owned entities. To best serve the public interest, the objective function is cost minimization subject to a break-even constraint (i.e., that total revenues cover total costs). This is given by equation (1.2):
Minimize ITLITL = f (Y, pi) (1.2)
subject to
Total Revenue ≥ Total Cost
where Y = output and pi = price of inputs.
Organizational types include municipals, public power districts, and state authorities. Publicly owned utilities are exempt from certain taxes and typically can obtain new financing at lower rates than investor-owned utilities. In addition, they are given priority in the purchase of the less-expensive power produced by federally owned generators. These are discussed in much more detail in Chapter 3, "The U.S. Electric Markets, Structure, and Regulation."
Cooperatively owned firms
Rural electric cooperatives (RECs) are owned by the members of the cooperative and established to provide electricity to their members, which reside in rural areas deemed too costly to be served by investor-owned entities. (This is discussed in more detail in the case studies of Chapters 7 and 8.) Like publicly owned utilities, cooperatives enjoy benefits that the investor-owned utilities do not: They are able to borrow directly from various federal agencies created especially to serve them, predominantly the Rural Utilities Service (RUS), which allows them to obtain financing at a lower interest rate than the market. In addition, they enjoy certain tax exemptions and are given preference in the purchasing of lower-cost federally produced power.
Presumably, the cooperatives' incentives are welfare maximization (W), which is equal to consumer surplus (CS) plus producer surplus (PS), due to the coincidence of sellers and buyers. The objective function is displayed in equation (1.3). (They are also subject to satisfying market demand, Ym.)
Maximize W = PS + CS (1.3)
subject to
Y ≥ Ym
where
PS = the area below P* and above the supply curve in Figure P.3 in the Preface. CS = the area above P* and below the demand curve. Cooperatively owned utilities are interesting in that they are not subject to price regulation in all states. In fact, fewer than 20 states regulate the rates charged by rural electric cooperatives, which are organized as either generation and transmission (G&T) or distribution only (also known as member coops). While not truly vertically integrated, member coops are typically contractually bound to a G&T coop to supply its power needs. While this is not always the case, it is far more common than not. This particular organizational structure was the impetus for the paper entitled "A Test of Vertical Economies for Non-Vertically Integrated Firms: The Case of Rural Electric Cooperatives" (Greer, 2008). This paper is presented as a case study in Chapter 8.
Other suppliers
Other types of suppliers include power marketers, independent power producers, public power agencies, power pools, and energy service providers. These are discussed in more detail in Chapter 3.
1.3 REDUCING CARBON EMISSIONS
Regulation and rate making
There is little doubt that any meaningful limit or reduction of carbon dioxide emissions will have a significant impact on the electric supply industry. For example, in the United States, the electric power sector accounted for about 40% of the total carbon dioxide emissions in 2006, which increased by 2.3% in 2007 (U.S. Department of Energy. Energy Information Administration, 2009). Also, these emissions have increased by over 14% from 1996 to 2006, as the demand of electricity has increased. Over 97% of carbon dioxide emissions come from burning coal and natural gas to generate electricity. This is not surprising, since together these fuels account for 69% of the fuel used to generate electricity in 2006.
The U.S. electric power industry, regulation
In addition to the scale of the emissions and importance of fossil fuel in generating electricity, a complicating factor is that electric generation in the United States is regulated by a complex mix of federal and state laws and regulations. These laws and regulations have an influence on the generation resource choices that suppliers make. At the federal level, generation is subject to oversight by the Federal Energy Regulatory Commission (FERC). Since the mid-1990s, the FERC has increasingly relied on market mechanisms to determine prices and generation resources for the wholesale regions they regulate. Also, at the state level, 20 states modified or "restructured" their regulation of their electric utilities and permitted some or all utility customers the opportunity to choose their own supplier. However, 30 states remain regulated in the "traditional" or cost based/rate of return manner that has been used for over a century. And, while the mix of federal and state regulation may be unique to the United States, many features of markets and regulations apply to other countries as well.
Regulation of investor-owned electric utilities in the United States
Average-cost pricing is the typical regulatory mechanism employed by the states that are price regulated in the United States, which is displayed in Figure 1.2. Not only does this permit the utility to recover its prudent costs but also compensates shareholders for the risk that they bear by holding the stock of the utility. Typically initiated by the utility when rates fall below average cost, a rate case is the formal procedure for determining the price of electricity sold to various types of end users (i.e., residential, commercial, industrial, or other). More specifically, this process involves the establishment of the utility's revenue requirement, which is the amount of dollars that must be collected from ratepayers to recover the utility's expenses (and required return, in the case of investor-owned utilities) for the period during which such rates would be in effect. Once the revenue requirement is determined, it is multiplied by the allowed rate of return (i.e., return on equity, ROE) set by the public regulatory commission. From here, allocations ("base rates") are made among the various rate or revenue classes served by the utility based on cost of service, price elasticity of demand, and politics. This is described in much more detail in Chapter 10, "Efficient Pricing of Electricity."
(Continues...)
Excerpted from ELECTRICITY COST MODELING CALCULATIONS by MONICA GREER Copyright © 2011
by Monica Greer . Excerpted by permission of Academic Press. All rights reserved. No part of this excerpt may be reproduced or reprinted without permission in writing from the publisher.
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