Electricity Cost Modeling Calculations: Regulations, Technology, and the Role of Renewable Energy

By Monica Greer

Reducing greenhouse gases and increasing the use of renewable energy continue to be critical goals for the power industry and electrical engineers to promote energy cost reductions. Engineers and researchers must keep up to date with the evolution of the power system sector, new energy regulations, and how different pricing techniques apply in today’s market. Electricity Cost Modeling Calculations, Second Edition delivers an updated view on pricing models, regulation, technology and the role renewable energy is starting to take in electricity. Starting with fundamental concepts relating to market structure, an increase in international regulations is added to expand the engineer’s knowledge. Cubic cost modeling and new modeling cases are included along with updated literature reviews for deeper research. The reference then extends into more advanced quantitative methods such as updated rate designs, and a new chapter is included on the marginal cost pricing of electricity in the United States with applications to reduce greenhouse gas emissions, making the reference relevant for today’s power markets. This book provides engineers with a practical guide on the latest techniques in electricity pricing and applications for today’s markets.

• Provides updates on international regulations and the role of renewable energy sources
• Presents foundational concepts and advanced quantitative aspects including updated practical case studies
• Discusses the appropriate rate/tariff structure for more efficient use of electricity and renewable options

• Language: English
• Publisher: Academic Press
• Release date: Sep 10, 2021
• ISBN: 9780128213728

Monica Greer

Monica Greer is a Senior Quantitative Analyst based in Kentucky, United States. Her role includes forecasting market shares for appliances, performing analysis and deriving price elasticities for clients. Previously, she was a Senior Business Consultant and Economist, and a Senior Economist for the Louisville Gas and Electric Company, managing impacts of various carbon-related policies on customer demand and performed load research and analysis. Monica is also currently an Adjunct Faculty member of the Department of Economics at Bellarmine University in Kentucky and taught previously at Jefferson Community College, University of Kentucky, and Indiana University. Monica earned a PhD in economics from the University of Kentucky, an MA in economics from Indiana University, and a BBA in finance from the University of Kentucky. She was awarded into the University of Kentucky Honors Program, has published two books, both with Elsevier, and has published several journal articles and provided presentations.

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Preface

I decided to work toward my doctorate in economics because I was fascinated by the subject of economics and I had a professor who truly inspired me. I especially enjoyed the theory of market structure, in particular monopoly theory and Natural Monopolies.

While working on my Master's degree at Indiana University, I was intrigued by the attempt of the Indianapolis Power and Light Company (IPL) to take over the then Public Service of Indiana (PSI, which became Cinergy and is now Duke). IPL was sort of the donut hole, serving the metropolis of Indianapolis while PSI served the surrounding area (the donut). My thinking was that it would be more efficient if one entity served this entire territory rather than the two separate entities (in other words, both the donut and the hole). Subsequently, my Master's thesis examined cases in which horizontal mergers between utilities could be welfare enhancing, which essentially boiled down to cost modeling and the savings that could be realized from such mergers.

During my doctoral program, in 1996 the Federal Energy Regulatory Commission (FERC) Orders 888 and 889 were passed. FERC Orders 888 and 889 were implemented to facilitate wholesale competition in the bulk power supply market. More specifically, Order 888 addresses the issues of open access to the transmission network, giving the FERC jurisdiction over all transmission issues, especially pricing. Order 889 requires utilities to establish electronic systems to share information about available transmission capacity. These will be discussed in more detail in the chapter on regulation (Chapter 3, State Regulations, Policies, and Updates on States With Retail Choice).

While thinking about a dissertation topic, I began to study the cost models that supported the Electric Industry, which were typically Natural Monopolies under some sort of price regulation (since Electric Utilities they were deemed Natural Monopolies, as discussed in Chapter 2, The Sustainability of a (Natural) Monopoly). What I found was that these cost models were lacking—not only did they inappropriately assume that distributed electricity was a single output, but also they were not true cost models in the sense that they did not conform to the properties to which a true cost model should (this will be discussed in subsequent chapters). As a result, in my dissertation, I developed an appropriately specified cost model, which is quadratic in output and will be detailed in Chapter 4, The Economics (and Econometrics) of Cost Modeling, and in the case studies that are presented in subsequent chapters.

More recently I began thinking about the structure of prices and the appropriate specification of cost functions employed to model the production (and distribution) of electricity; that is, a Total-Cost Function should be cubic in output, experiencing regions of increasing, constant, and decreasing Returns to Scale. It is only in this form that appropriately shaped Average- and Marginal-Cost Curves result, the latter of which could then be used to price electricity efficiently, which means that price reflects the Marginal Cost of supplying power at a given time. As such, it is only under these conditions that the true variable (i.e., marginal) cost of supplying electricity can be estimated, a cost which increases with output since higher-cost generating units come online to provide service. Figure P.1 displays such a cost function.

Figure P.1

Figure P.1 An appropriately shaped Total-Cost Function. A cost function that is cubic in output ( Y ). Y * denotes the inflection point, which is the point at which Returns to Scale go from being increasing to decreasing.

This cubic form yields the Average- and Marginal-Cost Curves that are depicted in Figure P.2.

Figure P.2

Figure P.2 Average- and Marginal-Cost Curves for a Cubic Cost Function. At output levels Y  <  Y *, increasing Returns to Scale are indicated by declining Average Costs (AC =  f ( Y )). At Y  =  Y *, Returns to Scale are constant (and Average Cost = Marginal Cost). Beyond this level of output, Y  >  Y *, diminishing returns to production set in (i.e., Marginal Cost increases with output), and decreasing Returns to Scale are experienced.

Only the proper specification of costs will facilitate the appropriate pricing of electricity that will truly incentivize producers to invest in new generating technologies and encourage Demand-Side Management and consumers to invest in energy efficiency and to become more conservative so that a real reduction in greenhouse gases can occur and real climate change is possible. To date, this is the missing link: this problem is not just a supply-side or a demand-side issue; it is a fundamental issue, which has been essentially ignored thus far. And that is the purpose of this book: effecting a real change in the methodology by which rates are set and costs are modeled so as to precipitate the changes that need to be made to combat global warming of our planet.

With all of this said, the motivation of this book emanates from my desire to effect a change in the way that rates are set in the United States (and possibly in other places that have similarly set rate structures or regulations). Having worked for a public utility commission (and a regulated, Investor-Owned utility), I have been frustrated as an economist to see that the true cost of service is not the mechanism by which rates are set; rather it is other forces (such as politics, demand elasticities, and the ability to hire attorneys to argue on behalf of their customers, namely industrial users) that influence the rate-making process.

Some Basic Economic Theory

Fundamentally, it has been ingrained in me that consumers (and producers) respond to prices, which should reflect the cost of providing a particular service, in this case electricity. To wit: Figure P.3 depicts the equilibrium price (P*) and output (Y*), which are set by the interaction of supply (or Marginal Cost, MC) and demand.

Figure P.3

Figure P.3 A market in equilibrium. Basic in nature, this figure merely represents the laws of supply and demand.

Granted, we are not discussing a perfectly competitive market. That being said, this paradigm should not be dismissed outright as there are lessons to be learned here. That is, first and foremost, price should always be a function of cost, which is not necessarily the case. It has been my experience in the Electric Industry that the price (or rate charged to end users) has little to do with the cost of providing such service, but rather tends to be a function of other factors, politics being among them.

Several years ago, I had the first flavor of the politics of regulation for Electric Utilities. As the economist at a state regulatory commission (in a state with predominately coal-fired generation), I struggled to understand the logic behind the methodology of how rates were set and how costs were allocated among the various customer classes. I still struggle with this today, which will be expounded upon in this book.

The bottom line is that the antiquated methodology under which rates have been set in the United States (and possibly other countries in which the same rate-making processes occur) is archaic; they do little (if anything) to provide the proper incentives to end users to use energy wisely, especially in states like Kentucky, where coal is king and the lobbyists (and legislators) are gold. (By the way, the color green has been removed from the crayon box.)

A New Regulatory Paradigm

With all of this said, prior to the publication of the first edition of this book, I had recently attended a conference on climate change that was sponsored by the National Association of Regulatory Utility Commissioners. There, I was pleased to hear talk of a new regulatory paradigm, which includes a departure from the traditional methodology by which rates have been set in the United States. As I have stated time and time again, if we are to achieve a reduction in the amount of greenhouse gases being emitted into the atmosphere, such a new paradigm must transpire; both producers and consumers must be incentivized to pursue energy efficiency, Demand-Side Management, and conservation, in general. Renewable resources must be a part of the generation mix and the way that Investor-Owned utilities provide returns to shareholders must be changed. Utility investment in renewables (or avoided costs) should allow a higher return to investors while those in fossil-fuel-fired generation return a lower return since the latter produce the very greenhouse gas emissions that wreak havoc on the environment. Finally, it is time to pay the piper, and this is everyone's responsibility.

Update: Sadly, more than a decade later, nothing has really changed. Yes, papers have been presented at conferences and RPS standards have been mandated, but in terms of rate-making activities, the status quo remains. And, as will be discussed in subsequent chapters, some states/utilities continue to pursue rate structures that actually discourage energy conservation (i.e., an Increasing-Block Rate structure).

Nonetheless, one of the major differences between this edition and the first one is the inclusion of a chapter on renewable energy sources and the technological advances that have occurred so that these sources (solar, wind, etc.) have become competitive (in terms of cost) as sources for generating electricity, thus displacing the traditional carbon-dioxide emitting (and other such greenhouse-gas producing fuels).

Also of interest is a seeming desire to disconnect from the grid. On a recent trip to Southern California, I was amazed at the number of homes that had installed solar panels and invested in other Distributed Generation technologies. This is discussed in much detail not only in Chapter 9 Renewable Energy Sources and Policies but also in other chapters.

Chapter 1: Introduction

Abstract

Much has transpired since the writing of the first edition of this book, and this Introductory provides the overview of this second edition and the updates that have been incorporated; some of the chapters are the same, but with added content and new concepts that have become relevant in the past decade. More recently, there has been a pronounced increase in Renewable energy sources and Distributed Generation Technologies that have become a part of the objective to reduce Greenhouse Gas emissions, not only in the United States but globally as well.

Keywords

Natural monopoly; Regulations; Cost modeling; Economies of scale; Economies of scope; Economies of vertical integration; Renewable portfolio standards; Demand-side management; Renewable energy sources

1.1: Introduction

The issue of global climate change and its consequences has become one of growing concern in recent years. According to a recent report, global emissions of carbon dioxide reached the highest levels on record in 2018 (Brady and Mooney, 2018). This 1656-page assessment compiled by 13 Federal agencies was released on November 23, 2018 and lays out the devastating effects of a changing climate on the economy, health, and environment, including record wildfires in California, crop failures in the Midwest, and crumbling infrastructure in the South. It states that going forward, American exports and supply chains could be disrupted, agricultural yields could fall to 1980s levels by midcentury, and fire season could spread to the Southeast. All told, the report says, climate change could slash up to a tenth of gross domestic product by 2100, more than double the losses of the Great Recession a decade ago.

Steady increases in greenhouse gas (GHG) emissions peaked in 2007, when the electric power sector accounted for more than 40.41% of the total carbon dioxide emissions in the U.S., an increase of more than 19.9% from 1990 to 2007 as the demand of electricity increased. This is displayed in Figure 1.1.

Figure 1.1

Figure 1.1 U.S. Greenhouse gas emissions by economic sector, 1990–2014. (Source: Based on data from the EIA report Emissions of Greenhouse Gases in the United States, Tables 5 and 6, https://www.epa.gov/climate-indicators/climate-change-indicators-us-greenhouse-gas-emissions.)

By 2014, the increase in GHG from carbon dioxide emissions had increased by 9% since 1990, with electricity Generation in the U.S. accounting for the largest shares (31%).

There is little doubt that any meaningful limit or reduction of carbon dioxide emissions will have a significant impact on the electric supply industry. Although greenhouse gas emissions from electricity were on the decline, approximately 28% in 2016, it is still the second largest source of U.S. GHG emissions. Breaking this down by end user, Residential and Commercial customers consume 32%, while the Transportation and Industrial sectors consume 29% each, and Agriculture the remaining 10%. This is due to fuel switching to lower-emitting sources of electricity production, like natural gas. (All emission estimates from the U.S. Environmental Protection Agency (n.d.-b) Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2016.)

An earlier report, released in May 2014, entitled U.S. Climate Has Already Changed, Study Finds, Citing Heat and Floods (Gillis, 2014) concluded with nearly as much scientific certainty, but not as much precision on the economic costs, that the tangible impacts of climate change had already started to cause damage across the country. It cited increasing water scarcity in dry regions, torrential downpours in wet regions, and more severe heat waves and wildfires. The results of this report helped inform the Obama administration as it wrote a set of landmark climate change regulations. The following year, the EPA finalized President Barack Obama's signature climate change policy, known as the Clean Power Plan, which aimed to slash planet-warming emissions from coal-fired power plants. At the end of 2015, President Obama played a lead role in brokering the Paris Agreement. At the 2015 United Nations Climate Change Conference, or COP 21, which was held in Paris on December 12, 2015, parties to the UN Framework on Climate Change (UNFCCC) reached a landmark agreement to combat climate change and to accelerate and intensify the actions and investments needed for a sustainable low-carbon future. The Paris Agreement builds upon the Convention and—for the first time—brings all nations into a common cause to make ambitious efforts to combat climate change and adapt to its effects, with enhanced support to assist developing countries to do so. As such, it charts a new course in the global climate effort (source: https://unfccc.int/process-and-meetings/the-paris-agreement/what-is-the-paris-agreement).

But in 2016, Republicans in general and Mr. Trump in particular campaigned against those regulations. In rallies before cheering coal miners, Mr. Trump vowed to end what he called President Obama's war on coal and to withdraw from the Paris deal. Since winning the election, his administration has moved decisively to roll back environmental regulations. For example, see "E.P.A. Prepares to Roll Back Rules Requiring Cars to Be Cleaner and More Efficient" (Davenport and Tabuchi, 2018).

The 2018 report puts the most precise price tags to date on the cost to the United States economy of projected climate impacts: $141 billion from heat-related deaths, $118 billion from sea level rise, and $32 billion from infrastructure damage by the end of the century, among others.

1.2: Going Green

This 2007 peak precipitated an increased focus on energy efficiency and on the development of alternative sources of energy, particularly renewables (which have the added benefit of not being subject to the price volatility of fossil fuels, but may have drawbacks that include intermittent availability and high initial capital costs), but also nuclear and clean-coal technologies. Going Green became the buzzword of the early 21st century. As a result, much of the work being performed at utilities has been focused on the potential impacts of conservation and energy efficiency on load forecasts, resource planning that includes noncarbon supply resources, and the preservation of shareholder value in the case of Investor-Owned utilities. At State Utility Commissions, regulators began asking tough questions about ratepayer impacts of utility investment in Demand-Side Management (DSM) programs, cost recovery, and not only the efficiency of investments but also the necessity of investments in generating capacity and related infrastructure. Subsequently, many states began crafting their own energy policies, including legislating mandates on Renewable Portfolios and Energy Efficiency Resource Standards (EERS). More specifically, states initiated Renewable Portfolio Standards (RPS), which require utilities to ensure that a percentage, or a specified amount, of the electricity they sell comes from renewable resources. States have created these standards to diversify their energy resources, promote domestic energy production, and encourage economic development. Roughly half of the growth in U.S. renewable energy generation since 2000 can be attributed to state renewable energy requirements. Figure 1.2 displays states and territories with RPS (dark green; dark gray in print version) and those with voluntary Renewable Energy Standards or targets (lighter green; medium gray in print versions). States with neither are in light gray.

Figure 1.2

Figure 1.2 State Renewable Portfolio Standards and goals. (Source: http://www.ncsl.org/research/energy/renewable-portfolio-standards.aspx.)

Addressing the concerns raised by electric suppliers, especially those that are Investor Owned, which are allowed a rate of return on sales of electricity, thus generating profits for shareholders without causing harm to ratepayers, will require compromises among regulators, utilities, and consumers. As will be discussed in Chapter 3 (State Regulations, Policies, and Updates on States With Retail Choice), under the current regulatory structure in the United States, rates are typically set based on the Average Cost of service; for Investor-Owned firms, the allowed rate of return is earned by selling electricity, and the more sold the higher the return, or profit. For Investor-Owned utilities (IOUs), which have a fiduciary to shareholders, any action geared toward reducing sales tends to be avoided.

The reduction in greenhouse gas emissions is a global issue that transcends regulatory structure—whether one is an electric customer in a deregulated European market or in the U.S. where the price of electricity is subject to a mix of regulation and market mechanisms, the end result will be the same: Decarbonizing electricity will entail extra costs that will be reflected in rates, which should be set to incentivize consumers to make appropriate choices and to promote the efficient allocation of resources.

According to a recent National Conference of State Legislators report entitled State Renewable Portfolio Standards and Goals (April 2020), these RPS requirements can apply only to Investor-Owned utilities (IOUs) but many states also include municipalities and Electric Cooperatives, though their requirements are equivalent or lower. In many states, standards are measured by the percentage of retail electric sales. Iowa and Texas, however, require specific amounts of renewable energy capacity rather than percentages, and Kansas requires a percentage of peak demand. According to Lawrence Berkeley National Laboratory, 20 states and Washington, D.C., have cost caps in their RPS policies to limit increases to a certain percentage of ratepayers’ bills. One state caps RPS gross procurement costs.

1.3: And Talking About Going Green …

A recent article in CNN Business (Egan, 2019) entitled More bad news for coal: Wind and solar are getting cheaper aptly describes the situation (source: https://www.cnn.com/2019/03/25/business/coal-solar-wind-renewable-energy/index.html):

"The simple laws of economics threaten to doom America's remaining coal power plants. Wind and solar costs have plunged so rapidly that 74% of the US coal fleet could be phased out for renewable energy – and still save customers money, according to a report released on Monday by Energy Innovation, a nonpartisan think tank.

That figure of at-risk coal plants in the United States rises to 86% by 2025 as solar and wind costs continue to plunge.

The research demonstrates how it's increasingly more expensive to operate existing coal plants than build clean energy alternatives.

‘US coal plants are in more danger than ever before,’ Mike O’Boyle, director of electricity policy at Energy Innovation, told CNN Business. ‘Nearly three-quarters of US coal plants are already zombie coal, or the walking dead.’

That's despite President Donald Trump's promise to revive the beleaguered coal industry. Trump declared the end of the ‘war on coal’ and slashed regulations that clamped down on the emissions from coal-fired power plants."

The article goes on to state that:

Glencore will cap coal production, but some climate groups say that isn't good enough. And late last year, the administration announced plans to reverse an Obama-era coal emissions rule to make it easier to open new coal plants. Trump even appointed Andrew Wheeler, a former coal lobbyist, to lead the EPA.

Trump administration efforts to cut environmental regulations are too little, too late to save coal, O’Boyle said. He goes on to state that:

Coal's biggest threat is now economics, not regulations.

1.4: And Speaking of Economics…

Given all of this, much of the work that is being performed at utilities has been 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 will 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 (i.e., Marginal Costs) via the energy charge. Instead, other motivations tend to guide the rate-making process, politics being among them (these will be detailed later and in Chapter 10, The Efficient Pricing of Electricity: Marginal-Cost Pricing).

In the Preface, Figure P.3 displayed a market in equilibrium in which the market clearing price (P*) and output (Y*) were set by the interaction of the demand and supply (or Marginal-Cost) Curves. In this situation, it is clearly the case that:

si1_e

which as the introductory economics textbooks tell us is both allocatively and productively efficient. In addition, Marginal-Cost Pricing yields a welfare-maximizing outcome in which both the consumer and the producer receive the maximum benefit that is possible. This will be discussed in much more detail in Chapter 3, State Regulations, Policies, and Updates on States With Retail Choice and Chapter 10, The Theory of Efficient Prices. But for now, an excerpt from Marginal cost pricing for utilities: a digest of the California experience makes this point well.

1.5: 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 so that they could evaluate the appropriate economic level and timing of their use of utility services. Thus, the buying decisions of consumers would be the means by which the end purpose of economic efficiency would be reached.

B. The Theory (2)

Quoting Professor Kahn, normative/welfare microeconomics concludes that under pure competition, price will be set at marginal cost (i.e., 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) (I, pp. 16–17).

The basis for the theory is clear-cut: 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 are directing 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 will be purchased, maximizing consumer satisfaction. If they are charged more, less than optimum quantities will be purchased: The sacrifice of other foregone products will have been overstated. If they are charged less, the production of the product will be greater than optimum: The sacrifice of other foregone products will have been understated. A price based on Marginal Costs is presumed to convey price signals that will 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 inability thus far to estimate/calculate accurately the Marginal Cost of distributing electricity to various types of end users. And this is the aspect of the puzzle that has been ignored until now and 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 will provide the proper incentives to both producers and consumers to make the appropriate investments in energy efficiency, Demand-Side Management, and conservation in general? (This will be discussed in more detail in Chapter 10, The Efficient Pricing of Electricity: Marginal-Cost Pricing.)

Note

I am not ignoring the Naturally Monopolistic nature of the Electric Industry, which will be discussed in Chapter 2, The Sustainability of a (Natural) Monopoly.

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 gasses.

1.6: A Brief Overview of the United States Electric Market

The Structure of the United States 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 1.3 displays the structure of the Electric Industry in the United States in 2017. More than 72% of electric customers are served by Investor-Owned utilities.

Figure 1.3

Figure 1.3 The structure of the Electric Industry in the United States, 2017.

According to the U.S. Energy Information Administration's (EIA) electric power sector survey data, almost 3000 electric distribution companies—or utilities—were operating in the United States in 2017. The EIA classifies utilities into three ownership types: Investor-Owned utilities, publicly run or managed utilities, and Cooperatives. Although there are fewer Investor-Owned utilities than the other two types of utilities, they tend to be very large. Investor-Owned utilities serve three out of every four utility customers nationwide. (Source: U.S. Energy Information Administration (n.d.).)

The Players and Their Incentives

In order 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 to 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 estimate accurately 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 as follows.

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 who 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 they are operating, and whether they are vertically integrated or not. Each has its own objective function, which will be 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 breakeven constraint under a regulated price, Pr, while procuring (or generating) enough electricity to satisfy market demand, Ym. That is,

si2_e

   (1.1)

Subject to

si3_e

And

si4_e

where Y = total output.

Under the type of regulation to which the utility is subject, which will be 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 which have been established to serve their communities at cost. While some of them 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 Administration (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 breakeven constraint (i.e., that total revenues cover Total Costs). This is given by Eq. (1.2):

si5_e    (1.2)

Subject to:

si6_e

where Y = output and P = price.

Organizational types include municipals, public power districts, and state authorities. Publicly Owned utilities are exempt from certain taxes and can obtain new financing at lower rates than Investor-Owned utilities typically can. In addition, the former are given priority in the purchase of the less-expensive power that is produced by Federally Owned generators. These are discussed in much more detail in Chapter 3 (State Regulations, Policies, and Updates on States With Retail Choice).

Cooperatively Owned Firms

Rural Electric Cooperatives (RECs) are owned by the members of the Cooperative and were established to provide electricity to their members, who reside in rural areas that were deemed too costly to serve by Investor-Owned entities. (This will be discussed in more detail in the case studies that are presented in Chapters 7 and 8, Can Rural Electric Cooperatives Survive in a Restructured U.S. Electric Market? An Empirical Analysis and A Test of Vertical Economies for Nonvertically Integrated Firms: The Case of Rural Electric Cooperatives.)

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 that carries a lower interest rate than the market does. 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 Cconsumer Surplus (CS) plus Producer Surplus (PS) (see Figure P.3), which is due to the coincidence of sellers and buyers. The objective function is displayed in Eq. (1.3). (The Cooperatives are also subject to satisfying market demand, Ym.)

si7_e    (1.3)

Subject to:

si4_e

where

PS = the area below P* above the supply curve in Figure 1.4

f01-04-9780128213650

Figure 1.4 Average-Cost Pricing.

Rate-of-return regulation creates a deadweight loss since price (PR) is set above Marginal Cost, which yields a price of P*. (The deadweight loss is approximated by the shaded triangle.) However, this loss is de minimis when compared to the lost Consumer Surplus from monopoly pricing without regulation, which is given by