Evolution of the Electric Industry Structure in the U.S. and Resulting Issues

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1 Evolution of the Electric Industry Structure in the U.S. and Resulting Issues Prepared for: Electric Markets Research Foundation Navigant Consulting, Inc th Street NW Suite 700 Washington, DC Navigant Consulting, Inc.

2 Copyright This report is protected by copyright. Any copying, reproduction, performance or publication in any form without the express written consent of Navigant Consulting, Inc. is prohibited. No Warranties or Representations, Limitation of Liability This report (The Report ) was prepared for Electric Markets Research Foundation on terms specifically limiting the liability of Navigant Consulting, Inc. ( Navigant ). Navigant s conclusions are the results of the exercise of its reasonable professional judgment based upon information believed to be reliable. This Report is provided for informational purposes only. Navigant accepts no duty of care or liability of any kind whatsoever to the reader or any other third party, and all parties waive and release Navigant for all claims, liabilities and damages, if any, suffered as a result of decisions made, or not made, or actions taken, or not taken, based on this report. Use of this Report by reader for whatever purpose should not, and does not, absolve reader from using due diligence in verifying the Report s contents. Electric Markets Research Foundation Navigant conducted this study for the Electric Markets Research Foundation (EMRF). EMRF was established in 2012 as a mechanism to fund credible expert research on the experience in the United States with alternative electric utility market structures those broadly characterized as the traditional regulated model where utilities have an obligation to serve all customers in a defined service area and in return receive the opportunity to earn a fair return on investments, and the centralized market model where generation is bid in to a central market to set prices and customers generally have a choice of electric supplier. During the first few years of restructured markets, numerous studies were done looking at how these two types of electric markets were operating and the results were mixed. But since those early studies, limited research has been done regarding how centralized markets and traditionally regulated utilities have fared. The Electric Markets Research Foundation has been formed to fund studies by academics and other experts on electric market issues of critical importance Navigant Consulting, Inc.

3 Table of Contents 1. Executive Summary... i History and Development of Traditional Regulation and Competitive Markets... i Today s Two Broad Models... iii System Reliability... iv Environmental Issues... v Relative Allocation of Risks over Time... vi Responsibilities for Planning and the Types of Planning Performed... vi Innovation and the Levels of Research and Development Pursued... vii State and Federal Government... viii 2. Introduction History and Development of Traditional Regulation and Competitive Markets Development of Traditionally Regulated Markets Period of Growth and Declining Costs, Slowed Growth and Inflation, Seeds of Competition, The Advent of Centralized Markets, Traditional Regulation and Centralized Markets Today Today s Two Broad Models Current Status of Centralized Wholesale Generating Markets Todays Centralized Wholesale Generating Markets Energy Markets Bilateral Wholesale Generation Today s Retail Choice Status Cost Based Rates and Traditional Utility Regulation The Retail Choice Model Differences Between the Traditional and Retail Choice Models Retail Choice Markets Pricing for Generation Services System Reliability Development of the Mandatory Reliability Standards Transmission Reliability The NERC Standards and Who Must Comply Role of the Registered Entities and States Compliance Monitoring and Enforcement Resource Adequacy Navigant Consulting, Inc. Page i

4 6. Environmental Issues Impacts of Environmental Regulation Differing Impacts for Different Structures Greenhouse Gas Initiatives Renewable Portfolio and Energy Efficiency Resource Standards Mercury and Air Toxics Standards National Ambient Air Quality Standards Clean Air Interstate Rule/Cross State Air Pollution Rule Regional Haze Cooling Water Intake Structures Coal Combustion Residuals Relative Allocation of Risks over Time Traditionally Regulated Model Centralized Market Model Responsibilities for Planning and the Types of Planning Performed The Transmission Planning Framework Regional Planning and the Inclusion of Non Incumbent Transmission Developers Interregional Planning Coordination Cost Allocation Planning for Public Policy Requirements Transmission Siting and Transmission Grid Expansion Adequacy Planning and Integrated Resource Planning Integrated Resource Planning and Procurement Plans Innovation and the Levels of Research and Development Pursued Declining Costs and Increasing Flexibility of Generation Technologies Emergence of Demand Side Alternatives Smart Grid Research and Development Investment State and Federal Government Navigant Consulting, Inc. Page ii

5 List of Figures and Tables Figures: Figure 1. Historical Timeline Figure 2. Historical Timeline Figure 3. Historical Timeline Figure 4. Historical Timeline Figure 5. Historical Timeline 1999 Present Figure 6. Regional Transmission Organizations Figure 7. Status of Electricity Restructuring (Retail Choice) by State Figure 8. NERC Regions Figure 9. State RPS Policies Figure 10. State EERS Policies Figure 11. Forecasted Energy Sales from Alternative Suppliers Figure 12. States with Integrated Resource Planning (or similar planning process) Tables: Table 1. Wholesale and Retail Market Structure by State Table 2. Centralized Markets and their Attributes Table 3. Examples of Market Based Resource Adequacy Mechanisms Table 4. Examples of Cost Allocation Approaches Used by Planning Region Table 5. Estimated National Average Levelized Cost of New Generation Resources in Table 6. EPRI Planned R&D Funding for 2013 and Navigant Consulting, Inc. Page iii

6 1. Executive Summary This paper explores the key policy questions surrounding two broad regulatory/market structures that currently exist in the United States (U.S.) in varying degrees: traditional utility regulation without centralized markets on the one hand, and centralized electricity markets, often involving restructured regulation, on the other. 1 The paper is intended as an educational piece for non industry experts on how and why electric utility regulation has evolved and one model has developed in some areas of the country while not in others. This paper does not provide a critique of the market structures nor a quantitative comparison between the two models. This paper may also serve as a foundation for identifying the issues that characterize the key differences between the approaches and help guide decisions on future research projects for the Electric Markets Research Foundation. History and Development of Traditional Regulation and Competitive Markets The evolution of the U.S. electric industry is a history of adaptation to changes in the operating and regulatory environment. The first chapter traces the history of the two regulatory/market structures. It begins from the early structure of the electric utility industry as it developed around the concept of a central source of power with vertically integrated utilities and regulation of these entities by municipal and state governmental entities. During the early twentieth century, electric systems grew rapidly. Under the Rural Electrification Act service was extended to unserved, or underserved, rural areas, which also gave rise to rural electric cooperatives in many areas of the U.S. Disenchantment with privately owned power spurred the development of government owned utilities, particularly hydroelectric power facilities. During the presidency of Franklin D. Roosevelt (1933 to 1945), a number of these facilities were built, ushering in the beginning of publicly owned power. In 1920, the Federal Water Power Act was passed to coordinate the development of these hydroelectric projects. This act created the Federal Power Commission (FPC), now the Federal Energy Regulatory Commission (FERC). In 1935 the law was renamed the Federal Power Act and the FPC s regulatory jurisdiction was expanded to include all interstate electricity transmission and sales of power for resale 1 Within the two different general models there are further distinctions. The traditionally regulated model is often characterized at the wholesale level by bilateral resource transactions while at the retail level the traditional vertically integrated utility provides / purchases all functions required to provide service to the end users. The centralized market model generally involves the existence of a Regional Transmission Organization (RTO) or Independent System Operator (ISO) that administer centralized, bid based markets at the wholesale level with some degree of retail competition where the customer has the right to procure power competitively with transmission and distribution service provided by a regulated utility. Transmission and distribution under both models remains governed by a cost of service regulatory approach. Further, the reader should be aware that there may be instances where regions or entities generally characterized as functioning under a certain broad model may not exhibit all features of that model. For example, there are regions that have centralized wholesale energy markets that may not have implemented retail choice in all states within that region. Similarly, there are regions that remain traditionally regulated but have elements of centralized markets and retail choice Navigant Consulting, Inc. Page i

7 and formed the basis for federal jurisdiction over the electric and natural gas industries, and the responsibilities of the FERC. In that same year, after several large holding company systems collapsed, the Public Utility Holding Company Act of 1935 (PUHCA) was passed, giving the Securities and Exchange Commission responsibility for regulating utility holding companies. Under Title II, PUHCA charged the FPC with regulating utilities involved in interstate wholesale marketing or transmission of electric power. Regulatory administration of the rate case established base rates based on the actual normal costs of providing service determined by the utility s revenue requirement. A number of damaging events occurred in the 1960s and 1970s that interrupted the growth that had occurred in the prior several decades. First, the Northeast Blackout of 1965 raised concerns about reliability; then, the passage of the Clean Air Act of 1970 and its amendments in 1977 increased utility costs to reduce polluting emissions. And, most significantly, the Oil Embargo of resulted in increases in fossil fuel prices. In 1978, Congress pursued legislation to address these pressures by reducing U.S. dependence on foreign oil and developing renewable and alternative energy sources. The Public Utility Regulatory Policies Act of 1978 ushered in a greater reliance on market forces to set wholesale energy prices, while requiring utilities to buy power at their avoided cost from unaffiliated alternative energy resources meeting a number of qualifications. Throughout the late 1980s, utility interest in wholesale transactions grew, prompted by a number of factors. Some utilities found themselves with excess generation because expected demand growth did not meet projected levels. In addition, in the wake of aggressive utility construction programs, regulators determined that some costs were imprudent and refused to allow the utilities to recover them in rates. Utilities sought to sell electricity in wholesale transactions at market based rates, and FERC would grant these requests upon a showing that the utility could not exercise market power to set prices. Two significant policy decisions occurred in the 1990s that provided a foundation for energy market development. The first was the passage of the federal Energy Policy Act of 1992 (EPACT), which created a number of incentives for market development. The second was the cornerstone in the creation of competitive wholesale power markets, FERC s Order No Order No. 888 strove to eliminate anticompetitive practices and undue discrimination in transmission services through a universally applied open access transmission tariff. At the same time these changes were occurring in the wholesale electricity markets, a growing number of states were also pursuing a reliance on competitive markets for the retail supply of electric power. This typically required the incumbent utility to divest some or all of its generation and become a wires only distribution utility. By 2000, FERC was calling for the voluntary formation of regional transmission organizations (RTOs) through its Order No The basis of Order No was FERC s belief that RTOs would facilitate the continued development of competitive wholesale power markets and would lead to improvements in reliability and management of the transmission system, eliminating any remaining discriminatory practices. However, concurrent with FERC s efforts under Order No. 2000, challenges were arising in the California markets. In 2001, California suffered from flaws in its power market structure leading to the insolvency of one of the largest utilities in the state. Following the California energy market crisis and a blackout that affected a large portion of the northeastern U.S. and Canada in 2003, Congress enacted the Energy Policy Act of 2005 (EPAct 2005) on August 8, This legislation provided FERC greater authority to oversee wholesale electricity markets. FERC subsequently issued Order No. 890 in 2013 Navigant Consulting, Inc. Page ii

8 early 2007 to correct flaws in its pro forma Open Access Transmission Tariff (OATT) that had been uncovered during the ten years since Order No. 888 was issued. During the autumn of 2008, large disruptions in the financial markets also uncovered vulnerabilities in the electricity markets. In response, FERC issued Order No. 741 proposing extensive revisions to its policy on RTO/Independent System Operator (ISO) credit practices. Congress took additional actions in response to the 2008 financial crisis, including enacting the Dodd Frank Act, which had the potential to affect energy trading companies and wholesale energy markets. Today s Two Broad Models At the wholesale level, bilateral transactions prevail in the Southeast, most of the Southwest, parts of the Midwest and the West, excluding California. Under this regime, utilities engage in wholesale physical power transactions through bilateral arrangements ranging from standardized contract packages, to customized, complex contracts known as structured transactions. This is characterized as a component of the traditionally regulated model. A centralized market model is the norm in the Northeast, Mid Atlantic, much of the Midwest, the Electric Reliability Council of Texas (ERCOT), and California. In these markets participants bid/offer resources into a centralized market and are paid a uniform clearing price. Similarly, two models are currently employed in the United States to deliver electric power to retail consumers. The traditional model is the Vertically Integrated Utility, where various services are bundled, meaning that all energy and energy delivery (transmission and distribution) services, as well as ancillary and retail services, are provided by one entity. 2 Customers do not have the option of selecting another provider for any of these services, and the utility s charges are set entirely by the regulatory authority or governing body in the case of public power. In contrast, under the retail choice model, customer choice has been partially or fully implemented. In this model, customers may often select their energy provider, and the utility will deliver the power. Non utility energy providers can set their own pricing for power, but the utility s charges for delivery and related services are set by the regulatory authority. Traditional bundled pricing may also be available from the utility, for some or all types of customers. 3 In the United States, traditional utility pricing (or ratemaking) is cost based, meaning that the utility is allowed to charge prices that will recover prudent operating costs and provide an opportunity to earn a reasonable rate of return on the property devoted to the business. Among the historical criticisms of cost based ratemaking are that it creates an incentive to over invest in capital intensive projects and fails to provide utilities proper incentives to operate efficiently. 2 Although in the case of Public Power, generation and transmission may be provided by joint authorities and bundled by the local distribution utility. 3 It is worth noting that the Retail Choice model encompasses a spectrum of features that may vary from state to state. The key features, such as the existence of retail choice for at least some customers and the availability of organized wholesale energy markets are the same, although there may be differences in the manner and degree to which these features are implemented Navigant Consulting, Inc. Page iii

9 The customer choice aspect of the Retail Choice model was introduced in the United States in the 1990s in response to high regulated prices in some regions relative to the cost of wholesale markets. Many consumer groups found retail competition attractive because the prices in emerging wholesale markets were significantly below the regulated retail prices charged by utilities. In contrast to the traditional regulated model, the customer choice feature of the retail choice model limits the operation of the regulated utility to the transmission and distribution functions, where traditional cost based pricing is implemented and approved by regulators. Generation services are provided either by competitive service providers or through a default provider of last resort. Retail choice also has its criticisms; among them are that residential participation in some retail markets has been slow to materialize, in part because retail suppliers have not pursued residential customers as aggressively as commercial customers due to their relatively small size. Other factors may include a lack of incentives (i.e., lower prices) or information. System Reliability Reliability standards or criteria used for planning and operations are an integral part of the electric power industry and have been since the very first systems were developed in the late nineteenth century. There are two principal components to bulk power system (BPS) reliability resource adequacy and transmission security. 4 The area of transmission security is governed by FERC, the North American Electric Reliability Corporation (NERC), and the Regional Entities (REs). The states still retain a role in resource adequacy and in regulating the reliability of local distribution systems. Over the years, a series of blackouts (the 1965 Northeast Blackout, the blackout on the East Coast in July 1977, the West Coast blackouts in July and August of 1996, and the blackout on August 14, 2003 affecting the northeastern U.S. and Canada) led to the creation of NERC and its REs. Prior to 2005, compliance with reliability standards was voluntary. The enactment of EPAct 2005 eliminated the voluntary nature of the NERC reliability standards. FERC was charged with the ultimate oversight of electric reliability of the Bulk Power System (BPS). NERC, as the independent Electric Reliability Organization (ERO), along with its REs develop mandatory reliability standards subject to FERC approval, monitor industry participants compliance with these standards, and can levy penalties for noncompliance up to one million dollars per day per violation for the most serious violations. Currently, there are 102 standards with more than 1,300 requirements applicable and mandatory in the U.S. Within the United States, other than Alaska and Hawaii, all users, owners, and operators of the BPS must comply with the reliability standards developed by the ERO and regional reliability standards developed by the REs. This responsibility extends FERC jurisdiction not only to the government owned and other so called non jurisdictional utilities, but also to utilities in Texas as well as to a wide range of non utility entities that use the transmission grid. The ERO s compliance registry process is used to identify the set of entities that are responsible for compliance with a particular reliability standard and the applicability section of a particular reliability standard determines the applicability of each reliability standard. The NERC Functional Model provides 4 Reliability is also dependent at the local level on the reliability of the local distribution system Navigant Consulting, Inc. Page iv

10 guidance concerning the type of function for which an entity is registered and, therefore, their role in maintaining reliability. Regardless of whether entities are located in regions that have centralized markets and RTOs/ISOs or a traditional regulation structure, the REs and NERC will identify who must be registered and as what type of functional entity. The primary difference between functional responsibilities of entities that exist in RTOs/ISOs and those that do not is that RTOs/ISOs often perform the functional roles of balancing authority, reliability coordinator, transmission operator, and transmission planner. In regions that do not have RTOs/ISOs, the electric utility often performs all the functions and is registered as multiple functional entity types. The states and other governmental entities that have regulatory oversight functions may participate as non voting members in NERC and RE activities, under the government sector, and may also provide comments in FERC proceedings. Two approaches have been applied to achieving the resource adequacy goals market based and an administrative approach. With a capacity market, suppliers receive periodic (i.e., annual or monthly) payments for providing reliable capacity to a system and Load Serving Entities (LSEs) are required by the regulatory standard to purchase the capacity. Examples of capacity markets are PJM, NYISO, and ISO NE. There are also other variations to the market based approach; these are energy only markets (in ERCOT) and markets with administrative resource adequacy requirements for LSEs (CAISO and MISO). One key concern for consumers is price volatility and uncertainty. Questions also remain as to how current market design will work to ensure capacity adequacy in the long term at economically efficient levels. Under the administrative approach, resource adequacy is achieved through traditional Integrated Resource Planning (IRP) and competitive resource solicitation. One key concern with the administrative approach is increased consumer cost due to uneconomic long term investment decisions. Examples of administrative approaches are the Southwest Power Pool, most of the Western Electricity Coordinating Council outside the CAISO, and the southeast U.S. Environmental Issues Market/regulatory structure plays an important role in whether and how environmental requirements and policies affect electric entities. Where the traditionally regulated model prevails, the impacts whatever they are fall on the utility and the associated costs flow to its customers through cost based rates. In contrast, where there has been a restructuring of utility regulation and the development of centralized electricity markets, impacts vary widely. A utility that owns no generation would not incur the direct expense of complying with environmental rules relating to emissions, although generators would try to raise prices to recover costs. Similarly, generation only entities would not normally be subject to renewable portfolio standards (RPS) or policies favoring the use of renewable energy resources. Independent generators in centralized markets are particularly sensitive to the costs of environmental regulation, since these generators rely on market pricing rather than cost of service rates. Uneconomic generation in competitive markets may be retired rather than operated at a loss for any extended period of time. Under the traditional regulated model, vertically integrated utilities are also sensitive to environmental regulation, including policies or regulations favoring renewables, since compliance would increase or decrease its costs Navigant Consulting, Inc. Page v

11 The costs and risks from proposed environmental regulations will differ by region, largely affecting those regions of the country with significant amounts of existing coal fired generation. Whether environmental costs end up being passed through in cost based rates or result in higher market based rates, the impact on electricity consumers in those regions will be considerable. Relative Allocation of Risks over Time Under the traditional regulated model, the allocation of risks is well established. The utility has a monopoly right to provide electric service to retail customers, who in turn are entitled to electricity at a reasonable cost. The utility s risk in the traditional model is that its rates will not recover its actual investment and operating costs or meet the rate of return required for its investors to risk their money. The utility also risks that its costs will be determined to have been prudently incurred and that it will receive timely recovery through the regulatory process. The customers face much of the risk of utility over investment or under investment (either through bad decision making or out of concern that it will not recover its costs), and unreliable service and high costs as a result of ineffective operations or bad decision making; to the extent the regulators allow utilities to recover their costs. In a centralized market model, the risks for customers and the mechanisms for addressing them are the same with respect to the transmission and distribution system. Rate cases and regulation are the principal tools to protect customers from monopoly abuses and to set the utility s pricing for the delivery of electricity. However, with respect to generation, the market sets wholesale energy prices. In these markets, many generators in a region compete with one another to supply electricity. These regions also rely on market forces to cause needed generation to be added when and where it is needed but some markets have found that these forces may not be enough incentive. A further complexity in some centralized markets is customer choice where a utility must be prepared to procure power for a changing customer base. Responsibilities for Planning and the Types of Planning Performed Planning functions encompass adequacy and transmission security planning. State and federal governments have overlapping responsibilities for these two aspects of planning. The oversight of resource adequacy planning has traditionally been a state function while transmission security planning, with the important exception of transmission siting, has now become governed by federal law and regulation overseen by FERC. In recent years, two key FERC Orders have encompassed the field of transmission planning. They are Order No. 890 and Order No. 1000, which apply to entities whether in RTO/ISO regions with centralized markets or not. Order No. 890 promoted increased open, transparent and coordinated transmission planning on sub regional (local) and regional levels. Order No built upon and extended many of the ideas initially introduced under Order No Among the changes introduced in Order No are requirements for regional and interregional planning, cost allocation, consideration of public policy requirements, and elimination of the Right of First Refusal in wholesale tariffs to construct new facilities. In areas where RTO/ISOs have formed, transmission planning often encompasses a larger region than previously existed and is coordinated around a centralized processes administered by the RTO/ISO. In areas where traditional regulation remains, planning is coordinated by the vertically integrated utilities 2013 Navigant Consulting, Inc. Page vi

12 or public power entities within their territory. These territories may also encompass large areas due to mergers and holding company consolidation. Both traditionally regulated and competitive market (RTO/ISO) regions have in place processes to coordinate planning with their neighboring entities. The authority over transmission siting is a patchwork quilt of overlapping and sometimes unclear divisions of authority. While the majority of siting authority currently lies with the states, there are instances where federal approvals are required. The Energy Policy Act of 2005 established a limited role for the U.S. Department of Energy (DOE) and the FERC in transmission siting. The act directed DOE to create transmission corridors in locations with adequate transmission capacity that had national interest implications. The act also granted FERC secondary authority over transmission siting in these corridors, which may not be exercised by FERC unless the state where the facility would be sited lacks the authority to issue the permit, the applicant does not qualify for the permit in the state, or the state has withheld approval of the permit for more than one year. While some regions have moved to develop capacity markets, discussed earlier, to ensure generation adequacy, many states, particularly in areas where the traditionally regulated model remains, have retained the IRP approach, which began in the late 1980s. Steps taken in an IRP include forecasting future loads, identifying potential supply side and demand side resource options to meet those future loads and their associated costs, determining the optimal mix of resources taking into account transmission and other costs, receiving and responding to public participation (where applicable), and creating and implementing a resource plan. Innovation and the Levels of Research and Development Pursued Innovations in the electric industry, technical and economic, have come about through the application of research and development (R&D) of projects by the electric sector, governments, and other industrial, communications, and technology sectors. The expansion of combined heat and power and natural gas fired combined cycle plants in the late 1970s into the 1990s was a strong contributing factor to growth in the class of non utility generation. The costeffectiveness of smaller increments of generation has reduced the need for utilities to periodically have large, lumpy, capital intensive investments and corresponding large additions to their rate base. Moreover, since generation can be added in smaller increments and with lead times closer to the time of anticipated need, the investment cycle has become smoother. This benefits both traditional and competitive market entities. Demand side management (DSM) induced reductions in load growth reduce or defer the need for new generation plant investment and the costs of the DSM alternatives may be less than the cost of new generation. Centralized market regions are gradually implementing market rules that seek to place supply and demand side options on equal footing with respect to bidding into capacity and energy markets. Traditionally regulated regions seek to maintain equal footing for these two types of options through integrated resource plans vetted by state regulators. In the last decade, or less, the Smart Grid has become a hot topic in political and academic circles as well as other groups not traditionally involved in the regular processes of the electric sector. The expectation 2013 Navigant Consulting, Inc. Page vii

13 is that Smart Grid implementation will generate potential savings to customers by providing them the tools to manage their energy consumption habits and costs, as well as providing potential savings to utilities and their customers through operating efficiencies. Utilities in both models would benefit from savings. Similarly, customers can benefit from smart meters and usage information under both models. R&D investment by electric utilities (including their contributions to the Electric Power Research Institute) is small when compared to other industrial sectors and when observed in the context of the role electricity plays in our national economy and society. However, historically, electric equipment manufacturers have provided the majority of the R&D in the sector; this is primarily because utilities cannot necessarily internalize the benefits of the innovations developed through R&D. No study has definitively assessed the impact of restructuring efforts on R&D investment in the electricity industry. However, several studies have noted a decline in R&D investment in some areas and concluded that utility restructuring is the likely cause. However, there are also studies that have concluded that the centralized market model encourages more innovation than the traditionally regulated model. 5 State and Federal Government The electric utility industry in the United States is regulated at the state and federal levels. State regulation extends to most areas of utility operations, rates, and end user issues. Federal regulation, founded on interstate commerce impacts, generally relates to the wholesale side of the utility business, including interstate transmission and sales of electricity for resale. State and Federal jurisdiction over transmission siting, resource adequacy and transmission security planning, and electric reliability have been discussed above. Investor owned utilities are subject to state regulation as to their duties to customers, system requirements, financing arrangements, and retail rates. Government owned utilities and rural electric cooperatives are not generally subject to regulation under state utility laws, but must follow the requirements of the ordinance or law establishing them and have governing boards that provide oversight. Under both the traditionally regulated model and the centralized market model, interstate transmission rates are approved by FERC and FERC regulates the interstate transmission and generation activities of public utilities. FERC does not regulate government owned utilities or most cooperatives, which are often referred to as non jurisdictional entities. In addition, because most of the Texas transmission grid is not interconnected with the rest of the interstate transmission grid, Texas is not subject to FERC rate regulation. In Texas, the state regulator is responsible for approving transmission rates (because Texas transmission is intrastate) as well as regulating all other aspects of the electric utility business in Texas. While FERC s regulatory reach is not absolute, FERC has effectively extended many of its regulations to non jurisdictional utilities through reciprocity. For example, if a non jurisdictional utility wants to take advantage of the terms of a public utility s Open Access Transmission Tariff (OATT), then it must itself have an OATT where the terms of service other than rates must comply with FERC requirements. 5 These studies are discussed in greater detail in section Navigant Consulting, Inc. Page viii

14 Similarly, in order to be part of the regional planning process and to take advantage of proposed cost allocation mechanisms, FERC has said that non jurisdictional entities have to agree to participate in the FERC regulated planning processes and be subject to the outcome of these processes Navigant Consulting, Inc. Page ix

15 2. Introduction This paper explores the key policy questions surrounding two broad regulatory/market structures that currently exist in the United States in varying degrees: traditional utility regulation without centralized markets on the one hand, and centralized electricity markets, often involving restructured regulation, on the other. The latter structure also generally involves the existence of a Regional Transmission Organization (RTO) or Independent System Operator (ISO). This paper provides a brief history of regulation and competition in the electric industry and identifies the issues that characterize the key differences between the two major regulatory/market structures, which for ease of reference are being called a traditionally regulated model and a centralized market model. 6 The paper is intended as an educational piece for non industry experts on how and why electric utility regulation has evolved and centralized energy markets have developed in some areas of the country and not in others. It focuses on consumer impacts and discusses how various issues are addressed under the two broad models as well as identifying ongoing issues and challenges. This paper does not provide a critique of the models nor a quantitative comparison between the two models. A secondary purpose of the paper is to serve as a foundation for identifying the issues that characterize the key differences between the two regulatory/market structures that will help guide decisions on future research projects for the Electric Market Research Foundation (EMRF) to meet its goal of informing the public policy debate on the pros and cons of the major market structures. 6 Within the two different general models there are further distinctions. The traditionally regulated model is often characterized at the wholesale level by bilateral resource transactions while at the retail level the traditional vertically integrated utility provides / purchases all functions required to provide service to the end users. The centralized market model generally involves the existence of a Regional Transmission Organization (RTO) or Independent System Operator (ISO) that administer centralized, bid based markets at the wholesale level with some degree of retail competition where the customer has the right to procure power competitively with transmission and distribution service provided by a regulated utility. Transmission and distribution under both models remains governed by a cost of service regulatory approach. Further, the reader should be aware that there may be instances where regions or entities generally characterized as functioning under a certain broad model may not exhibit all features of that model. For example, there are regions that have centralized wholesale energy markets that may not have implemented retail choice in all states within the region. Similarly, there are regions that remain traditionally regulated but have elements of centralized markets and retail choice Navigant Consulting, Inc. Page 1

16 3. History and Development of Traditional Regulation and Competitive Markets The evolution of the U.S. electric industry is a history of adaptation to changes in the operating and regulatory environment. During times of significant economic and technological change, policymakers adapted regulatory policy to ensure the public interest continued to be served, economic principles of efficiency and competition were advanced, and the reliable and efficient delivery of electric service to consumers was maintained. The decisions made by regulators and policymakers shaped the two regulatory paths that have emerged traditional rate making based on cost of service regulation and centralized market development. Today, both of these approaches co exist and continue to evolve to meet changing economic and technological challenges. The allocation of regulatory authority between the federal government and the states is distinguished by what constitutes interstate commerce and what constitutes intrastate commerce. 7 Furthermore, there is the preemptive effect of federal wholesale rate orders on state retail rate authority. 8 This dichotomy has resulted in a number of distinctions among industry participants as to whether they are subject to federal, state or both federal and state regulation by virtue of how they are organized and whether they operate within a single state. Further, distinctions as to the applicability of federal vs. state regulation turn on which specific physical and functional components of the electric system (e.g., generation, transmission, distribution, and customer service) are in question. The sections that follow describe, from the early beginning to present day, the key events that transformed approaches in electric regulation policy and the evolving approaches designed by regulators and policymakers on both the federal and state levels to meet those challenges. 7 See also, New York v. FERC, 535 U.S. 1 (2002). The court acknowledged that FERC correctly could choose not to regulate the transmission component of bundled retail sales. Bundled sales are sales that combine energy and transmission service as a single unit. 8 Under the Narragansett line of cases, Narragansett Elec. Co. v. Burke, 381 A.2d 1358 (1977), cert. denied, 435 U.S. 972 (1978), comprising what is now called the ʺfiled rate doctrine,ʺ state regulators must treat a utilityʹs FERC approved wholesale power costs as reasonable operating expenses in the companyʹs retail cost of service. In other words, the retail regulator cannot, in its retail rate hearing, question the reasonableness of the wholesale rate that the FERC has fixed Navigant Consulting, Inc. Page 2

17 3.1 Development of Traditionally Regulated Markets Figure 1. Historical Timeline The early structure of the electric utility industry developed around the concept of a central source of power supplied by efficient, low cost utility generation, transmission, and distribution. Regulation of utilities began in the late nineteenth century, with municipalities issuing franchises, often overlapping, as a method of regulation, promoting competition between utilities. This regulatory oversight derived from a series of nineteenth century court decisions in the U.S. that held industries such as grain elevators, warehouses, and canals were monopoly providers of service affected with the public interest 7 and that their rates and terms of service could therefore be regulated. 10 Municipal regulation gave way to state regulation following the passage of laws in New York and Wisconsin developing powerful state commissions. 11 In the early part of the twentieth century, the electric industry evolved quickly through the creation, growth, and consolidation of vertically integrated utilities. A rapid increase in electricity generation encouraged growth and consolidation of the industry to achieve economies of scale, which resulted in an expansion into more and more cities across wider geographic areas. 12 During this period, vertically integrated electric utilities produced approximately two fifths of the nationʹs electricity. 13 Over time, states granted these consolidated utilities monopoly franchises with exclusive service territories in exchange for an obligation to serve customers within that territory at rates for service based on stateregulated, cost of service ratemaking. 14 As utility service territories grew throughout the 1900s, state 9 Source: Navigant Consulting, Inc. 10 See Munn v. Illinois, 94 U.S. 113, 126 (1877). 11 There are alternative views of why the municipal regulation ended. The natural monopoly view is that state regulation was necessary to distance the regulator from the local level and to enforce uniform regulation throughout the jurisdiction. This view assumes that one firm can serve the market more cheaply than two or more firms and can keep out rival firms by expanding output and lowering price when threatened. The alternative view was that the move from municipal to state regulation was in the public interest. See R. Richard Geddes, A Historical Perspective on Electric Utility Regulation, CATO REVIEW OF BUSINESS, 8.pdf, at pp See U.S. Electric Power Industry Context and Structure, Analysis Group for Advanced Energy Economy (November 2011) ( AEE Context and Structure ). 13 Energy Information Administration, The Changing Structure of the Electric Power Industry 2000: An Update (October 2000) Part I, Chapter 2, pg. 5 ( EIA Changing Structure ). 14 See AEE Context and Structure Navigant Consulting, Inc. Page 3

18 regulation of privately owned electric utilities increased. Among the first states to regulate electric utilities were Georgia, New York, and Wisconsin, which established state public service commissions in These states were soon followed by more than 20 other states. Part of the justification for exclusive service territories was that a single distribution system in an area was more efficient due to economies of scope; competing distribution facilities on thoroughfares and in communities would require redundant capital investment and expenditures. Despite the lure of exclusive franchises, some areas were inevitably less attractive than others. This was particularly true with respect to rural areas, where the progress of electrification was much slower than in urban areas. The Rural Electrification Act was enacted to provide power to unserved, or underserved, rural areas and gave rise to the advent of rural electric cooperatives in many areas of the U.S. During the 1920s and the early years of the Depression, the public became disenchanted with privately owned power and began to support the idea of government ownership of utilities, particularly hydroelectric power facilities. This disenchantment resulted primarily from abuses imposed by holding companies on utilities, and ultimately on their customers, causing the price of electricity to increase. A fierce debate at the time was whether government owned hydroelectric power facilities could produce power cheaply and sell it to publicly owned utilities for distribution. During the presidency of Franklin D. Roosevelt (1933 to 1945), a number of these facilities were built, ushering in the beginning of publicly owned power. 16 The development of hydroelectric projects in the United States was coordinated under the Federal Water Power Act in The act created the Federal Power Commission (FPC), now the Federal Energy Regulatory Commission (FERC), as the licensing authority for these plants. The FPC also regulated the interstate activities of the electric power and natural gas industries. The responsibility of the FPC was to maintain just, reasonable, and nondiscriminatory rates to the consumer. In 1935 the law was renamed the Federal Power Act (FPA), and the FPC s regulatory jurisdiction was expanded to include all interstate electricity transmission. The FPC was also given authority to regulate nonfederal hydropower projects. The Federal Power Act is the core legislation providing federal jurisdiction over the electric and natural gas industries and defining the responsibilities of the FERC. 17 However, the FPA exempts 15 Energy Information Administration, Annual Outlook for U.S. Electric Power 1985, DOE/EIA 0474(85) (August 1985), pg EIA Changing Structure, Part I, Chapter 2, pg. 6. As part of the program, President Roosevelt proposed that the government build four hydropower projects and, within a year after his proposal, his administration began to implement the projects. Hoover Dam began generation in 1936, followed by other large projects. Grand Coulee, the nation s largest hydroelectric dam, began operation in Under the Tennessee Valley Authority Act of 1933, the federal government supplied electric power to states, counties, municipalities, and nonprofit cooperatives. The Bonneville Project Act of 1937 pioneered the federal power marketing administrations. From 1933 to 1941, one half of all new capacity was provided by federal and other public power installations. Public power contributed 12 percent of total utility generation, with federal power alone contributing almost 7 percent. See Id. It should be noted that the federal power generating entities were not subject to regulation by States. 17 See AEE Context and Structure Navigant Consulting, Inc. Page 4

19 certain entities from many provisions of the Act, including entities in the state of Texas, which is a single state Interconnection with no interstate transactions, as well as certain non public utilities (i.e., Municipal Utilities, Cooperatives, Power Marketing Administrations, and state authorities). 18 After several large holding company systems collapsed, an investigation by the Federal Trade Commission was ordered, leading eventually to the passage of the Public Utility Holding Company Act of 1935 (PUHCA). PUHCA was aimed at breaking up the unconstrained and excessively large trusts that then controlled the nationʹs electric and gas distribution networks. 19 PUHCA gave the Securities and Exchange Commission (SEC) responsibility for regulating utility holding companies. Under Title II of PUHCA, the FPC also regulated utilities involved in interstate wholesale marketing or transmission of electric power. 20 One of the most important features of the Act was that the SEC was given the power to break up the large interstate holding companies by requiring them to divest their holdings until each became a single consolidated system serving a circumscribed geographic area. Another important feature of the law permitted holding companies to engage only in business that was essential and appropriate for the operation of a single integrated utility. 21 In the Supreme Court case of FPC v. Hope, the Court stated: [t]he rate making process i.e., the fixing of just and reasonable rates, involves a balancing of the investor and the consumer interest. 22 This balancing of consumer and investor interests evolved into what has become known as the regulatory compact. 23 In addition, Hope gave rise to an End Results Doctrine relating to rates. Under this doctrine, only the end result not the methodology matters in determining whether rates are just and reasonable. 24 The regulatory compact is premised on the existence of a set of rights, obligations, and benefits that are shared between utilities and their customers. 25 In return for the grant of a franchise and the right to recover its costs plus a market determined profit equal to the cost of debt and equity capital, the 18 Section 201(f) of the FPA generally exempts the United States, a state or any political subdivision of a state, an electric cooperative that receives financing under the Rural Electrification Act of 1936 (7 U.S.C. 901 et seq.) or that sells less than 4,000,000 megawatt hours of electricity per year from Part II of the FPA. However, it should be noted that the reliability section of the FPA added under EPACT 2005 extends to entities that were described under 201(f) of the FPA. See Federal Power Act 215(b), 16 U.S.C 844o(b). 19 EIA Changing Structure, Part I, Chapter 4, pg Ibid., Part I, Chapter 2, pg Ibid., Part I, Chapter 4, pg Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944). 23 The concept of a regulatory compact is not that there is a formal agreement between the utility and government but rather that the legal obligations of regulators and utilities have evolved through a long series of court decisions, See RAP Publications, Electricity Regulation in the US: A Guide (March 2011), pp Dr. Karl McDermott, Cost of Service Regulation In the Investor Owned Electric Utility Industry (June 2012), pg. 3 ( Cost of Service Regulation ). 25 Cost of Service Regulation, pg. vii Navigant Consulting, Inc. Page 5

20 investor owned utility must submit to rate regulation and provide service efficiently. 26 The regulatory compact has a two fold focus: (1) establish prices based on the actual prudent costs (i.e., avoid monopoly pricing); and (2) provide incentives to maintain a reasonable level of efficiency in serving the customers. 27 Under traditional utility regulation, this determination of the appropriate cost of service that can be charged by the utility is determined through what developed as the rate case process, which examines the prudency of costs after they are incurred. 28 This form of regulation serves as an administrative replacement for market mechanisms in determining what costs were efficient Period of Growth and Declining Costs, Figure 2. Historical Timeline From the 1940s through the 1960s the industry saw extensive growth and increasing electricity consumption. Economies of scale increased as new, larger generating units were built which drove down costs, and stimulated an increased demand for electricity. 31 Regulatory administration of the rate case process described above became routine during this period and established the normal course of utility operations and funding. Utilities would provide service to all customers in their franchise area and in return were guaranteed a reasonable return on their investments determined through the rate case process. Both utilities and customers have benefited from this relationship; utilities received a guaranteed service territory with a return on investment (ROI) and customers received protection from monopoly pricing. The rate case would establish rates based on the normal costs of providing service determined by the revenue requirement. The utility had to work within a framework of regulatory lag, demand growth, and cost instability in real time operations. Exposure to real time operations provided both a risk and 26 See Ibid. The utility was obligated to supply service efficiently, but had the right to recover its costs, including an opportunity to earn a return/profit equal to its market determined cost of debt and equity capital. Ibid. 27 Ibid., pg. vii. 28 A rate case is a formal administrative process in which the utility provides support for its proposed cost of service and the public, including the regulatory body, is provided the opportunity to scrutinize the data, policy arguments, and any other relevant information. Ibid., pg Ibid., pg. viii. 30 Source: Navigant Consulting, Inc. 31 Cost of Service Regulation, pg. ix Navigant Consulting, Inc. Page 6

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