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A Perspective on Regulatory Risk in the Electric Industry
CHAPTER 1
A Perspective on Regulatory Risk in the Electric Industry William G. Riggins1,2 Vice President and General Counsel, Kansas City Power and Light
Introduction “Past experience, if not forgotten, is a guide to the future.”3 The past experiences of the electric industry provide a guide to predicting, and thus better managing, risks created by changing regulation. The industry’s history is represented by continuing cycles of phenomena that create socio-political dynamics that drive regulatory initiatives. These regulatory initiatives, and in some cases their unintended consequences, can have a dramatic impact on the ability of electric utilities to meet their public service obligations while, at the same time, maintaining their financial commitments to investors. This chapter begins by presenting and summarizing some of these historical patterns and themes. It then assesses current issues and provides some suggestions for thinking about, and planning for, an uncertain future. Historical Scenarios Why an entrepreneurial industry became subject to economic and quality of service regulation4 Entrepreneurs were responsible for the creation and expansion of the electric utility industry in the late 19th and early 20th centuries. The cost of constructing a central 1
William G. Riggins is General Counsel, Great Plains Energy. The author is indebted to Jerry Pfeffer, Gerald Reynolds, and Robert Zabors for their contributions to this chapter. 3 A Chinese proverb. 4 Sources for this subsection include Welch, Francis X., Cases and Text on Public Utility Regulation, 1st ed. (Washington: Public Utilities Reports, Inc., 1961), pp. 543–544, 547–548, 550–552; Vennard, Edwin, The Electric 2
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generating station and distribution facilities was high. Initially, therefore, electricity was considered a luxury. Its use was limited to “public service” applications such as street lighting and to more affluent customers. However, demand grew as new, efficiency enhancing devices that used electricity, such as the electric motor, were created. These devices came to be considered necessities, not luxuries, and so did electricity. When problems began to emerge with the supply and pricing of this essential service, regulation of rates and service emerged as the public policy response. Initially, electric companies were formed and operated wherever the investors thought they could profitably sell electricity. Companies competed vigorously with each other for customers. They operated at various voltages with different kinds of equipment. There was significant duplication of facilities. In some cases, multiple sets of wires were strung haphazardly throughout city landscapes. Companies engaged in price wars to increase market share for industrial and commercial customers who were able to shop among suppliers. They offset any revenue losses by charging extremely high rates to “captive” customers who had no other supply option. As a result of these tightening margins and competitive pressures, some electric companies began to fail. These dynamics of inferior service, widely varying rates, and inadequate or no returns to investors were occurring at the same time that demand for electricity, and the capital requirements to supply that demand, were growing rapidly. Economies of scale emerged as an industry driver. Larger systems had numerous inherent benefits such as: 1. facilitating the replacement of small, obsolete, or inefficient units, 2. facilitating standardization of equipment and facilities, 3. improving load and diversity factors, 4. centralized purchasing, 5. more efficient use of a specialty labor force. These benefits resulted in operating economies and more uniform and dependable service. The bigger and more efficient the generating plant and distribution network, the lower the price per unit of electricity produced and delivered to end-users. Ironically, regulation emerged as a result of two apparently contradictory dynamics. On the one hand, major suppliers such as Samuel Insull, who had aggregated a number of small suppliers into a large, national holding company system, actively lobbied for regulation. Their goal in doing so was to insulate their local franchises from competitive entry and thereby protect their profits. On the other hand, policy-makers began to doubt that the new industry was conducive to competition or that market forces alone were likely to be effective in bringing about adequate service at reasonable rates. Early regulatory efforts in the 1900-1920s included state legislatures and municipal governing bodies directly
Power Business, 2nd ed. (New York: McGraw-Hill Book Company, 1970), pp. 9, 69; Bradley, Robert, “The Origins of Political Electricity: Market Failure or Political Opportunism?” Energy Law Journal, 17(1) (1996), 59–102.
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regulating public utilities by statute and ordinance. When it became obvious that regulation was a full-time job requiring specialized skills and expertise, states began to form specially organized boards with powers over utility service and rates. Federal regulation followed in the 1920s and 1930s, as electric service expanded from downtown areas throughout urban regions. To enhance the economy and reliability of power supply, the first higher voltage transmission lines began to be constructed to interconnect local and regional systems spanning several states. Electric power assumed even more of the characteristics of an essential service to interstate commerce. This created a perceived need for federal legislation to facilitate industry growth and to avoid conflicting and parochial state regulatory mandates. The first significant federal legislation came with enactment of the Federal Power Act of 1935 that expanded the role of the Federal Power Commission, which previously was limited to the licensing of hydroelectric projects. The act expanded the commission’s jurisdiction to include the interconnection and coordination of electric facilities; mergers and security issuances and asset sales; wholesale rates; adequacy of service; asset valuation, and; accounting practices.
Financial and structural regulation5 Regulation of public utility securities and corporate organization developed after rate regulation. In the early days of regulation, it was not considered necessary to regulate the financial and corporate structure of the industry. During a period of relatively simple corporate organizations and capital structures that were not excessively leveraged, the prevailing view was that the utility’s rates and service were sufficiently controlled on the basis of property values, regardless of the company’s capitalization. Therefore, it did not make much difference, from the customers’ perspective, how the company organized its capital structure or acquired the capital needed for expansion. Congress and state legislatures responded with financial regulation only when the holding company excesses in the late 1920s and early 1930s demonstrated that a company’s organization and capitalization could negatively affect its ability to serve and unnecessarily increase its rates. During the 1920s, the electric utility industry, faced with increasing demand, needed to build plants and to raise a great deal of new capital. At the same time, holding companies were emerging as the predominant corporate structure. Holding companies facilitated the consolidation occurring in the industry and provided greater financial flexibility to the entrepreneurs that still controlled most utility companies, many of which were owned by non-utility holding companies that were interstate in character. By 1932, 49% of the investorowned electric utility industry was controlled by three holding companies. Another 35% was controlled by the next 12 largest holding company systems. Over time, however, the scale economies that encouraged consolidation into complex holding company structures became secondary to a wide range of financial abuses. In fact,
5 Sources for this subsection include Welch, op. cit., pp. 615, 617, 641–644; Hawes, Douglas W., Utility Holding Companies, 4th ed. (New York: Clark Boardman Company, Ltd., 1987), pp. 2–5, 2–12, 2–13, 2–15.
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the complex corporate structures made the abuses difficult to detect. Eventually, however, the abuses were exposed, and public concern began to grow about the evolving industry structure. These abuses included pyramiding of corporate organizations (which was used to magnify control and/or profits), excessive leveraging of capital structures, and abusive affiliate dealings within the holding companies. In addition, some holding companies collapsed because of faulty acquisition and diversification strategies or because of accounting inadequacies. In 1928, Congress directed the Federal Trade Commission to investigate holding companies and abuses in the electric and gas utility industries. This investigation, which lasted a number of years, documented numerous financial abuses and, in turn, led to enactment of the Public Utility Holding Company Act of 1935 (PUHCA). The act was primarily directed toward simplifying holding company structures, eliminating businesses unrelated to the utility industry from holding company structures, and regulating service contracts between affiliated companies. As a result, the number of registered holding companies dropped from more than 200 in the 1930s to approximately 306 in 2005. Regulation driven by environmental, national security, and safety issues7 Between 1940 and 1960s, electricity usage doubled every decade. The post-war economic boom increased demand in all customer segments. The cost of electricity declined significantly as scale economies combined with technological innovation to reduce the unit costs of production. This reduction in unit costs accelerated as increasingly larger coal and oilfired base load-generating plants were introduced. This phenomenon resulted in greater electrification of the economy. In the late 1960s and 1970s, however, a number of factors converged which threatened the financial viability of the industry in a manner unseen since the industry’s financial problems of the 1930s. It was during the 1960s and 1970s that evolving public concern about the environmental effects of energy production technology resulted in the enactment of new laws that effectively became a major form of indirect economic regulation of the utility industry. New legislation such as the National Environmental Policy Act, the Clean Water Act, and the Clean Air Act, and the accompanying regulatory initiatives, became as important to the industry as traditional regulation of rates and services. It also drove utility management decision-making concerning the fuel choice for new generation facilities. Although large supplies of coal were available domestically, and the technology for converting coal to electricity was mature, many utilities began to look for alternatives because of the expense and uncertainty associated with constantly changing environmental regulations. On a national level, natural gas generally was not considered a cost effective alternative to oil and coal for power generation. A bifurcated gas market resulting from federal price regulation limited the availability of gas at reasonable prices in regions that did not produce natural gas. Therefore, the use of natural gas for new generation was limited to the
6 There are currently 31 “top tier” registered holding companies. The total number of registered holding companies exceeds 50 due to the fact that some registered holding companies own other registered holding companies. 7 Sources for this subsection include Congressional Research Service, Electricity: A New Regulatory Order? (Washington: U.S. Government Printing Office, 1991), pp. 158–164, 205–206, 212–216.
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gas producing regions of the Gulf Coast and Southwestern states. Over time, however, changes in the nation’s energy supply and geopolitical considerations (e.g., the oil embargos and natural gas shortages of the 1970s) resulted in the passage of the Powerplant and Industrial Fuel Use Act that prohibited new facilities from burning natural gas or petroleum products to generate electricity.8 At the same time, the energy crisis also brought about the demise of controlled pricing for oil and natural gas, and prices for those commodities (which still could be used as boiler fuels for existing facilities) equalized across the country, albeit at substantially higher prices. One of the few options available to the industry was to place a greater reliance on nuclear energy. The first commercial nuclear generating plants were developed in the 1960s with considerable support from the federal government. They were able to exploit plentiful supplies of uranium, technical skills developed in the naval reactor program, and an enrichment capability developed for military purposes to produce electricity at costs that initially were projected to be “too cheap to meter.” More importantly, from environmental and fuel supply reliability perspectives, nuclear plants did not raise air or water pollution concerns and reduced U.S. dependence on imported fuels. However, at the same time as the industry sought to increase its reliance on nuclear energy, a growing awareness of the safety risks associated with nuclear generation and a slowing demand for electricity combined to create a “perfect storm” for utilities involved in nuclear generation. Increasing public opposition to nuclear plant development delayed the completion of new plants that were planned or under construction. Double-digit inflation increased the capital carrying charges associated with plants whose costs could not be recovered until they commenced commercial operation. Complying with constantly changing federal safety regulations proved to be an expensive and time-consuming process. The industry’s nuclearrelated problems accelerated dramatically after the accident at Three Mile Island triggered a de facto moratorium on new plant orders and intensified the regulatory burdens and delays for plants already under construction. By the late 1970s and early 1980s, these problems caused some companies that were building or planning nuclear plants to begin rethinking their position. The impact of allowing utilities to capitalize the carrying charges of plants under construction was customer rates that spiraled upward. The combination of huge cost overruns and uncertain cost recovery made it prohibitive for some utilities even to complete their plants. Those utilities chose to minimize their losses by simply abandoning and writing off their partially completed plants. In other cases, the plants were completed, and utilities were forced to seek huge rate increases to recover the costs. These requests, along with the omnipresent safety debate, created a political and, ultimately, a regulatory dynamic that had severe adverse effects on the entire industry. Regulatory commissions slashed rate requests, and only allowed the utilities to recover costs and earn the minimal returns necessary for survival. The quality of utility earnings also deteriorated as the non-cash component (reflecting capitalized interest costs) increased, and some companies resorted to borrowing to cover their dividends. The notion of utility stocks as “debt equivalents” vanished as dividends were cut or eliminated, and earnings volatility increased dramatically. It took years for some of these
8
The act was repealed in 1987.
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utilities to return to a financially sound position. Some never did and were acquired in the wave of industry consolidation that began in the late 1980s and is still ongoing.
Economic and financial deregulation9 In 1978, partially in response to the energy crisis and to major power outages, Congress passed the Public Utility Regulatory Policies Act (PURPA). PURPA provided a starting point for deregulation and competitive entry into the generating segment of the market by providing incentives for non-utility cogeneration and small power production. Initially, a surge of new cogeneration, small hydroelectric projects, and biomass projects were developed. Utilities were mandated by PURPA to purchase the output of these facilities at the utilities’ “avoided cost.” 10 This mandate enabled these facilities to be financed with project financing secured by long-term contracts with utilities. PURPA’s incentives also were extended, however, to alternative fuel technologies that were immature and/or uneconomic. For that reason, these technologies never achieved the hoped-for levels of market penetration. In addition, other continuing regulatory barriers discouraged many non-utility entities from developing more traditional generating facilities that did not qualify for PURPA benefits because this would have subjected those entities to regulation as public utilities. Enticed by the price reductions and increased innovation that had occurred in other deregulated industries, Congress tried again with the Energy Policy Act of 1992, which did accelerate the development of regional, competitive wholesale power markets. Among other things, and unlike PURPA, the act gave authority to the Federal Energy Regulatory Commission (FERC)11 to require access to the transmission grid for wholesale generators. During the next few years, the FERC required utilities owning transmission to provide open access to their transmission systems under standard terms, conditions, and rates. It also promoted regional entities that would independently operate transmission systems. These developments provided the incentive for non-utility independent power producers (IPPs) to construct gas-fired generation wherever gas and transmission lines were in reasonable proximity.12 The legislation also created a new designation as “exempt wholesale generators” that protected new wholesale market entrants from regulation under PUHCA. In state-regulated retail markets, price disparities were a major driver of efforts to implement retail competition. States where prices were high, like California, embraced the concept. By 1997 some form of retail competition had been authorized or was under consideration in nearly half the states, which included nearly two-thirds of the country’s population. By 1998, one survey suggested that 80% of electric industry executives believed that all retail electric customers would be able to choose their supplier by 2005.
9 Sources for this subsection include Washington International Energy Group, The 1998 Electric Industry Outlook (Washington: Washington International Energy Group, Ltd., 1998), pp. 6–8, 30. 10 In the context of PURPA, avoided cost generally was considered to be the marginal cost of utility production. 11 The successor to the Federal Power Commission. 12 Gas-fired generation (which had been prohibited for several years in the 1970s and 1980s) was preferred because the plants are relatively inexpensive and can be built relatively quickly.
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There was wide variation between the retail competition plans at the state level. In some cases, this led to dysfunctional outcomes. In California, for example, although the wholesale market was deregulated, retail prices were capped. The state’s three investor-owned utilities were encouraged to sell their generation as part of a deal related to stranded cost recovery.13 At the same time, however, they were prohibited from entering into long-term contracts with suppliers to hedge their risk and were forced to buy all of the power needed to serve their residual retail load in volatile spot markets. Unlike other regional energy markets such as those established in the Northeast, the forward energy market and the network reliability functions were organizationally separated. With this inherently flawed market system in place, California began to experience dramatically higher natural gas and emission allowance prices.14 There was an unforeseen surge in electricity demand because of the state’s economic growth and unusual weather patterns. Due to siting and environmental rules limiting new power plant construction, none had been built in the state in more than 10 years, and the state’s aging portfolio of plants experienced high outage rates. Similar rules had made it difficult to construct new transmission lines, and this limited the amount of power that could be imported. Droughts in the Northwest reduced the amount of hydropower that was available for import. During certain volatile periods, California’s utilities sometimes were forced to pay thousands of dollars per megawatt hour (MWH) for wholesale purchases in the spot market to maintain reliability. However, because of the price cap, they were able to charge their retail customers only $60–70 per MWH. Within 6 months, this price squeeze resulted in utility debt of $10–12 billion, rolling blackouts, and, for one of the state’s major utilities, insolvency. The problem was exacerbated by significant abuses of a flawed market design by several of the major energy trading companies that moved quickly to exploit the opportunities created by newly deregulated wholesale markets. Utility customers in California, meanwhile, were paying only a fraction of the cost of power purchased on their behalf and had little incentive to conserve or to shop for alternative suppliers. “The California Experience” was the primary contributor to a shift in political momentum in the national deregulation movement. Beginning in the late 1990s many states slowed or reversed their deregulation efforts. At the federal level, the FERC began investigations into alleged market abuses in California, thereby creating a threat of widespread contract abrogation and refund obligations for the newly deregulated merchant sector of the industry. At the same time, the industry’s cash flow and its access to capital markets on reasonable terms deteriorated significantly. The concern about deregulation was exacerbated by the collapse of Enron and several other trading companies implicated in the California crisis and its aftermath. Newer plants constructed by IPPs to take advantage of newly deregulated markets became liabilities instead of assets and were placed on the market at
13 Stranded costs were costs incurred by utilities under their obligation to serve all customers that would not be recoverable in a competitive market. 14 Emission allowances, created by the Clean Air Act, authorize a generating unit to emit 1 ton or 1 pound of specified pollutants during or following a given year. The number of allowances allocated to each unit is established by federal or state environmental regulatory agencies. Emission allowances are a marketable commodity that can be saved, transferred, sold, or purchased.
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prices less than book value. Broader concerns about the reliability of audited financial statements (across all publicly traded companies) worsened the situation for utilities in the “accounting crisis” of 2001–2003 that led to, among other things, the Sarbanes Oxley Act and a new layer of accounting, reporting, and governance regulation. The problems in the generating and energy supply sector also had an indirect effect on the wire sector of the industry. Investment in transmission and distribution, which had lagged generation growth in the 1980s and 1990s, slowed to a trickle as the uncertainty over future industry structure and the federal interest in transmission divestiture made utilities reluctant to commit new capital. At the same time, the bubble in energy trading increased the demand for interregional energy transfers and further strained an inadequate transmission network. Several massive regional outages have highlighted the need for tens of billions of dollars of investment in new infrastructure at a time when the industry is ill prepared to commit such capital.
Themes The foregoing discussion illustrates how certain industry themes drove the perceived need for economic regulation of the power supply industry during various phases of its growth and maturation. The critical factor that defines this interaction is that, once electricity emerged as an essential service, a temptation to regulate was inevitable. For example, in the 1900s and 1920s, the public became unhappy with high or disparate prices and inferior service. The companies desired protection against encroachment by new market entrants and local patchwork regulatory efforts; the result was comprehensive price and service regulation. This new regulatory order facilitated industry consolidation. Industry consolidation ultimately created opportunities for “gaming the system,” financial abuses, and company failures resulted. This led to financial regulation and restriction of utilities’ ability to diversify. In the 1960s and 1970s, for various reasons, regulation restricted, and in some cases foreclosed, the ability of utility management to finance needed growth in infrastructure solely on the basis of traditional “free market” forces. When combined with external forces such as high inflation, these regulatory prohibitions restricted market-based responses to changing supply and demand conditions. This, in turn, created inefficiencies, supply shortages, and higher prices. When frequent price spikes became a political issue, two relevant regulatory responses occurred. First, aggressive regulation restricted price increases but created financially vulnerable companies. This, in turn, stimulated industry consolidation once again. Second, Congress took a small step toward re-introducing competition in the generating segment of the industry through passage of PURPA. In the 1990s, price disparities and public expectations of the same price reductions that had occurred in other deregulated industries drove the electric utility industry toward wholesale and retail deregulation. This encouraged diversification as utilities looked for ways to replace the revenue from customers that would be lost to competitors and transform their business models in the hope of achieving the higher growth expectations necessary to compete with the higher multiples being assigned to new market entrants.
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High prices, inferior service, company failures, and poorly designed markets that facilitated financial abuses brought the movement toward competition to a halt. Customers paid much of the cost associated with bringing insolvent utilities out of bankruptcy, and political leaders called for re-regulation. A great deal of capital was spent to construct plants that ultimately proved to be uneconomic.
Current Issues Today’s electric utility industry is desperately in need of greater regulatory predictability. Political momentum, however, wavers between continuing down the road toward competition or re-imposing some form of cost-based regulation. This uncertainty and indecision has resulted in a temporary, uneasy equilibrium. In many respects, this mixed competitive/regulated environment is the worst of both worlds and only exacerbates market risk. The attempted regulatory responses to date often have been incomplete and/or inconsistent. Perhaps this is because they address issues using the faulty premise that a single utility market structure still exists. In fact, regional differences in market structures are pronounced and range from traditional regulated models to liberalized unbundled ones. In the absence of a national energy strategy or policy, and given the difficulties of passing comprehensive energy legislation, Congress tends to address energy matters on an ad hoc basis through spending bills that neither coherently nor comprehensively address energy issues in a strategic or integrated way. Even when consensus develops to pass “comprehensive energy legislation,” the many components of the legislation vary widely in their effectiveness and value. A recent example is the Energy Policy Act of 2005, the first comprehensive energy legislation enacted by Congress in 13 years. Various factors served to create consensus on the need for such legislation. These included: 1. global geopolitical developments that, once again, highlight U.S. vulnerability to oil supply disruptions, 2. increased public awareness of global warming, 3. renewed interest in non-fossil technologies such as wind, solar, and nuclear, 4. a recent major power blackout in the Eastern United States that underscored the need for massive new investment in transmission and federal reliability standards. Even though the legislation contained provisions that had widespread support (such as federal reliability standards for the power industry), it was nearly doomed by parochial issues, such as insulating petrochemical companies from liability associated with certain gasoline additives. In addition, to gain the votes needed for passage, the legislation included a number of non-market-based incentives for the development of selected renewable energy, “clean coal” technology and “advanced” nuclear reactors. It also included provisions that essentially repeal PUHCA and modify PURPA. Given the lessons of history, one might
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confidently predict that, as demonstrated by PURPA in the 1980s, it is unlikely that nonmarket-based incentives for otherwise uneconomic technologies will significantly contribute toward the development of a sustained, widespread competitive market or otherwise increase the efficiency of power supply. It also is likely that the repeal of PUHCA, which was enacted to discourage consolidation and diversification, will stimulate further industry consolidation and ultimately encourage diversification. It may also attract a genre of owners that are primarily or solely interested in financial performance. The change in administrations and the political mix in Congress also have been reflected in a more pragmatic approach to regulation of the industry. During the past several years, the Environmental Protection Agency (EPA) has attempted to bring some regulatory certainty to owners of coal-fired generation. It took definitive positions in new proposed regulations and was less aggressive in pursuing some of the litigation it inherited from the prior administration. The EPA promulgated a series of regulations designed to reduce nitrogen oxide, sulfur dioxide, and mercury emissions. It attempted to clarify the situations in which changes to existing plants would trigger compliance with more stringent emission requirements and require investment in emission reduction infrastructure. Once again, however, regionalism became evident as numerous Northeastern states, concerned both with air quality and economic competitiveness, cooperated with environmentalists to challenge EPA action in litigation. Thus, uncertainty regarding the operational and financial risks associated with coal-fired generation is likely to continue as long as litigation is pending and until a clear national environmental policy emerges. The FERC has continued its focus on encouraging new transmission development and assuring access to transmission for new market entrants. It has, however, backed off of its efforts to mandate a national standard market design. This change in position was prompted by strong opposition from industry and political leadership in Southeastern and Northwestern states with low-cost power. The federal agency continues to push utilities to relinquish control over the operation of, if not ownership of, their transmission systems to independent organizations. Its rationale is that open-access transmission tariffs alone will not totally eliminate the ability of transmission providers to favor their generation affiliates which, in turn, will discourage the development of a healthy and stable wholesale energy market. Transmission-owning companies, however, are understandably reluctant to invest significant amounts of money in assets they do not control. As noted, the FERC’s prior efforts to unbundle generation and transmission assets have led to conflict with state regulators who are concerned about numerous issues. These issues include the priority of retail customers for transmission capacity and the jurisdiction of state agencies to site new transmission lines. From the state regulators’ perspective, both of these issues have potential impacts on cost and quality of service. State regulators in low-cost states also are concerned that FERC efforts to promote large, regional wholesale power markets will divert their low-cost power supplies to higher cost regions. As a result of the 2003 widespread blackout and pervasive transmission constraints, the FERC also has continued its focus on mandatory reliability rules. Congress established a system of voluntary compliance with transmission operating standards after the Northeast Blackout of 1965. This system was deliberately structured to rely on industry “selfregulation” and to keep governmental involvement to a minimum. However, in a restructured
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market characterized by many non-utility generators moving power over long distances, and with the cost pressures on utilities, compliance with voluntary standards has eroded. The current challenge is for the FERC to develop meaningful enforcement mechanisms as it implements the reliability provisions of the Energy Policy Act of 2005. The foregoing issues are being debated and deliberated in the context of new geopolitical realities shaping the industry’s future risk profile. Nuclear power plants, utility information systems, transmission grids, and substations all have been identified as terrorist targets. As referenced earlier in this chapter, regulatory uncertainty has contributed to a need for infrastructure investment, particularly in transmission. This need is exacerbated by forecasts for economic recovery and growth, with the attendant increase in demand for electricity. Assessing Risk in Terms of What Is Unknown and What Is Unknowable15 It is sometimes said that events in the electric utility industry unfold in slow motion. This truism, considered in isolation, would lead one to believe that utility management should be well positioned to deal with unanticipated regulatory changes. The obvious problem is that, although potential regulatory changes can be identified in advance, the lead times for response in a highly capital intensive industry with enormous infrastructure needs are measured over a much longer planning horizon. In the past, regulatory changes were prompted by high prices, bad service, consolidation, financial abuses, and industry failures. In response, policy-makers have either extended regulation, attempted to stimulate competition, or both. Utilities have sometimes supported these governmental initiatives. The primary strategic industry response to risk mitigation, however, has been through diversification of its risk exposure. Often, the preference has been to achieve that diversification quickly through acquisitions, which results in industry consolidation. Typical diversification strategies have included: 1. geographic diversification to reduce the impact of a single regulatory commission on a utility’s financial structure, 2. fuel diversification to minimize the impact of regulation on a specific fuel source, 3. electric/gas convergence to smooth cash flows and reduce costs, 4. diversification into non-utility businesses, which in turn facilitates removing some functions of the utility business from regulatory purview.
15
Sources for this section include an article entitled “Consequential Heresies: How ‘Thinking the Unthinkable’ Changed Royal Dutch/Shell” written by Art Kleiner in 1989 for Doubleday as a prototype for a magazine called Currency, and; The Application of Banking Models to the Electric Power Industry: Understanding Business Risk in Today’s Environment, Karyl Leggio, David Bodde, and Marilyn Taylor, March, 2003. The latter paper defines unknown risks as “risks that are knowable with new technologies, additional research, or a shift in resources. . . .” Unknowable risks are those that cannot become known regardless of the “amount of research or resources deployed. . . .”
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As noted, however, some of these risk diversification strategies have not been successful, especially when companies desperate to attract new capital have entered “higher growth” markets that are far removed from their core competencies. In recent years, utilities also have undertaken numerous initiatives that, although smaller in scope, have a significant cumulative impact when successful. These include seeking legislative or regulatory authority for power cost adjustment mechanisms, environmental compliance surcharges, pre-approval of significant capital projects, incentive rates and tariff redesign. These efforts are aimed at reconciling regulation and market risk, and reducing regulatory uncertainty. Underlying all of these utility efforts, both large and small, are strong political and community relationships. States, counties, and municipalities are recognizing that utility investment in supply and reliability is a powerful tool for economic development. Utilities are fortunate when compared to companies in other industries that provide nonessential services in a highly competitive market. Since regulatory change develops slowly and is prompted by crisis or controversy, much that is unknowable becomes unknown. The emergence of traditional indicators of regulatory change such as increasing prices, environmental accidents, company failures, deteriorating service quality, or accelerating industry consolidation should alert utility management that currently unknown risks are beginning to build. Traditional governmental responses to these indicators provide a historical reference point, but the challenge is how to identify, categorize, and develop action plans to address these unknown risks. Companies that can develop and ingrain such a dynamic and adaptive process into their corporate cultures will establish themselves as a true exception – a proactive company in a historically reactive and cyclic industry. The potential rewards from occupying that position are self-evident. Precedent and analytic tools exist for companies willing to invest the efforts of their best strategic thinkers and their operational experts. Royal Dutch/Shell used scenario planning to foresee the 1973 energy crisis 2 years before it happened. At the time, the price of oil had remained steady for 25 years. Only 2 of Shell’s 40 top managers thought that the price of oil would rise above $2 a barrel. Nevertheless, Shell imagined prices at an outlandish amount – $10 a barrel – and developed contingency plans that included converting refineries so they could quickly switch to refine oil from different countries. Within a year and half, oil prices were $13 a barrel. The energy crisis was the beginning of a turnaround for Shell. At the time the crisis began, Shell was considered the least profitable of the major oil companies. By the late 1980s, Shell was the most profitable oil company in the world. Shell prospered in a crisis because it was prepared for it. Scenario planning, which considers adaptive behavior under alternative futures, is uniquely suited for identifying and categorizing unknown utility risks. It focuses both on facts and perceptions and considers internally consistent combinations of variables. It transforms information into fresh perceptions. It forces decision-makers to question “the rules” governing their industry and ultimately to change their perception of the reality of their business environment. Uncertainty and risk management are institutionalized as a part of the decision-making process. Value is created from the scenarios themselves because they lead to better planning and more options. The process also identifies triggers for re-evaluating strategy, thus leading management to become more flexible and creative.
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The Future16 As mentioned numerous times in this chapter, the defining characteristic of electricity is that it is essential to our quality of life, the operation of our economy and our security. The attributes of the industry in terms of its capital intensity, long lead times, regional infrastructure, and inability to stockpile its essential output are unique and not readily subject to change. Investment in transmission and distribution (a significant percentage of Gross Domestic Product) is most efficient through a single provider. Given those facts, it is reasonable to expect that the transmission and distribution of electricity will remain regulated to some extent. As for generation, it is certainly possible that governmental policy, for the foreseeable future, will continue to encourage niche competition and aggressively regulate certain types of generation, such as coal and nuclear. The cycle of events and regulatory reactions in the industry are well established. As discussed in the previous section, scenario planning in this context should enable the development of strategic initiatives that are sufficiently robust to proactively meet unknown risks as they become known. Scenario planning offers even more value, however, when it is extended further by developing contingency plans for the unknowable. This is especially true given the long lead times necessary to develop utility infrastructure. For example, the unknowable could be a new technology (e.g., wireless power transmission) that completely changes the nature of the electric utility business and the dynamics of industry structure and market forces. Dramatic technological innovations that will minimize the importance of the current electric infrastructure, and consequently regulation, have been predicted for years. Indeed, one argument in support of deregulation of the industry in the 1990s was that competition would provide the incentive for the development of new technologies that could vastly reduce costs and enhance the quality of our environment. Clearly, some of those innovations are likely to happen, but the time frame is unknowable. The unknowable also could be external forces of enormous consequence. Is the industry in denial about the possibility of terrorism, or a widespread nuclear shutdown (as occurred in Japan in 2001 and 2002), or end-use technology such as Liquid Crystal Displays replacing lights, or fuel cell breakthroughs, or interest rate volatility, or dramatically rising coal prices, or electric vehicles? In retrospect, major transformations have taken place in the electric industry in the past 100 years. Utilities should focus on the tools that will position them to prosper in the next 100 years. By planning for both unknown and unknowable risks, utilities can identify common causal relationships between apparently unrelated factors that are interwoven throughout various scenarios. Developing strategic plans based on these causal relationships not only minimizes risk, it provides a competitive advantage during times of industry turmoil and better positions those companies to thrive under a wide range of future conditions.
16
Sources for this section include Leggio, Bodde, and Taylor, op. cit.
A Perspective on Regulatory Risk in the Electric Industry William G. Riggins1,2 Vice President and General Counsel, Kansas City Power and Light
Introduction “Past experience, if not forgotten, is a guide to the future.”3 The past experiences of the electric industry provide a guide to predicting, and thus better managing, risks created by changing regulation. The industry’s history is represented by continuing cycles of phenomena that create socio-political dynamics that drive regulatory initiatives. These regulatory initiatives, and in some cases their unintended consequences, can have a dramatic impact on the ability of electric utilities to meet their public service obligations while, at the same time, maintaining their financial commitments to investors. This chapter begins by presenting and summarizing some of these historical patterns and themes. It then assesses current issues and provides some suggestions for thinking about, and planning for, an uncertain future. Historical Scenarios Why an entrepreneurial industry became subject to economic and quality of service regulation4 Entrepreneurs were responsible for the creation and expansion of the electric utility industry in the late 19th and early 20th centuries. The cost of constructing a central 1
William G. Riggins is General Counsel, Great Plains Energy. The author is indebted to Jerry Pfeffer, Gerald Reynolds, and Robert Zabors for their contributions to this chapter. 3 A Chinese proverb. 4 Sources for this subsection include Welch, Francis X., Cases and Text on Public Utility Regulation, 1st ed. (Washington: Public Utilities Reports, Inc., 1961), pp. 543–544, 547–548, 550–552; Vennard, Edwin, The Electric 2
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generating station and distribution facilities was high. Initially, therefore, electricity was considered a luxury. Its use was limited to “public service” applications such as street lighting and to more affluent customers. However, demand grew as new, efficiency enhancing devices that used electricity, such as the electric motor, were created. These devices came to be considered necessities, not luxuries, and so did electricity. When problems began to emerge with the supply and pricing of this essential service, regulation of rates and service emerged as the public policy response. Initially, electric companies were formed and operated wherever the investors thought they could profitably sell electricity. Companies competed vigorously with each other for customers. They operated at various voltages with different kinds of equipment. There was significant duplication of facilities. In some cases, multiple sets of wires were strung haphazardly throughout city landscapes. Companies engaged in price wars to increase market share for industrial and commercial customers who were able to shop among suppliers. They offset any revenue losses by charging extremely high rates to “captive” customers who had no other supply option. As a result of these tightening margins and competitive pressures, some electric companies began to fail. These dynamics of inferior service, widely varying rates, and inadequate or no returns to investors were occurring at the same time that demand for electricity, and the capital requirements to supply that demand, were growing rapidly. Economies of scale emerged as an industry driver. Larger systems had numerous inherent benefits such as: 1. facilitating the replacement of small, obsolete, or inefficient units, 2. facilitating standardization of equipment and facilities, 3. improving load and diversity factors, 4. centralized purchasing, 5. more efficient use of a specialty labor force. These benefits resulted in operating economies and more uniform and dependable service. The bigger and more efficient the generating plant and distribution network, the lower the price per unit of electricity produced and delivered to end-users. Ironically, regulation emerged as a result of two apparently contradictory dynamics. On the one hand, major suppliers such as Samuel Insull, who had aggregated a number of small suppliers into a large, national holding company system, actively lobbied for regulation. Their goal in doing so was to insulate their local franchises from competitive entry and thereby protect their profits. On the other hand, policy-makers began to doubt that the new industry was conducive to competition or that market forces alone were likely to be effective in bringing about adequate service at reasonable rates. Early regulatory efforts in the 1900-1920s included state legislatures and municipal governing bodies directly
Power Business, 2nd ed. (New York: McGraw-Hill Book Company, 1970), pp. 9, 69; Bradley, Robert, “The Origins of Political Electricity: Market Failure or Political Opportunism?” Energy Law Journal, 17(1) (1996), 59–102.
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regulating public utilities by statute and ordinance. When it became obvious that regulation was a full-time job requiring specialized skills and expertise, states began to form specially organized boards with powers over utility service and rates. Federal regulation followed in the 1920s and 1930s, as electric service expanded from downtown areas throughout urban regions. To enhance the economy and reliability of power supply, the first higher voltage transmission lines began to be constructed to interconnect local and regional systems spanning several states. Electric power assumed even more of the characteristics of an essential service to interstate commerce. This created a perceived need for federal legislation to facilitate industry growth and to avoid conflicting and parochial state regulatory mandates. The first significant federal legislation came with enactment of the Federal Power Act of 1935 that expanded the role of the Federal Power Commission, which previously was limited to the licensing of hydroelectric projects. The act expanded the commission’s jurisdiction to include the interconnection and coordination of electric facilities; mergers and security issuances and asset sales; wholesale rates; adequacy of service; asset valuation, and; accounting practices.
Financial and structural regulation5 Regulation of public utility securities and corporate organization developed after rate regulation. In the early days of regulation, it was not considered necessary to regulate the financial and corporate structure of the industry. During a period of relatively simple corporate organizations and capital structures that were not excessively leveraged, the prevailing view was that the utility’s rates and service were sufficiently controlled on the basis of property values, regardless of the company’s capitalization. Therefore, it did not make much difference, from the customers’ perspective, how the company organized its capital structure or acquired the capital needed for expansion. Congress and state legislatures responded with financial regulation only when the holding company excesses in the late 1920s and early 1930s demonstrated that a company’s organization and capitalization could negatively affect its ability to serve and unnecessarily increase its rates. During the 1920s, the electric utility industry, faced with increasing demand, needed to build plants and to raise a great deal of new capital. At the same time, holding companies were emerging as the predominant corporate structure. Holding companies facilitated the consolidation occurring in the industry and provided greater financial flexibility to the entrepreneurs that still controlled most utility companies, many of which were owned by non-utility holding companies that were interstate in character. By 1932, 49% of the investorowned electric utility industry was controlled by three holding companies. Another 35% was controlled by the next 12 largest holding company systems. Over time, however, the scale economies that encouraged consolidation into complex holding company structures became secondary to a wide range of financial abuses. In fact,
5 Sources for this subsection include Welch, op. cit., pp. 615, 617, 641–644; Hawes, Douglas W., Utility Holding Companies, 4th ed. (New York: Clark Boardman Company, Ltd., 1987), pp. 2–5, 2–12, 2–13, 2–15.
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the complex corporate structures made the abuses difficult to detect. Eventually, however, the abuses were exposed, and public concern began to grow about the evolving industry structure. These abuses included pyramiding of corporate organizations (which was used to magnify control and/or profits), excessive leveraging of capital structures, and abusive affiliate dealings within the holding companies. In addition, some holding companies collapsed because of faulty acquisition and diversification strategies or because of accounting inadequacies. In 1928, Congress directed the Federal Trade Commission to investigate holding companies and abuses in the electric and gas utility industries. This investigation, which lasted a number of years, documented numerous financial abuses and, in turn, led to enactment of the Public Utility Holding Company Act of 1935 (PUHCA). The act was primarily directed toward simplifying holding company structures, eliminating businesses unrelated to the utility industry from holding company structures, and regulating service contracts between affiliated companies. As a result, the number of registered holding companies dropped from more than 200 in the 1930s to approximately 306 in 2005. Regulation driven by environmental, national security, and safety issues7 Between 1940 and 1960s, electricity usage doubled every decade. The post-war economic boom increased demand in all customer segments. The cost of electricity declined significantly as scale economies combined with technological innovation to reduce the unit costs of production. This reduction in unit costs accelerated as increasingly larger coal and oilfired base load-generating plants were introduced. This phenomenon resulted in greater electrification of the economy. In the late 1960s and 1970s, however, a number of factors converged which threatened the financial viability of the industry in a manner unseen since the industry’s financial problems of the 1930s. It was during the 1960s and 1970s that evolving public concern about the environmental effects of energy production technology resulted in the enactment of new laws that effectively became a major form of indirect economic regulation of the utility industry. New legislation such as the National Environmental Policy Act, the Clean Water Act, and the Clean Air Act, and the accompanying regulatory initiatives, became as important to the industry as traditional regulation of rates and services. It also drove utility management decision-making concerning the fuel choice for new generation facilities. Although large supplies of coal were available domestically, and the technology for converting coal to electricity was mature, many utilities began to look for alternatives because of the expense and uncertainty associated with constantly changing environmental regulations. On a national level, natural gas generally was not considered a cost effective alternative to oil and coal for power generation. A bifurcated gas market resulting from federal price regulation limited the availability of gas at reasonable prices in regions that did not produce natural gas. Therefore, the use of natural gas for new generation was limited to the
6 There are currently 31 “top tier” registered holding companies. The total number of registered holding companies exceeds 50 due to the fact that some registered holding companies own other registered holding companies. 7 Sources for this subsection include Congressional Research Service, Electricity: A New Regulatory Order? (Washington: U.S. Government Printing Office, 1991), pp. 158–164, 205–206, 212–216.
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gas producing regions of the Gulf Coast and Southwestern states. Over time, however, changes in the nation’s energy supply and geopolitical considerations (e.g., the oil embargos and natural gas shortages of the 1970s) resulted in the passage of the Powerplant and Industrial Fuel Use Act that prohibited new facilities from burning natural gas or petroleum products to generate electricity.8 At the same time, the energy crisis also brought about the demise of controlled pricing for oil and natural gas, and prices for those commodities (which still could be used as boiler fuels for existing facilities) equalized across the country, albeit at substantially higher prices. One of the few options available to the industry was to place a greater reliance on nuclear energy. The first commercial nuclear generating plants were developed in the 1960s with considerable support from the federal government. They were able to exploit plentiful supplies of uranium, technical skills developed in the naval reactor program, and an enrichment capability developed for military purposes to produce electricity at costs that initially were projected to be “too cheap to meter.” More importantly, from environmental and fuel supply reliability perspectives, nuclear plants did not raise air or water pollution concerns and reduced U.S. dependence on imported fuels. However, at the same time as the industry sought to increase its reliance on nuclear energy, a growing awareness of the safety risks associated with nuclear generation and a slowing demand for electricity combined to create a “perfect storm” for utilities involved in nuclear generation. Increasing public opposition to nuclear plant development delayed the completion of new plants that were planned or under construction. Double-digit inflation increased the capital carrying charges associated with plants whose costs could not be recovered until they commenced commercial operation. Complying with constantly changing federal safety regulations proved to be an expensive and time-consuming process. The industry’s nuclearrelated problems accelerated dramatically after the accident at Three Mile Island triggered a de facto moratorium on new plant orders and intensified the regulatory burdens and delays for plants already under construction. By the late 1970s and early 1980s, these problems caused some companies that were building or planning nuclear plants to begin rethinking their position. The impact of allowing utilities to capitalize the carrying charges of plants under construction was customer rates that spiraled upward. The combination of huge cost overruns and uncertain cost recovery made it prohibitive for some utilities even to complete their plants. Those utilities chose to minimize their losses by simply abandoning and writing off their partially completed plants. In other cases, the plants were completed, and utilities were forced to seek huge rate increases to recover the costs. These requests, along with the omnipresent safety debate, created a political and, ultimately, a regulatory dynamic that had severe adverse effects on the entire industry. Regulatory commissions slashed rate requests, and only allowed the utilities to recover costs and earn the minimal returns necessary for survival. The quality of utility earnings also deteriorated as the non-cash component (reflecting capitalized interest costs) increased, and some companies resorted to borrowing to cover their dividends. The notion of utility stocks as “debt equivalents” vanished as dividends were cut or eliminated, and earnings volatility increased dramatically. It took years for some of these
8
The act was repealed in 1987.
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utilities to return to a financially sound position. Some never did and were acquired in the wave of industry consolidation that began in the late 1980s and is still ongoing.
Economic and financial deregulation9 In 1978, partially in response to the energy crisis and to major power outages, Congress passed the Public Utility Regulatory Policies Act (PURPA). PURPA provided a starting point for deregulation and competitive entry into the generating segment of the market by providing incentives for non-utility cogeneration and small power production. Initially, a surge of new cogeneration, small hydroelectric projects, and biomass projects were developed. Utilities were mandated by PURPA to purchase the output of these facilities at the utilities’ “avoided cost.” 10 This mandate enabled these facilities to be financed with project financing secured by long-term contracts with utilities. PURPA’s incentives also were extended, however, to alternative fuel technologies that were immature and/or uneconomic. For that reason, these technologies never achieved the hoped-for levels of market penetration. In addition, other continuing regulatory barriers discouraged many non-utility entities from developing more traditional generating facilities that did not qualify for PURPA benefits because this would have subjected those entities to regulation as public utilities. Enticed by the price reductions and increased innovation that had occurred in other deregulated industries, Congress tried again with the Energy Policy Act of 1992, which did accelerate the development of regional, competitive wholesale power markets. Among other things, and unlike PURPA, the act gave authority to the Federal Energy Regulatory Commission (FERC)11 to require access to the transmission grid for wholesale generators. During the next few years, the FERC required utilities owning transmission to provide open access to their transmission systems under standard terms, conditions, and rates. It also promoted regional entities that would independently operate transmission systems. These developments provided the incentive for non-utility independent power producers (IPPs) to construct gas-fired generation wherever gas and transmission lines were in reasonable proximity.12 The legislation also created a new designation as “exempt wholesale generators” that protected new wholesale market entrants from regulation under PUHCA. In state-regulated retail markets, price disparities were a major driver of efforts to implement retail competition. States where prices were high, like California, embraced the concept. By 1997 some form of retail competition had been authorized or was under consideration in nearly half the states, which included nearly two-thirds of the country’s population. By 1998, one survey suggested that 80% of electric industry executives believed that all retail electric customers would be able to choose their supplier by 2005.
9 Sources for this subsection include Washington International Energy Group, The 1998 Electric Industry Outlook (Washington: Washington International Energy Group, Ltd., 1998), pp. 6–8, 30. 10 In the context of PURPA, avoided cost generally was considered to be the marginal cost of utility production. 11 The successor to the Federal Power Commission. 12 Gas-fired generation (which had been prohibited for several years in the 1970s and 1980s) was preferred because the plants are relatively inexpensive and can be built relatively quickly.
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There was wide variation between the retail competition plans at the state level. In some cases, this led to dysfunctional outcomes. In California, for example, although the wholesale market was deregulated, retail prices were capped. The state’s three investor-owned utilities were encouraged to sell their generation as part of a deal related to stranded cost recovery.13 At the same time, however, they were prohibited from entering into long-term contracts with suppliers to hedge their risk and were forced to buy all of the power needed to serve their residual retail load in volatile spot markets. Unlike other regional energy markets such as those established in the Northeast, the forward energy market and the network reliability functions were organizationally separated. With this inherently flawed market system in place, California began to experience dramatically higher natural gas and emission allowance prices.14 There was an unforeseen surge in electricity demand because of the state’s economic growth and unusual weather patterns. Due to siting and environmental rules limiting new power plant construction, none had been built in the state in more than 10 years, and the state’s aging portfolio of plants experienced high outage rates. Similar rules had made it difficult to construct new transmission lines, and this limited the amount of power that could be imported. Droughts in the Northwest reduced the amount of hydropower that was available for import. During certain volatile periods, California’s utilities sometimes were forced to pay thousands of dollars per megawatt hour (MWH) for wholesale purchases in the spot market to maintain reliability. However, because of the price cap, they were able to charge their retail customers only $60–70 per MWH. Within 6 months, this price squeeze resulted in utility debt of $10–12 billion, rolling blackouts, and, for one of the state’s major utilities, insolvency. The problem was exacerbated by significant abuses of a flawed market design by several of the major energy trading companies that moved quickly to exploit the opportunities created by newly deregulated wholesale markets. Utility customers in California, meanwhile, were paying only a fraction of the cost of power purchased on their behalf and had little incentive to conserve or to shop for alternative suppliers. “The California Experience” was the primary contributor to a shift in political momentum in the national deregulation movement. Beginning in the late 1990s many states slowed or reversed their deregulation efforts. At the federal level, the FERC began investigations into alleged market abuses in California, thereby creating a threat of widespread contract abrogation and refund obligations for the newly deregulated merchant sector of the industry. At the same time, the industry’s cash flow and its access to capital markets on reasonable terms deteriorated significantly. The concern about deregulation was exacerbated by the collapse of Enron and several other trading companies implicated in the California crisis and its aftermath. Newer plants constructed by IPPs to take advantage of newly deregulated markets became liabilities instead of assets and were placed on the market at
13 Stranded costs were costs incurred by utilities under their obligation to serve all customers that would not be recoverable in a competitive market. 14 Emission allowances, created by the Clean Air Act, authorize a generating unit to emit 1 ton or 1 pound of specified pollutants during or following a given year. The number of allowances allocated to each unit is established by federal or state environmental regulatory agencies. Emission allowances are a marketable commodity that can be saved, transferred, sold, or purchased.
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prices less than book value. Broader concerns about the reliability of audited financial statements (across all publicly traded companies) worsened the situation for utilities in the “accounting crisis” of 2001–2003 that led to, among other things, the Sarbanes Oxley Act and a new layer of accounting, reporting, and governance regulation. The problems in the generating and energy supply sector also had an indirect effect on the wire sector of the industry. Investment in transmission and distribution, which had lagged generation growth in the 1980s and 1990s, slowed to a trickle as the uncertainty over future industry structure and the federal interest in transmission divestiture made utilities reluctant to commit new capital. At the same time, the bubble in energy trading increased the demand for interregional energy transfers and further strained an inadequate transmission network. Several massive regional outages have highlighted the need for tens of billions of dollars of investment in new infrastructure at a time when the industry is ill prepared to commit such capital.
Themes The foregoing discussion illustrates how certain industry themes drove the perceived need for economic regulation of the power supply industry during various phases of its growth and maturation. The critical factor that defines this interaction is that, once electricity emerged as an essential service, a temptation to regulate was inevitable. For example, in the 1900s and 1920s, the public became unhappy with high or disparate prices and inferior service. The companies desired protection against encroachment by new market entrants and local patchwork regulatory efforts; the result was comprehensive price and service regulation. This new regulatory order facilitated industry consolidation. Industry consolidation ultimately created opportunities for “gaming the system,” financial abuses, and company failures resulted. This led to financial regulation and restriction of utilities’ ability to diversify. In the 1960s and 1970s, for various reasons, regulation restricted, and in some cases foreclosed, the ability of utility management to finance needed growth in infrastructure solely on the basis of traditional “free market” forces. When combined with external forces such as high inflation, these regulatory prohibitions restricted market-based responses to changing supply and demand conditions. This, in turn, created inefficiencies, supply shortages, and higher prices. When frequent price spikes became a political issue, two relevant regulatory responses occurred. First, aggressive regulation restricted price increases but created financially vulnerable companies. This, in turn, stimulated industry consolidation once again. Second, Congress took a small step toward re-introducing competition in the generating segment of the industry through passage of PURPA. In the 1990s, price disparities and public expectations of the same price reductions that had occurred in other deregulated industries drove the electric utility industry toward wholesale and retail deregulation. This encouraged diversification as utilities looked for ways to replace the revenue from customers that would be lost to competitors and transform their business models in the hope of achieving the higher growth expectations necessary to compete with the higher multiples being assigned to new market entrants.
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High prices, inferior service, company failures, and poorly designed markets that facilitated financial abuses brought the movement toward competition to a halt. Customers paid much of the cost associated with bringing insolvent utilities out of bankruptcy, and political leaders called for re-regulation. A great deal of capital was spent to construct plants that ultimately proved to be uneconomic.
Current Issues Today’s electric utility industry is desperately in need of greater regulatory predictability. Political momentum, however, wavers between continuing down the road toward competition or re-imposing some form of cost-based regulation. This uncertainty and indecision has resulted in a temporary, uneasy equilibrium. In many respects, this mixed competitive/regulated environment is the worst of both worlds and only exacerbates market risk. The attempted regulatory responses to date often have been incomplete and/or inconsistent. Perhaps this is because they address issues using the faulty premise that a single utility market structure still exists. In fact, regional differences in market structures are pronounced and range from traditional regulated models to liberalized unbundled ones. In the absence of a national energy strategy or policy, and given the difficulties of passing comprehensive energy legislation, Congress tends to address energy matters on an ad hoc basis through spending bills that neither coherently nor comprehensively address energy issues in a strategic or integrated way. Even when consensus develops to pass “comprehensive energy legislation,” the many components of the legislation vary widely in their effectiveness and value. A recent example is the Energy Policy Act of 2005, the first comprehensive energy legislation enacted by Congress in 13 years. Various factors served to create consensus on the need for such legislation. These included: 1. global geopolitical developments that, once again, highlight U.S. vulnerability to oil supply disruptions, 2. increased public awareness of global warming, 3. renewed interest in non-fossil technologies such as wind, solar, and nuclear, 4. a recent major power blackout in the Eastern United States that underscored the need for massive new investment in transmission and federal reliability standards. Even though the legislation contained provisions that had widespread support (such as federal reliability standards for the power industry), it was nearly doomed by parochial issues, such as insulating petrochemical companies from liability associated with certain gasoline additives. In addition, to gain the votes needed for passage, the legislation included a number of non-market-based incentives for the development of selected renewable energy, “clean coal” technology and “advanced” nuclear reactors. It also included provisions that essentially repeal PUHCA and modify PURPA. Given the lessons of history, one might
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confidently predict that, as demonstrated by PURPA in the 1980s, it is unlikely that nonmarket-based incentives for otherwise uneconomic technologies will significantly contribute toward the development of a sustained, widespread competitive market or otherwise increase the efficiency of power supply. It also is likely that the repeal of PUHCA, which was enacted to discourage consolidation and diversification, will stimulate further industry consolidation and ultimately encourage diversification. It may also attract a genre of owners that are primarily or solely interested in financial performance. The change in administrations and the political mix in Congress also have been reflected in a more pragmatic approach to regulation of the industry. During the past several years, the Environmental Protection Agency (EPA) has attempted to bring some regulatory certainty to owners of coal-fired generation. It took definitive positions in new proposed regulations and was less aggressive in pursuing some of the litigation it inherited from the prior administration. The EPA promulgated a series of regulations designed to reduce nitrogen oxide, sulfur dioxide, and mercury emissions. It attempted to clarify the situations in which changes to existing plants would trigger compliance with more stringent emission requirements and require investment in emission reduction infrastructure. Once again, however, regionalism became evident as numerous Northeastern states, concerned both with air quality and economic competitiveness, cooperated with environmentalists to challenge EPA action in litigation. Thus, uncertainty regarding the operational and financial risks associated with coal-fired generation is likely to continue as long as litigation is pending and until a clear national environmental policy emerges. The FERC has continued its focus on encouraging new transmission development and assuring access to transmission for new market entrants. It has, however, backed off of its efforts to mandate a national standard market design. This change in position was prompted by strong opposition from industry and political leadership in Southeastern and Northwestern states with low-cost power. The federal agency continues to push utilities to relinquish control over the operation of, if not ownership of, their transmission systems to independent organizations. Its rationale is that open-access transmission tariffs alone will not totally eliminate the ability of transmission providers to favor their generation affiliates which, in turn, will discourage the development of a healthy and stable wholesale energy market. Transmission-owning companies, however, are understandably reluctant to invest significant amounts of money in assets they do not control. As noted, the FERC’s prior efforts to unbundle generation and transmission assets have led to conflict with state regulators who are concerned about numerous issues. These issues include the priority of retail customers for transmission capacity and the jurisdiction of state agencies to site new transmission lines. From the state regulators’ perspective, both of these issues have potential impacts on cost and quality of service. State regulators in low-cost states also are concerned that FERC efforts to promote large, regional wholesale power markets will divert their low-cost power supplies to higher cost regions. As a result of the 2003 widespread blackout and pervasive transmission constraints, the FERC also has continued its focus on mandatory reliability rules. Congress established a system of voluntary compliance with transmission operating standards after the Northeast Blackout of 1965. This system was deliberately structured to rely on industry “selfregulation” and to keep governmental involvement to a minimum. However, in a restructured
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market characterized by many non-utility generators moving power over long distances, and with the cost pressures on utilities, compliance with voluntary standards has eroded. The current challenge is for the FERC to develop meaningful enforcement mechanisms as it implements the reliability provisions of the Energy Policy Act of 2005. The foregoing issues are being debated and deliberated in the context of new geopolitical realities shaping the industry’s future risk profile. Nuclear power plants, utility information systems, transmission grids, and substations all have been identified as terrorist targets. As referenced earlier in this chapter, regulatory uncertainty has contributed to a need for infrastructure investment, particularly in transmission. This need is exacerbated by forecasts for economic recovery and growth, with the attendant increase in demand for electricity. Assessing Risk in Terms of What Is Unknown and What Is Unknowable15 It is sometimes said that events in the electric utility industry unfold in slow motion. This truism, considered in isolation, would lead one to believe that utility management should be well positioned to deal with unanticipated regulatory changes. The obvious problem is that, although potential regulatory changes can be identified in advance, the lead times for response in a highly capital intensive industry with enormous infrastructure needs are measured over a much longer planning horizon. In the past, regulatory changes were prompted by high prices, bad service, consolidation, financial abuses, and industry failures. In response, policy-makers have either extended regulation, attempted to stimulate competition, or both. Utilities have sometimes supported these governmental initiatives. The primary strategic industry response to risk mitigation, however, has been through diversification of its risk exposure. Often, the preference has been to achieve that diversification quickly through acquisitions, which results in industry consolidation. Typical diversification strategies have included: 1. geographic diversification to reduce the impact of a single regulatory commission on a utility’s financial structure, 2. fuel diversification to minimize the impact of regulation on a specific fuel source, 3. electric/gas convergence to smooth cash flows and reduce costs, 4. diversification into non-utility businesses, which in turn facilitates removing some functions of the utility business from regulatory purview.
15
Sources for this section include an article entitled “Consequential Heresies: How ‘Thinking the Unthinkable’ Changed Royal Dutch/Shell” written by Art Kleiner in 1989 for Doubleday as a prototype for a magazine called Currency, and; The Application of Banking Models to the Electric Power Industry: Understanding Business Risk in Today’s Environment, Karyl Leggio, David Bodde, and Marilyn Taylor, March, 2003. The latter paper defines unknown risks as “risks that are knowable with new technologies, additional research, or a shift in resources. . . .” Unknowable risks are those that cannot become known regardless of the “amount of research or resources deployed. . . .”
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As noted, however, some of these risk diversification strategies have not been successful, especially when companies desperate to attract new capital have entered “higher growth” markets that are far removed from their core competencies. In recent years, utilities also have undertaken numerous initiatives that, although smaller in scope, have a significant cumulative impact when successful. These include seeking legislative or regulatory authority for power cost adjustment mechanisms, environmental compliance surcharges, pre-approval of significant capital projects, incentive rates and tariff redesign. These efforts are aimed at reconciling regulation and market risk, and reducing regulatory uncertainty. Underlying all of these utility efforts, both large and small, are strong political and community relationships. States, counties, and municipalities are recognizing that utility investment in supply and reliability is a powerful tool for economic development. Utilities are fortunate when compared to companies in other industries that provide nonessential services in a highly competitive market. Since regulatory change develops slowly and is prompted by crisis or controversy, much that is unknowable becomes unknown. The emergence of traditional indicators of regulatory change such as increasing prices, environmental accidents, company failures, deteriorating service quality, or accelerating industry consolidation should alert utility management that currently unknown risks are beginning to build. Traditional governmental responses to these indicators provide a historical reference point, but the challenge is how to identify, categorize, and develop action plans to address these unknown risks. Companies that can develop and ingrain such a dynamic and adaptive process into their corporate cultures will establish themselves as a true exception – a proactive company in a historically reactive and cyclic industry. The potential rewards from occupying that position are self-evident. Precedent and analytic tools exist for companies willing to invest the efforts of their best strategic thinkers and their operational experts. Royal Dutch/Shell used scenario planning to foresee the 1973 energy crisis 2 years before it happened. At the time, the price of oil had remained steady for 25 years. Only 2 of Shell’s 40 top managers thought that the price of oil would rise above $2 a barrel. Nevertheless, Shell imagined prices at an outlandish amount – $10 a barrel – and developed contingency plans that included converting refineries so they could quickly switch to refine oil from different countries. Within a year and half, oil prices were $13 a barrel. The energy crisis was the beginning of a turnaround for Shell. At the time the crisis began, Shell was considered the least profitable of the major oil companies. By the late 1980s, Shell was the most profitable oil company in the world. Shell prospered in a crisis because it was prepared for it. Scenario planning, which considers adaptive behavior under alternative futures, is uniquely suited for identifying and categorizing unknown utility risks. It focuses both on facts and perceptions and considers internally consistent combinations of variables. It transforms information into fresh perceptions. It forces decision-makers to question “the rules” governing their industry and ultimately to change their perception of the reality of their business environment. Uncertainty and risk management are institutionalized as a part of the decision-making process. Value is created from the scenarios themselves because they lead to better planning and more options. The process also identifies triggers for re-evaluating strategy, thus leading management to become more flexible and creative.
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The Future16 As mentioned numerous times in this chapter, the defining characteristic of electricity is that it is essential to our quality of life, the operation of our economy and our security. The attributes of the industry in terms of its capital intensity, long lead times, regional infrastructure, and inability to stockpile its essential output are unique and not readily subject to change. Investment in transmission and distribution (a significant percentage of Gross Domestic Product) is most efficient through a single provider. Given those facts, it is reasonable to expect that the transmission and distribution of electricity will remain regulated to some extent. As for generation, it is certainly possible that governmental policy, for the foreseeable future, will continue to encourage niche competition and aggressively regulate certain types of generation, such as coal and nuclear. The cycle of events and regulatory reactions in the industry are well established. As discussed in the previous section, scenario planning in this context should enable the development of strategic initiatives that are sufficiently robust to proactively meet unknown risks as they become known. Scenario planning offers even more value, however, when it is extended further by developing contingency plans for the unknowable. This is especially true given the long lead times necessary to develop utility infrastructure. For example, the unknowable could be a new technology (e.g., wireless power transmission) that completely changes the nature of the electric utility business and the dynamics of industry structure and market forces. Dramatic technological innovations that will minimize the importance of the current electric infrastructure, and consequently regulation, have been predicted for years. Indeed, one argument in support of deregulation of the industry in the 1990s was that competition would provide the incentive for the development of new technologies that could vastly reduce costs and enhance the quality of our environment. Clearly, some of those innovations are likely to happen, but the time frame is unknowable. The unknowable also could be external forces of enormous consequence. Is the industry in denial about the possibility of terrorism, or a widespread nuclear shutdown (as occurred in Japan in 2001 and 2002), or end-use technology such as Liquid Crystal Displays replacing lights, or fuel cell breakthroughs, or interest rate volatility, or dramatically rising coal prices, or electric vehicles? In retrospect, major transformations have taken place in the electric industry in the past 100 years. Utilities should focus on the tools that will position them to prosper in the next 100 years. By planning for both unknown and unknowable risks, utilities can identify common causal relationships between apparently unrelated factors that are interwoven throughout various scenarios. Developing strategic plans based on these causal relationships not only minimizes risk, it provides a competitive advantage during times of industry turmoil and better positions those companies to thrive under a wide range of future conditions.
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Sources for this section include Leggio, Bodde, and Taylor, op. cit.