92 Historical Highlights

Over a fifty year period bounding the turn of the century, PUCs were created by almost every state legislature. They were born out of the social and political concern that natural monopolies, such as railroads, should be prohibited from exercising undue discrimination on captive customers. During this period, the electric industry was still very young, local in scope, small in scale, and lightly regulated. As managerial and technological changes brought about an increasing opportunity for utilities to exercise market power through their expanding scope and scale, the political and legislative structure strengthened its regulatory influence over utilities. As holding companies steadily abused their concentration of economic power, and as the Great Depression created a political climate to address market abuse, federal laws were passed in the 1930s (the Federal Power Act, the Public Utilities Holding Company Act, and others). The New Deal established the Rural Electrification Administration and created major federal electric developments (such as the Tennessee Valley Authority and the Bonneville Power Authority). These developments represented an alternative to the private and municipal owners of electric infrastructure.

Post-World War II technological improvements and expansion of the economy were accompanied by a stable and pervasive influence of local, state, and federal regulation of the electric power industry. The investor-owned electric industry was satisfied with this arrangement, as regulation provided predictability of capital recovery to finance and profit from a growing and reliable electric infrastructure. If price to consumers, particularly residential consumers, was the major criterion to judge, regulation was a success through the 1950s and 1960s. This period has been referred to as the Golden Age of Regulation (Hirsch, 1999).

Several major energy tremors occurred in the 1970s that led to changes evident in today's regulatory environment. Conventional coal-fired generating stations reached a point when larger size no longer resulted in a lower unit price of electricity. Domestic oil production had already peaked. Environmental awareness began to have an influence on policy making. Costly nuclear power plants were built, often with severe economic and environmental consequences. The economy suffered from double-digit inflation, producing substantial cost overruns. Already reeling from high oil embargo-induced gasoline prices, the public pleaded with utility regulators to take a more active role in protecting consumers from escalating electric rates. Consumer advocates achieved success across the country by undertaking full-time residential and small business consumer advocacy appearances before PUCs.

Utility planners in the early 1970s were unprepared for what would transpire in the mid- and late 1970s. Utility planners applied the same 7% per year electric growth rates that characterized the previous decades and forged ahead with construction of large nuclear and coal-fired generators. This led to excess capacity and excess cost. Precipitated by the Organization of Petroleum Exporting Countries' (OPEC) 1973 oil embargo, all fuel costs were on the rise. Despite the warning signals, utilities did not anticipate the potential for industrial conservation in response to higher electric rates. Utilities did not anticipate double-digit inflation, and they underestimated the depth of concern about environmental quality.

In response, electric regulators often agreed with the public outcry that utilities should be held accountable for their decisions. Regulators responded to excess capacity by applying "used and useful" criteria to disallow full recovery on certain investments. Utility managers learned lessons that are now common in utility culture: be cautious when considering major investments in generation, do not overestimate electric demand, and do not underestimate the influence that aroused consumers have on regulators.

State regulators were not alone in response to the utilities' problems. Social and political pressure focused federal attention on energy policy. The Carter Administration encouraged, and Congress passed, a series of electric power reforms in 1978. These changes included requirements that state regulators examine their rate structures to ensure that they did not result in energy waste. Of greatest importance to this chapter, in 1978 Congress passed the Public Utility Regulatory Policies Act (PURPA),* which contained a provision (Section 210,17{c}(1)) requiring investor-owned utilities to interconnect with smaller systems (typically combustion-turbine plants) owned by independent power producers (IPPs). The law created qualifying cogeneration facilities, which produce heat and electricity from fossil fuels. Such facilities would need to meet guidelines, to be determined by the FERC, regarding energy efficiency, types of fuel used, reliability, and other characteristics. These non-utility generators were paid a rate that matched the avoided cost that the utilities would have spent on their next (typically large nuclear or coal-fired) generating station. Although some tried, utilities and regulatory bodies could not fully dodge this Congressional mandate. Retail electric rates on the rise in the 1970s continued to move upward as projected utility generation costs pushed higher, resulting in high avoided costs paid to the IPPs.

Some states, such as California, established very high avoided-cost payments, which attracted the IPPs. Other states, because of either a larger customer-owned utility presence that was exempt from PURPA or lower avoided costs, were not attractive to the IPPs. The high avoided cost payments to IPPs resulted in important impacts. IPP development spurred the transformation of fossil-fuel plants from boilers to cleaner, often smaller, and always more efficient aeroderivative and combustion turbine plants. About 10% of all U.S. electric capacity is now composed of non-utility generation.** PURPA and production tax credits provided a financial platform for renewable energy developers, particularly wind developers, to gain manufacturing and operational experience, leading to significant declines in cost.***

High nuclear generation cost overruns and avoided cost payments to IPPs in the 1980s set the stage for competition in the late 1990s. States with high electric rates (often those states that had a high penetration nuclear generation and IPPs) deliberately sought out market mechanisms as a way to lower

* In his article on PURPA in the Aug./Sept. 1999 issue of the Electricity Journal, Richard Hirsch said that: "... though some observers expected only a few hundred megawatts of capacity to be offered in California, entrepreneurs signed up for more than 15,000 MW."

** Some states such as California, New England states, Texas, and Michigan have a much higher penetration of IPPs, particularly compared to some states in the South and Midwest.

*** See America Wind Energy Association.

customers' bills.* There is a correlation between the early tier of states that decided to restructure the electric industries and those states with high rates from high-cost nuclear generation and high-price IPPs. By the late 1990s, reaction to high PURPA payments was a major point of contention in Congress. Congress debated whether PURPA should be terminated, either through stand-alone legislation or as part of what has become elusive comprehensive restructuring legislation.**

Not long after the electric jolts of the late 1970s and early 1980s,*** regulators adopted a more rational way of planning for new capacity additions. Regulators developed (first in Wisconsin and California, then in dozens of states) least cost planning, or integrated resource planning (IRP). The new approach featured public participation in a planning process, ultimately leading to a more cost-effective, competitive acquisition of both supply-side and demand-side electric resources. But just as IRP was starting to be normative across the country, the regulatory structure started to de-integrate. The further that states moved across the EUIR continuum, the faster the underpinnings of IRP were being removed. IRP is now being removed by legislation or regulators, to the gratitude of the utilities but to the dismay of energy-efficiency advocates and beneficiaries of PUC-oversight of competitive bidding. In short, as EUIR is established in the states, a corresponding elimination or diminution of IRP is occurring.

During the heyday of IRP in the early 1990s, electric regulators were taking a more proactive position relative to electric planning, and their focus was primarily on generation and, to a lesser extent, transmission. Pertinent to this chapter, the focus in most states was not, and is still not, on distribution and certainly not on distributed generation. However, with the coming disintegration of the vertically-integrated electric utility structure, regulators and the market are expected to focus their attention more on distribution.1 A review of electric utility asset utilization reveals that distribution assets are utilized a much smaller fraction of the time compared to electric generation asset utilization. This suggests that there is room for an increase in distribution efficiency. Distribution companies (Discos) in the evolving structure could be expected to spend more on distribution relative to generation and transmission. How they will spend that distribution money and whether their investment strategy includes DG are open questions.

* California's Public Utilities Commission, responding to a combination of too slow a recovery from the economic slump of the late 1980s, high electric rates, base closures, etc., set out on a course, beginning in 1993, to consider, then introduce, major structural changes to the California electric industry.

** See PURPA Reform Group, Washington, D.C.

*** Consider the debacles of the Washington Power Supply System, the Seabrook and Shoreham reactors, Three Mile Island, bankruptcies, and near-misses caused by synthetic fuel subsidies gone awry.

f The March 1, 1999, issue of Public Utilities Fortnightly is nearly completely dedicated to a discussion of this matter ([email protected]).

Before the advent of the EUIR debate, Congress yielded to 14 years (starting in 1978) of pressure for a comprehensive review of energy (including electricity) policy by passing the Energy Policy Act on October 25, 1992 (EPAct).* EPAct continued, and liberalized, the federal policy of allowing companies other than electric utilities to construct electric power plants and compete with utility-owned generation. EPAct required that interstate transmission line owners allow all electric generators access to their lines. The objective of these initiatives at the federal level was to further the efficiency of competitive wholesale electric markets. In effect, transmission lines became common carriers.

In 1996, after two or three years of piecemeal utility filing of tariffs required by EPAct, FERC opened what was called a mega-NOPR (notice of proposed rulemaking), that resulted in FERC Orders 888 and 889. The rules strengthened the open access transmission intent of EPAct. Tariffs were required to be filed that permitted any generator of electricity — utility-affiliated or independent — to have non-discriminatory access to transmission lines that have available capacity. As a follow up, the FERC was not satisfied with the progress made to create independent system operators (ISOs), which were first encouraged by EPAct. An NOPR was issued on the ISO, or Regional Transmission Organization, in the spring of 1999. The cost and benefit of creating multi-state ISOs to dispatch power by independent entities throughout the country is entangled in the broader EUIR debate and the state-federal relationship. The outcome of ISO developments could have an influence on distributed generation, as key questions of price transparency in wholesale markets will have a bearing on the transferability of these pricing rules on the distribution market.

EPAct moved federal electricity policy further along the competition continuum, but stopped short of mandating retail wheeling or direct access, which permits end-use customers to select their wholesale supplier of electricity. Since there is not a bright line that distinguishes between federal and state jurisdiction, and Congress did not want to define that distinction precisely in EPAct, the question of retail competition was left to the states, who have regulatory authority for approximately 90% of the electric infrastructure (the remaining being interstate transmission, which is regulated by the FERC).

* EPAct contained provisions including Energy Efficiency (Buildings, Utilities, Appliance and Equipment, Industrial, State and Local Assistance, Federal Energy Management), Natural Gas, Alternative Fuels, Electricity (Exempt Wholesale Generators, Federal Power Act, Interstate Commerce in Electricity), High-Level Radioactive Waste, Uranium, Renewable Energy, Coal, Strategic Petroleum Reserve, Global Climate Change, Reduction of Oil Vulnerability, Environment, Indian Energy Resources, and Nuclear Plant Licensing.

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