The third factor setting the stage for change in the electricity industry was the 1978 Energy Policy Act. While it created an environment for experimentation with independent power, it was the establishment of bad contracts that raised electricity rates that would help create incentives for deregulation. The Act also had an important indirect impact: by initiating the deregulation of the natural gas market, it provided the infrastructure to support new natural-gas-fired generation.
The Carter administration attempted to deal with the perceived “energy crisis” with a comprehensive proposal to deregulate natural gas, encourage conservation, and tax energy consumption and imports. A contentious political debate that lasted more than a year resulted in a congressional conference committee working out compromises motivated by fatigue.1 The Energy Policy Act included the Power Plant and Industrial Fuel Use Act, PURPA, and the Natural Gas Policy Act.
PURPA created a new category of power plants – “qualifying facilities” (QFs). QFs included power plants that burned renewable fuels or employed renewable energy sources and cogeneration plants that met efficiency thresholds. Section 201 of PURPA generally defined a qualifying small power production facility as one using only biomass, waste, and/or renewable resources as a primary energy source, with a capacity no greater than 80 MW. A cogeneration facility was a facility that produced both electricity and steam or some other useful form of energy. There was no size limit for qualifying cogeneration facilities. A QF must be owned by a person not primarily engaged in the generation or sale of electric power. Nonutility generation before 1978 was typically undertaken to meet demands of major industry groups such as the paper, chemical, mining, and oil refining. Most of the power was produced through cogeneration, and the electricity was for the producers' own use. Utilities purchased surplus power at wholesale power rates and charged retail rates for backup power and additional charges for transmission and distribution capacity.
Section 210 of PURPA established a rule requiring electric utilities to interconnect with and purchase power from any facility meeting the criteria for a QF under the Act. Qualified cogenerators of any size, and renewable energy small producers under 30 MW, were exempt from both PUHCA and the FPA, while small producers from 30 MW to 80 MW were exempt from PUHCA. Cogenerators must meet certain non-electricity production and overall efficiency standards.2 FERC held that electric utilities, public utility holding companies, or subsidiaries of either can own up to 50 percent of the entity that owns the qualifying facilities.3
A key to the successful passage of the cogeneration and small renewable energy producer provisions was the lobbying efforts of Wheelabrator-Frye Corporation. Wheelabrator was a developer of waste-to-energy facilities, and saw an opportunity to expand its market by improving the economics of its projects through better terms from sales of electricity to utilities. Wheelabrator hired the law firm of Van Ness, Feldman, and Sutcliffe, which had excellent Washington connections, to lobby for selected provisions. Van Ness managed to extend the exemption from PUHCA to small power producers. Van Ness, along with Senator Durkin of New Hampshire, a supporter of small power production, was also able to base the payment by utilities for surplus electricity on total avoided cost rather than incremental (i.e., operating) avoided cost. While incremental cost was not defined in the final bill, the conference report noted that full avoided cost was the conferees' intent. The author of the report, Ross Ain, would become the FERC associate general counsel in 1979, writing the interpretation that was incorporated in FERC regulations governing avoided costs.4
In 1980, FERC specified how the price for QF power was to be determined. The agency established general ratemaking principles in its rules but delegated their implementation to the state regulatory commissions.5 The rule defined “avoided costs” as the costs to an electric utility of energy or capacity, or both, which the electric utility would generate or construct itself or purchase from another source. It included both the fixed and operating costs that could be avoided by obtaining energy or capacity from QFs. If a purchase from a QF permitted the utility to avoid the addition of new capacity, then the avoided cost of this new capacity should be used.6
A challenge to PURPA's constitutional legitimacy was denied in FERC v. Mississippi.7 The Supreme Court not only upheld PURPA but implicitly provided permission for the federal government to extend its authority to intrastate electricity transactions:
We agree with appellants that it is difficult to conceive of a more basic element of interstate commerce than electric energy, a product used in virtually every home and every commercial or manufacturing facility. No State relies solely on its own resources in this respect. Indeed, the utilities involved in this very case, Mississippi Power & Light Company and Mississippi Power Company, sell their retail customers power that is generated in part beyond Mississippi's borders, and offer reciprocal services to utilities in other States. The intrastate activities of these utilities, although regulated by the Mississippi Public Service Commission, bring them within the reach of Congress' power over interstate commerce.8 [citations omitted]
In American Paper Institute v. AEP, the Supreme Court held that FERC had the authority to require payments up to the full avoided cost. The Commission noted that ratepayers and the nation as a whole would benefit from the decreased reliance on scarce fossil fuels and the more efficient use of energy. Under these circumstances it was not unreasonable for the Commission to prescribe the maximum rate authorized by PURPA.9
QFs could exploit highly leverage financing structures unavailable to conventional utilities. Utilities were required to purchase power from QFs, and rates were exempt from state regulation. FERC's decision to establish full avoided cost as the default price if a QF and utility could not agree on a price schedule gave the QF leverage in negotiations. A long-term purchased power agreement (PPA) provided guaranteed cash flow that enabled QF developers to obtain financing. Investors could leverage a small amount of equity, since they could use the PPAs as collateral for loans. Nonutilities were able to finance projects with high debt/equity ratios, with the percentage of debt in the capital structure often ranging between 80 percent and 90 percent. Sale-leaseback agreements allowed for 100 percent debt financing once the nonutility plant became operational. The potential advantage of highly leveraged project financing may have been partially offset by the higher cost of borrowing for nonutilities, since this financing was usually done on a nonrecourse basis, with the project as security.10
In addition, the Energy Tax Act of 1978 gave a 10 percent tax credit to businesses, including QFs, that installed certain classes of energy equipment after September 1978 until the end of 1982. Tax credits for renewable energy were extended through 1985 with the passage of the Windfall Profits Tax Act of 1980, and included a 10 percent credit for cogenerators. The 1981 Economic Recovery Tax Act allowed a five-year depreciation of wind turbines. These provisions encourage the development of investment vehicles designed to exploit tax shields.11
While a few states, such as New Hampshire and Vermont, established avoided cost rates on a statewide basis, most states determined avoided costs utility by utility. California became the key state for the expansion of independent power producers (IPPs), owing to a regulatory environment that was friendly to cogenerators and small producers, rapid economic growth that created a growing market, and physical and regulatory constraints that increased costs of adding new capacity. In January 1982, the CPUC ordered utilities to offer one of five power purchase contracts, or standard offers, with prices based on the short-run avoided cost of fuel and capacity payments. US Windpower won regulatory approval in 1982 for a contract with costs above avoided costs in the early years and lower costs in later years. This contract became the template for a new standard offer with fixed prices based on a ten year forecast of full avoided costs, after which price would be based on short-run avoided costs. The contracts offered in 1983 and 1984 assumed continual increases in the cost of electricity, even though fuel prices had already begun to decline. The result was a response to these standard offers that far exceeded the expectations of regulators and utility managers.12
The escalating fixed contracts made investment in QFs almost riskless. Since an investor could sign a standard offer without a financial commitment, and had five years to complete the project, these contracts became zero-cost options to build. If energy prices rise, making a project uneconomical, the investor could walk away. However, if fuel prices declined, the project had a guaranteed revenue stream. The CPUC realized that they had engendered a potential capacity glut and suspended these offers in 1985, issuing a new standard offer that was less attractive to investors. But the damage had already been done, with 15,000 MW of contracts signed.13
High-priced states such as New York, the New England states, New Jersey, and Pennsylvania also embraced PURPA requirements with enthusiasm. Many state PUCs and legislatures greatly overestimated long-run avoided costs, thus forcing utilities to buy huge amounts of overpriced power. When utilities entered into long-term PPAs, they assumed financial risks, with payment agreements (in particular capacity payments) viewed as being analogous to off-balance sheet debt by bond-rating agencies. When power purchases by a utility exceeded 10 percent of their capacity or total sales, bond-rating agencies added some portion of the fixed payment obligations to the utility's existing debt to compute its total long-term debt liability.14 This resulted in an additional, “hidden” cost to purchases of power from QFs.
Over time, utilities convinced regulators that competitive bidding was a more effective means of setting avoided costs for purchasing QF power than arbitrary avoided cost calculations. In 1984, Central Maine Power and the Maine Public Service Commission became the first to put competitive bidding into practice. The commission set avoided cost rates for QFs based on the cost of a nuclear power plant, which resulted in offers to supply more power than Central Maine needed.15 After 1984, utilities or public utility commissions in twenty-seven states adopted or developed competitive bidding systems, and as of December 1989, competitive bidding solicitations were conducted in nineteen states.16
By the late 1980s, FERC had become concerned with the rates provided to QFs in some states and issued a prospective order in April 1988, holding that in light of changes that had occurred since 1980, states thereafter could not impose a rate for QF sales to utilities in excess of avoided cost.17 However, FERC stayed this prospective order a few months later, pending completion of a then-pending rulemaking proceeding.18 FERC finally ruled on the issue in January 1995, declaring that a statute that could require an electric utility to purchase power at a rate above avoided cost was preempted by PURPA.19 However, the Commission also “grandfathered” QF contracts where the avoided cost issue could have been raised.20
PURPA spurred the sale of nonutility power to the U.S. electric utilities. Sales to IOUs increased from 28.3 million MWhs in 1985 to 164 million MWhs in 1992, or almost 6 percent of the electricity generated for sale to end-use consumers. Cogenerator QFs accounted for about 60 percent of U.S. nonutility electricity-generating capacity, and other small power producers accounted for 15 percent. Most nonutility generating capacity was in the manufacturing sector of the economy. The chemical industry (25 percent of nonutility capacity), the paper industry (18 percent), and petroleum refining (8 percent) were the chief beneficiaries of the QF rules.21 All three industries are characterized by steady and predictable thermal loads, which allowed operation of cogeneration facilities at high levels of utilization.
The success of PURPA generators created the perception that economies of scale in generation had been supplanted by new technologies. This was partially the result of problems building large power plants, but also because of the ability of small combustion turbines to exploit low natural gas prices. The success of cogeneration facilities had less import for utility structure, since the population of favorable locations would eventually be exhausted. However, the creation of so-called PURPA machines – power plants with a contrived thermal application masquerading as a cogeneration facility – suggested that independent power projects were becoming economic without the need for a thermal energy revenue stream.22 PURPA had little direct impact on gas turbine development as the primary customers for these generators were the traditional utilities and their need for flexible generation to meet peak loads.
PURPA did create a constituency of independent power suppliers who promoted state and federal policies to expand opportunities for independent power.23 Some utilities, with experience with negotiating PPAs and a track record working with small power producers, became more receptive to reliance on third-party supplies as a less risky alternative to building major new generating facilities. Other utilities saw an opportunity to spin off subsidiaries to supply generation to utilities outside of their traditional service territories and without traditional cost-of-service constraints.
The decline in the price and the increased availability of natural gas due to deregulation made natural gas a more attractive fuel for electricity generation during a period when there were significant advances made in turbine and power plant design. The early 1960s saw the beginning of gas turbine “packages” for power generation when GE and Westinghouse engineers were able to standardize designs. To win over customers from traditional steam turbine or reciprocating engine equipment, manufacturers offered fully assembled packages, which included turbines, compressors, generators, and auxiliary equipment. Standardization allowed for multiple sales with little redesign for each order, easing the engineering burden and lowering costs. Advances in cooling and improvements in turbine materials allowed manufacturers to increase their firing and rotor inlet temperatures and improve efficiencies. The fast startup times of gas turbines allowed them to ramp up quickly during demand peaks, making them better suited for that role than steam-driven turbines. Despite efficiencies of only around 25 percent, the market for combustion turbines rapidly expanded in the late 1960s and early 1970s.24
The first gas turbine installed in an electric utility applied in a combined-cycle (gas turbine and steam boiler) power system was a 3.5 MW gas turbine that used the energy from the turbine exhaust gas to heat feed water for a 35 MW conventional steam unit in 1949. Most combined-cycle power generation systems installed during the 1950s and early 1960s were basically adaptations of conventional steam plants, with the gas turbine exhaust gas serving as combustion air for the boiler, raising the efficiency of the combined cycle by 5–6 percent compared to a similar conventional steam plant. Heat recovery combined cycles, which recovered the heat in the gas turbine exhaust gas using finned tubes, entered service in 1959. In the 1970s and 1980s, heat recovery for feed water preheating became a mature technology. Material enhancements and cooling evolutions were the main gas turbine improvements that would increase operating efficiencies over the next three decades. An increase in firing temperature made possible through improved metals and coatings and metal surface cooling techniques provided more efficient turbine operation, and better heat exchangers improved utilization of exhaust heat.25 The GE Frame 7F gas turbine marked the beginning of a period of rapid market expansion, successive product launches, and intensified technological competition. The 147 MW power output of the Frame 7F was almost double that of GE's previous vintage of large gas turbines. A new combined cycle utilizing the Frame 7F was larger and more efficient than competitive systems offered by Westinghouse, ABB, and Siemens. The first GE Frame 7F turbine combined cycle was installed in Virginia Power's Chesterfield power plant, completed in 1990.26 These larger combined-cycle systems, although they had significantly higher capital costs, could achieve net plant efficiencies around 45 percent, compared to 30–35 percent for a state-of-the-art combustion turbine.27 Since coal plants were limited to a net efficiency of less than 40 percent, this gave combined-cycle plants a competitive advantage if gas prices were close to coal prices.
Natural gas had no particulate or sulfur dioxide issues, and improvements in combustion turbines reduced NOx emissions. The 1987 repeal of the Fuel Use Act, which prohibited construction of new gas and oil-fired boilers, allowed merchant generators to use gas as their primary fuel. Combustion turbines could be built in eighteen months in increments of 100–200 megawatts, while combined-cycle plants could be built in twenty-four to thirty months, compared to the six-to-eight years necessary to develop a coal-fired plant.28
Technological advances continued during the 1990s, resulting in incremental improvements in a number of areas of plant design. A triple pressure reheat cycle became the industry standard for achieving higher efficiency. With higher gas exhaust temperatures from the combustion turbines, the steam boiler pressure steadily increased. In warm weather, a combined-cycle plant may lose as much as 10–15 percent of its rated output because of higher ambient air temperature. Inlet air cooling, evaporative cooling, refrigeration cooling, and/or moisture injection provided power output enhancement, though at a cost in operating efficiency.29
One factor that slowed the adoption of new combustion turbines was the emergence of reliability problems stemming from the rush to increase the size and operating efficiency of these plants. In the mid-1990s, the problems of reliability, which had plagued combustion turbine technology before 1986, returned with a vengeance, and all the major manufacturers had to devote significant efforts to problem solving. Although these problems were addressed, and newer generations of turbines were developed, the market remained soft until the end of the decade.30
The larger combustion turbines allowed combine-cycle plants to exploit economies of scale in steam boiler size and pressure. Most of the aeroderivative combustion turbines31 and older combustion turbine units were used for peaking. Peaking units frequently ramp electricity output up and down (cycling), leading to greater maintenance needs, more rapid performance degradation, and shorter life for turbines. The larger combustion turbines were reliable as long as they could be used as part of baseload combined-cycle generation plants.32
Construction of independent generation plants began in earnest in the late 1980s, as independent generators sold power to utilities wary of committing to new construction and directly to large industrials when they could bypass the local utility's monopoly franchise. By 1992, there were almost 44,000 MW of QF facilities on the ground, and another 13,000 MW of independent power plants. Most of the purchasing utilities were located in high-cost areas. Demand risk was allocated to buyers, with price rising when capacity factors fell. A study of power contracts during the 1990–1993 period found that natural gas plants were clearly more economic than coal.33 A key element of these contracts was dispatchability, as utilities wanted to be able to dispatch these resources similar to the way they operated their own plants. Explicit linkage of bidding with the utility's resource planning process became common practice.
Figure 4.1. Natural Gas Generation.
Access to transmission emerged as a key element for projects located outside a utility's service area. This put the developer into a quandary: locate within the service area and you may face a monopsony buyer who can pressure you into accepting lower prices; locate elsewhere and you have to negotiate long-term transmission rights, sometimes across multiple utility service areas.34 Buyers had to arrange for transmission or wheeling service if the transaction required use of a third utility's transmission system. FERC's jurisdiction regulated the rates charged for transmission service, but it couldn't order a utility to provide such service.35 This limited transmission arrangements to voluntary agreements, subject to the transmission utility's whims, with only the threat of antitrust sanction as a weapon to encourage cooperation.
However, the situation was not as bleak as it seemed at first glance. The political power of municipal utilities and cooperatives had forced some cracks in the IOU monopoly over power wheeling. Prior to 1979, many municipal utilities had obtained limited permission to wheel power on IOU transmission systems. Their success was unanticipated fallout from nuclear projects. In a compromise between public and private power proponents, the Atomic Energy Act of 1954 endorsed development of nuclear generating plants by the IOUs but required the Atomic Energy Commission (later the Nuclear Regulatory Commission) to consider antitrust issues in its licensing procedures. In 30 of the 100 construction permits issued by the Nuclear Regulatory Commission during the 1960s and 1970s, the agency imposed conditions to relieve alleged anticompetitive activities by licensees. These typically took the form of allowing municipal systems within the IOU's service area some participation in the nuclear project (e.g., partial ownership), including transmission access. The result was that these IOUs had to publish a transmission tariff, which subsequently served as a wedge to obtain more extensive access.36
Municipal power companies obtained additional wheeling rights from antitrust suits brought under the Sherman Act. In Otter Tail,37 the most prominent of these cases, the Supreme Court found that the Otter Tail Power Company used its monopoly over transmission to impede municipalities within its retail area from establishing viable distribution companies when their contracts with Otter Tail expired. The Court found that electric power companies were subject to the antitrust laws, but there was no authority granted the Commission under the FPA to order wheeling of power, as common carrier provisions were deleted from the final act.38 However, when a transmission utility blocks a distribution utility in its service area from accessing power from third parties, the Commission must order the utility to provide transmission services when such action is “necessary or appropriate in the public interest.”39 Courts ordered wheeling services in a series of subsequent cases, but only as a remedy for anticompetitive practices.
PURPA created a group of independent power producers that would lobby for more access to electricity markets, but their emergence was merely one of many trends converging toward the opening of electricity markets. IRP provided incentives for utilities to sign PPAs with independent power, while regulatory pressure encouraged utilities to pursue cost-saving measures such as bulk wholesale purchases. The gradual development of combustion turbine technology provided a viable alternative to central station, “natural monopoly” generation. However, to take the next step, it was necessary to provide the rationalization for disrupting the regulatory status quo. Enter the economists.
