DEREGULATIONOFTHEU.S. electricity industry, a process with strong implications for natural gas demand, slogged part way through a critical phase in 1997. State legislatures and public utility commissions were deciding how competition would occur at the retail level and who would bear the costs of change.
The possible outcome was 50 separate sets of answers to important questions about the amount of latitude consumers would have in choosing electricity suppliers, the mechanics of those choices, and disposition of hundreds of billions of dollars in utility book value expected to be voided by competition. And further action at the federal level was not out of the question. Deregulation bills had been introduced in the House and Senate, but floor action appeared unlikely before 1998.
Electricity deregulation had moved to the state level in April 1996, when the Federal Energy Regulatory Commission carried the process through the wholesale level with its Orders 888 and 889 and left retail deregulation to the states. Through mid-1997, eight states had enacted legislation restructuring their electric utility industries, according to a tally by the U.S. Energy Information Administration. Five states had issued comprehensive regulatory orders addressing the issue, and 23 states had legislative or regulatory investigations under way.
For natural gas, slow progress toward complete deregulation created huge uncertainty about future markets, especially during the several years expected to be needed for the transition to a competitive electricity market. Generation of electrical power, especially in nonutility plants, was generally regarded as the gas market sector with greatest potential for growth (Fig. 1; Tables 1, 2).
Future demand within that market, however, depended greatly on how utilities made use of existing generation capacity in a competitive climate. At least for the 3-5 years following deregulation, a continuation of strong growth in gas use for power generation was anything but certain.
Moving to competition
If a detailed picture of a deregulated electricity industry remained elusive in 1997, the general pattern did not.
Before deregulation, utilities owned and operated generation, transmission, and distribution functions, delivering electricity as a bundled service to consumers with little or no choice of supplier. After deregulation, generation will be subject to little or no regulation. Transmission and distribution will remain regulated, although the nature of regulation will change. The three branches of the business will be operated, if not owned, separately. And many consumers will have some degree of choice among electricity suppliers.
Congress made the first official step toward deregulation in 1978 by passing the Public Utility Regulatory Policy Act (Purpa). Purpa was significant for creating the first place in the wholesale market in many years for generators not owned by utilities. Purpa called those nonutility generators "qualifying facilities," which included cogeneration plants and generators fueled by renewable energy. Utilities had to buy electricity from qualifying facilities and from designated small power producers at prices reflecting their avoided costs, based on estimates of what the buyers would have paid for the same amount of power if they had added generation capacity or bought the electricity from other utilities. Purpa also made utilities undertake major conservation programs.
In 1992, the Energy Policy Act took nonutility power generation a step further. It created an entity called "exempt wholesale generator," which could produce electricity by any of a variety of means for the wholesale market free of utility-type regulation and which could, unlike cogenerators under Purpa, be owned by utilities. The act further allowed wholesale wheeling-or transactions across a power grid by parties other than grid owners-and directed the FERC to promote wholesale competition.
FERC Orders 888 and 889 of April 1996 provided for open access to power grids for wholesale transactions and took steps to assure competitive equivalency of that access, such as mandating functional segregation of utility marketing functions and provision of real-time electronic information on availability of capacity. The FERC orders further allowed utilities to recover, through charges on departing wholesale customers, stranded costs, or past investments made or obligations incurred to serve customers lost to new competition. They also set standards of operation for independent system operators (ISOs)-entities created to manage and operate power grids independently of utility owners.
FERC thus took deregulation to the point of open access to the power grid by wholesale nonutility generators. At that stage, however, movement toward competition in electricity markets had only begun.
Stranded costs
In fact, the parts of the process left for states to handle were the toughest. The two biggest general issues were stranded costs and mechanisms of consumer choice.
Stranded costs gave state authorities an enormous problem to solve. At mid-1997, estimates of future stranded costs ranged from $10-20 billion to as high as $500 billion. The costs were expected to materialize as utility consumers took advantage of their new ability to buy electricity from other providers. Investments that the utilities had made to serve those customers, whether in generating capacity or purchase agreements, would lose value and have to be written down in utility financial books. The amount of expected devaluation was the estimated stranded cost.
The question was who would pay for these asset devaluations. The basic options were utility shareholders and ratepayers. From the utility`s point of view, the greater the share of stranded costs recoverable from ratepayers the better.
Nonutility suppliers, of course, took a different view. Before legislatures and public utility commissions, they argued that allowing for the recovery of stranded costs compromised the process of deregulation and kept consumers from enjoying full benefits of competition. They believed that compensating utilities for investments soured by competition gave traditional electricity suppliers unfair competitive advantage in the new environment.
To these charges, utilities responded that investments voided by competition had been ruled prudent by regulatory authorities when they were made and, moreover, were needed to satisfy service obligations central to regulation. Furthermore, they said, some uncompetitive investments were mandated by legislation, such as Purpa`s requirements that utilities buy electricity from qualifying cogenerators and plants fueled by renewable energy. Unless they received the right to renegotiate contracts related to Purpa, utilities would be left with obligations to buy expensive electricity impossible to sell, except at a loss, in a competitive environment.
Securitization issue
An issue of special concern for nonutility generators was a financial arrangement called securitization of stranded costs. The procedure enabled a utility to turn a regulatory order allowing for recovery of stranded costs into immediate cash. Since a recovery order amounted to a guaranteed future stream of cash, a utility could sell it at a discount to an investment institution, which would in turn sell shares of the package in financial markets.
For a utility with significant investment in generation equipment threatened by competition, securitization was very attractive. With the recovery order, the utility could write down costs of existing generation equipment without sustaining the loss that would normally come with such a move. And lowering the book value of the equipment lowered fixed costs of operations. So the utility could continue using otherwise uncompetitive generating capacity at greatly reduced cost. It also had the infusion of cash, which had bailed it out of money-losing investments of the past, to help it meet new competition.
Nonutility power producers, most of which used natural gas as primary fuel, opposed securitization of stranded costs. In their view, the scheme not only threatened to extend operations of old generation capacity but also gave utility owners of that capacity an unfair competitive advantage.
State approaches States differed in their handling of stranded costs.
California, among the first states to deregulate its electricity industry, allowed utilities to recover stranded costs through what regulators called a competitive transition charge. Implemented through legislation enacted in September 1996, the mechanism set time limits on recovery and rate caps aimed at keeping consumer costs from rising as a result of the charge. In late 1997, however, news reports were raising questions about whether electricity costs at the retail level would decline appreciably, in spite of increasing supplier choice, during the recovery period for stranded costs. For most types of costs of investor-owned utilities, that period was to last through 2001.
In New York, the Public Service Commission, as part of an initiative authorizing retail choice starting in 1998, proposed to spread stranded costs across all consumers. Payment would take the form of what the commission called a wires charge at the distribution level. New York`s deregulation program urged utilities to seek "creative means" to reduce stranded costs, apparently envisioning less than full recovery.
Maine`s Public Utility Commission took a more moderate approach to stranded-cost recovery in a deregulation plan it submitted at the end of 1996. It delayed estimation of utility stranded costs until 2000 and called for new estimates in 2003 and 2006. The commission`s view was that stranded costs would shrink over time and that utilities could recover those that remained through surcharges administered by transmission and distribution companies divested from utilities.
Among other approaches, New Hampshire allowed recovery of 50% of stranded costs from customers participating in deregulation, Alabama and Arizona allowed recovery through "exit fees" paid by former utility customers choosing other suppliers, and Rhode Island allowed partial recovery.
Other state issues
Stranded costs were the biggest but not the only issue facing state legislators and regulators in 1997.
Mechanisms of consumer choice raised a variety of questions, not least of which was how retail marketers would solicit business and physically provide service. A related issue was accounting for consumer switching among suppliers, a problem that was expected to require new metering technology. Competition also pushed a number of states to examine new rate designs. And many states were looking for ways to ensure that transition costs were not heaped on small residential and consumer electricity buyers.
In other areas, most states wanted to sustain the obligation of utilities to ensure reliability of service to customers but had to adjust the requirement to the rigors of competition. They also had to grapple with equivalency of transmission and distribution service under competition. Some states, such as Maine, concluded that retail wheeling necessitated divestiture by utilities of transmission and distribution assets.
State governments also had to deal with utility obligations in areas such as use of renewable fuel, environmental protection, energy conservation, and assistance to the needy-obligations that in most cases hurt utilities` abilities to compete against new generators not similarly burdened.
In line with expectations, states acting first on deregulation were those where electricity costs were highest under regulation. Those states included California, states of the Northeast, and Illinois-all with comparatively high populations ensuring political support for deregulation at the national level (Fig. 2).
Because of the disparity among states of electricity costs in the era of regulation, competition-if allowed fully to develop-was expected to level prices across the U.S. and reduce the nationwide average over time. The Gas Research Institute (GRI), in a study that took into account assumptions about energy industry restructuring, said the national average electricity price to consumers likely would fall to 5.2¢/kw-hr in 2015 from 6.9¢/kw-hr in 1995, both in 1995 money. The amount of general price decline was difficult to predict in 1997 because of the many uncertainties that would linger until states settled their difficult issues of deregulation, possibly supplemented by an act of Congress.
Effects on natural gas
Similarly uncertain were the consequences for consumption of natural gas.
Development of a wholesale market for electricity had opened a growth market for gas as a fuel for nonutility electricity generators, mainly for peaking but increasingly in baseload uses. In relation to coal-fired, nuclear, and hydropower generation capacity, gas-fired generation in combined cycle plants was attractive on a total-cost basis but less so on the basis of marginal costs. Gas-fired combined cycle plants generally cost less to build, operate, and maintain than the other types did and had become more efficient on an energy conversion basis than modern coal-fired generators. But gas itself was more expensive on an energy-equivalent basis than coal and power produced at nuclear and hydro plants.
In general, therefore, gas demand for power generation would grow most if deregulation encouraged construction of generating capacity. And it would grow least if deregulation encouraged old coal-fired and nuclear capacity to remain in service. The mix depended on what incentives states created with their deregulation plans and the directives they issued for use of capacity.
Gas markets thus had a great stake in handling of stranded costs, which would be central to utility decisions whether to retire, repower (keep capacity in use with a new primary fuel), or extend the life of old coal-fired and nuclear capacity. They also depended on the directions that deregulation plans gave to grid operators, including ISOs.
Natural Gas Supply Association (NGSA) warned in the second half of 1997, for example, that cost-driven utilities would likely dispatch electricity from different fuel sources in order of lowest to highest marginal cost. Such a dispatch priority would suppress demand for gas.
NGSA further pointed out that many utilities had unused coal and nuclear capacity with which to compete for markets, largely on a marginal cost basis. And in response to competition, they would tend to substitute some wheeling for gas-fired peaking.
Indeed, management of what the electricity industry calls the reserve margin was crucial to the outlook for gas. The reserve margin is essentially generating capability that a utility holds idle against periods of peak load, or demand. It is measured as the difference between generating capability and peak load, divided by generating capability. Even before FERC opened access to power grids with Orders 888 and 889, reserve margins were steadily declining because of growth in wholesale generation and the consequent abilities of utilities to buy electricity to meet peak demand.
Under complete deregulation, utilities would be able not only to buy power to meet peak load but also raise generating capacity utilization in off-peak times and sell excess electricity into the grid to the extent markets existed for the output. As utilities thus moved to lower the reserve margins they had maintained under deregulation as a response to competition, a nationwide generating capacity surplus was expected to become apparent.
Life extension and increased utilization rates for existing capacity would erode the need for new generating capacity, most of which likely would have been fired by natural gas. In 1997, estimates of volumes likely to be affected were only guesses based on assumptions about capacity uses. The GRI acknowledged the effect but predicted that gas volumes would be relatively small. It also pointed out that much of the effects would occur during a 3-5 year transition period to deregulation, after which the environmental and economic advantages of gas-fired electricity generation would reassert themselves.
The renewables issue
A political issue highlighted by NGSA in 1997 was the treatment of renewable energy sources used for generation of electrical power. In 1997, renewable energy excluding hydropower and biomass accounted for less than 1% of total electricity generation. With hydropower and biomass, the renewable share increased to 3%.
Mandates for use of renewable energy were parts of some state-level proposals as well as several electricity-deregulation bills in Congress. Supporters of the mandates argued that Purpa had encouraged investment in generating capacity based on renewable energy and that the capacity would become uncompetitive on the basis of cost under deregulation. Yet mandate proposals sought further market penetration by renewable sources, not just protection of capacity encouraged by past legislation. The mandates ranged to as high as 20% of the electricity generation market.
NGSA characterized a renewables mandate as a "set-aside" of part of the electricity market for noncompetitive energy. And the set-aside would displace highest-marginal-cost electricity, which likely would be gas-fired. A renewable mandate equivalent to 1% of the 1997 electricity market, NGSA estimated, would supplant demand for slightly more than 300 bcf/year of natural gas. Depending on which renewables were included, a mandate to increase renewables use to 5% of the electricity generation market could displace 600 bcf-1.5 tcf/year of current gas-fired electricity, NGSA said. And a 12% mandate could replace all baseload natural gas.
Thus, natural gas interests had much at stake in the renewables issue and other questions still swirling around electricity deregulation in 1997. As NGSA pointed out, utility and nonutility generation of electricity consumed 4.5 tcf in 1996. That was 23% of the U.S. market for natural gas.
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