Electric utilities are lying low and remaining mum about their capital investment plans. Not eager to “give away the store,” detailed information about future generation, transmission and distribution spending is no longer trumpeted. A consequence of competitiveness and the growing diversity of entities that own and operate facilities is that government agencies, industry groups and reliability organizations face growing difficulties in obtaining consistent and complete data on existing and planned projects. Capital allocation has become a guarded trade secret.
Generation projections/best guesses
In an October 1999 report, “Maintaining Generation Adequacy in a Restructuring U.S. Electricity Industry,” Oak Ridge National Laboratory`s (ORNL) Eric Hirst and Stan Hadley discussed difficulties in obtaining data and making projections. Because the electricity industry is currently in an awkward position-half regulated and half competitive-many utilities are understandably reluctant to make investments until the rules and the separation between competitive and regulated activities are clear.
ORNL`s report serves as a barometer to gauge general trends in utilities` investment in generation. Hirst and Hadley reported annual capacity additions declined from 9,700 MW between 1991 and 1995 to only 5,200 MW between 1996 and 1998. Utilities added less than 500 MW of new capacity in 1998 and retired almost 2,900 that year, a net loss of 2,400 MW. On the other hand, nonutility companies added 3,000 MW in 1998.
In its “Annual Energy Outlook 2000,” the Energy Information Administration (EIA) estimated that assuming an average plant capacity of 300 MW, a thousand new generating plants with a total of 300 gigawatts (GW) of capacity could be needed by 2020 to meet growing demand and to offset retirements. Of the new capacity, 90 percent is projected to be combined-cycle or combustion turbine technology fueled by natural gas or both oil and gas.
More than 21 GW of new coal-fired capacity is projected to come on line between 1998 and 2020, accounting for almost seven percent of all capacity expansion. Renewable technologies account for the remaining three percent of capacity expansion by 2020-primarily wind, biomass gasification and municipal solid waste units. EIA estimated that by 2020, annual investment in new capacity would be nearly $30 billion, assuming the cost of new plants is recovered over a 20-year period.
The North American Electric Reliability Council (NERC) noted its projections for capacity margins for years 2003 to 2007 are highly uncertain because the owners of merchant plants often do not reveal their plans early and because new generating units can often be constructed in only a few years-reducing the need for long-term projections of generating capacity.
Transmission “planning” an oxymoron
Integrated transmission planning is becoming more difficult, according to Hirst. Traditional, vertically integrated utilities coordinated planning and construction of generation and transmission. Coordination now may suffer in a competitive industry due to:
– Generation investors are reluctant to reveal plans;
– Transmission planning takes longer because there is more public invol-vement and because coordination between regional transmission organizations and transmission owners is required;
– Continuing public opposition to new transmission lines; and
– Load forecasting is challenging-who does it and on what basis.
Figure 1 shows a decade-long decline in transmission investment and maintenance. According to Standard & Poor`s, transmission and distribution companies are expected to remain tightly regulated monopolies, with rates set on a cost-plus basis in many circumstances. Under a cost-plus regime, rates are set to recover costs and, for investor-owned utilities, a return on shareholder investment. While a utility may be largely protected from business risk under cost-based rates, the responsiveness of the rate-setting process to changes in a utility`s cost structure influences the business pressures on the company. Although cost-plus regulation is usually favorable, directives to regulators are important. For example, a regulator whose mandate is to balance needs of customers and shareholders is preferable to one whose main responsibility is to protect the ratepayer. Also, legislation that incorporates language such as “favorable,” “adequate,” or “appropriate rate of return” as a means of setting revenues can be widely open to interpretation.
Spurring on transmission investment in today`s market requires reconsideration of incentives. For example, there is a need to entice investors with higher return on equity and shorter cost-recovery periods.
Customer service takes a front seat
Entergy Corp. exemplifies a recent industry shift in utilities` spending priorities-boosting dollars committed to customer service. Entergy announced a five-year, $9.8 billion capital investment plan of which $4.2 billion is earmarked to enhance customer service and reliability. Another $3.9 billion is allocated to growth in wholesale operations and $1.7 billion will be used to purchase and operate additional nuclear plants over the next five years.
Chartwell Inc. reported in June 1999 that customer service center budgets varied among surveyed utility companies, with most reporting budgets between $100,000 and $500,000; and $1 million and $5 million for mid-sized investor-owned utilities and large municipals. Three utilities reported budgets of more than $10 million, including two companies with two million-plus customers that reported spending more than $20 million annually on their customer service operations.
In another survey (March 1999), Chartwell looked at internal billing department budgets. Most utilities surveyed (26 percent) carry billing department budgets between $1 million and $1.9 million annually. About 16 percent have billing operating budgets of $200,000 to $250,000, and another 16 percent have reported budgets of about $500,000 annually.
Figure 2 shows surveyed utilities` billing system upgrade budgets (defined as cost of new system or upgrade of existing system).
E-commerce continues to increase in the industry. At this point in time, utilities` services offered on the Internet overwhelmingly are provided without charge. Only eight of 101 respondents reported charging for a Web service. Fee-based services are likely to grow, particularly as companies move to offer more products for commercial and industrial customers.
To date, the development of the Internet has favored free services for mass market customers. As e-commerce offerings mature and the number of services increases, customers may become more accustomed to paying for Web-based services.
Figure 3 shows the average budget for Web projects and Figure 4 shows marketing budgets for e-commerce.
Copies of Hirst`s and Hadley`s report are available at www.esper.com/hirst. Hirst may be contacted at 423-482-5470. Information about Chartwell Inc.`s reports is available at 404-237-9099.
Because the electricity industry is currently in an awkward position-half regulated and half competitive-many utilities are reluctant to make investments until the rules and the separation between competitive and regulated activities are clear. Photo courtesy of Conoco.
Spurring on transmission investment in today`s market requires reconsideration of incentives. Photo courtesy of ABB Power Lines.