The focus for most of the U.S. power industry is on divestiture, consolidation and-perhaps most impor- tantly-cost containment. Rethinking capital allocation is integral in the wake of restructuring initiatives and their continued push to competition. The variables factored into a company`s business strategies are now weighted differently, or are new ones not previously considered. The balance of future risk and reward tradeoffs depends on variables such as regulated assets vs. non-regulated assets, domestic vs. international investments, joint ventures, and mergers and acquisitions. Overall utility performance indicates success so far in solving the changed equation.
As a whole, the industry remains robust. The Energy Information Administration (EIA) reported electric utility operating revenues of $195 billion in 1997 (see Figure 1). This is an increase of $6 billion over 1996. U.S. sales of electricity increased for the 15th consecutive year, according to the Edison Electric Institute (EEI). Overall, investments in unregulated power affiliates, international acquisitions and unregulated domestic activities increased 44 percent from $46 billion in 1996 to $66 billion in 1997.
Electric utilities have planned 42 GW in U.S. capacity additions for the 10-year period, 1998 through 2007, reported EIA. However, worldwide electric power growth is projected at 1,190 GW of new capacity, requiring an estimated $1.4 trillion in capital investment. This contrast between U.S. and international expected electric power growth provides the backdrop for the trends discussed in this report.
Aging, but not gracefully
Since the 1980s very little new conventional steam capacity was added. As a result, the average age of the U.S. fleet is increasing. By the year 2003, the average U.S. utility-owned conventional steam plant will be 32 years old, and the average plant fueled by oil or gas will be 36 years old. Many conventional steam plants have already passed the traditional retirement age of 40. However, few retirements are planned.
Between 1994 and 2015, utilities are expected to retire only 48 GW of non-nuclear generating capacity, according to the U.S. Department of Energy (DOE). Of that, only 19 GW of coal-fired retirements are scheduled. The current fleet will still largely be operating 20 years from now, with average age approaching 50.
Maintenance is taking on new meaning for these aging power plants. Utilities are in the early stages of planning major refurbishment. The line between maintenance spending and capital spending on upgrades of old plants is being blurred. DOE reports U.S. utilities will refurbish 770 coal-fired units, 172 gas-fired units, and 74 oil-fired units between now and 2015.
A PennWell Research market study found from Oct. 1, 1997 to Sept. 30, 2000, electric utilities in the United States and Canada are planning to conduct 613 conventional steam maintenance outages valued at about $828 million (see Table 1). The average budget for units less than 50 MW is approximately $574,000. Units with generating capacities of 500 MW or more have average maintenance budgets of $1.4 million.
Refurbishment is defined as the upgrading of equipment for better efficiency. This requires capital spending averaging $260 per kW, offering considerable cost savings in many cases when compared to buying new capacity. For example, EEI cites the cost to construct a new gas-fired advanced combined-cycle plant at about $459 per kW; gas/oil steam turbine plant at $992 per kW; and $1,080 per kW for a new scrubbed coal plant (a typical coal plant cost about $400 per kW to build in the mid-1970s).
T&D stakes its claim
Utility expenditure patterns show shifts that are projected to continue. Utility operating companies are concentrating their resources on transmission and distribution (T&D) for expansion and upgrading. Unregulated subsidiaries, however, are building peaking generation plants.
In 1997, electric utility construction work in progress was $11.1 billion, down from $11.4 billion in 1996 and $18 billion in 1993, according to EIA. In real numbers, adjusted for inflation, EEI reported construction expenditures decreased 47 percent over the past 10 years.
Investor-owned utilities (IOUs) projected total electric plant expenditures of $61 billion from 1998 to 2000. The forecast plant expenditures for 2000 are projected to be at the lowest level since 1976.
Industry construction expenditures from 1998 to 2000 will focus on T&D, nuclear plant maintenance, and improved technology for electric power systems (see Table 2).
In 1997, T&D expenditures were $11.4 billion, an increase of 8.6 percent over 1996, reported EEI. T&D expenditures comprised 56 percent of total electric plant construction-the highest portion in the past 25 years.
Transmission lines are being constructed to connect areas to more distant, cheaper capacity resources. The North American Electric Reliability Council forecast an addition of 9,000 miles to the existing 240,000 miles of transmission lines from 1996 to 2005.
Distribution expenditures increased by about $340 million between 1996 and 1997 and are expected to remain at the same level in 1998.
Over the past 10 years, according to EEI, generation as a percent of total plant expenditures decreased 26 percent. Utilities spent about $5.5 billion on total generating plant expenditures in 1997, compared to $5.9 billion in 1996. This decline was due to several factors: a decreased requirement for large base load capacity nationwide; mergers resulting in economies of scale; and IOUs building smaller plants for peaking needs.
Coal-fired generating facilities expenditures decreased 26 percent to $2 billion in 1997. EEI said utilities forecast continued decreases in these spending levels in the 1998-2000 period, due to environmental concerns and technological improvements in other types of generating plants.
Tollgate for compliance
Although companies are reducing their coal capacity additions to comply with the Clean Air Act Amendment of 1990 (CAAA) regulations on SO2 and NO2 emissions, preparation for Phase 2 in 2000 calls for additional environmental expenditures. EEI reported a 43 percent increase in forecast 1998 CAAA expenditures compared to 1997`s $201 million.
Compliance doesn`t come cheaply. Phase 1 affected units achieved 100 percent SO2 compliance through banked allowances and fuel switching. Phase 2, with its 8.95 million ton per year cap, will require additional scrubber retrofits. As banked credits are depleted, Electric Power Research Institute estimated retrofit capital costs around $100 per kW will be necessary to justify large flue-gas desulfurization investments to be competitive with current SO2 allowance prices of $150 per ton.
NOx regulations (CAAA and National Ambient Air Quality Standards) will require large capital outlays in the next 10 years. The McIlvaine Co., a utility consulting firm, reported that annual orders for low-NOx burners, selective catalytic (SCR) and selective non-catalytic reduction systems, reburn systems, instrumentation and controls, catalysts, and chemicals for NOx reduction will expand to $2 billion per year within 10 years. For example, annual orders for SCR systems are projected to pass the $1 billion mark by 2006, while catalyst and ammonia purchases will reach $280 million and $100 million, respectively.
Illustrating the types of decisions being made to meet compliance guidelines, Illinois Power (IP) plans to switch to Wyoming`s Powder River Basin low-sulfur coal by the end of next year for its southern Illinois Hennepin and Baldwin plants. IP burned about five million tons of Illinois coal in these power plants. IP said installing scrubbers would have cost more than three times what it will cost to switch to Wyoming coal.
IP met Phase 1 of CAAA requirements by purchasing SO2 allowances, which made possible the continued use of Illinois coal for five years. However, as environmental regulations become more stringent, IP`s vice president Richard W. Eimer Jr. said switching fuel is the only realistic alternative. “We`ve looked at all the options,” he said. “This was a business decision that we had to make after looking at the economic realities.”
With the switch to Wyoming coal, SO2 emissions at the two stations will drop nearly tenfold, from more than 300,000 tons per year to about 38,000 tons per year.
At the Baldwin Station, the company expects to invest more than $200 million in pollution control equipment over the next 18 months. Eimer said, “We`re upgrading the plant as a low-polluting, modern generating station. The changes we`re making will enable our electricity generating system to meet current and anticipated future environmental requirements.”
Changes in coal unloading facilities, precipitators and boilers will equip the Baldwin Station to use the low-sulfur coal. The company is also installing an SCR system to reduce NOx emissions by 65 percent.
Overseas investments buoy earnings
International demand for electricity is projected to grow at an annual rate of 6.5 percent compared to the estimated U.S. growth of 1.5 percent, according to EEI. U.S. utilities and their affiliated power subsidiaries recognized and seized opportunities presented in global markets (see Figure 2).
Global economic uncertainty and weak financial markets in Asia and Latin America temporarily dampened the attractiveness of these investments. Nevertheless, optimism prevails in long-term assessment of prospects.
Fred Cohen, managing director, PricewaterhouseCoopers LLP`s energy risk management practice, said there is a keen interest in international business. Electric utilities are less inclined to sprinkle investments across projects in which they hold a minority role; they are instead directing capital to segments of the industry where their core competencies lie. He said, “The volume of international investment is more focused in the way it`s being executed. There is greater diversification with utilities taking more of a portfolio approach.”
International profitability is often due to increased efficiencies investors bring. System changes in developing countries often mean significant earnings opportunities. According to the World Bank, 40 percent of the generating capacity, on average, in developing countries is out of service at any one time compared to 15 percent in the United States. U.S. transmission system line losses are about 7 percent, but typically reach 15 percent and higher for international systems.
EEI reported that almost 50 percent of diversified assets of U.S. utilities are now located overseas. Several IOUs now have more customers outside of the United States than they do in the United States, due to acquisition of privatized companies. The United Kingdom and Australia were fertile grounds for acquisitions by U.S. IOUs through privatization efforts over the past four years.
Privatization continues in South America, Europe and Asia; however, foreign governments are now relinquishing less control to buyers. More agreements retain the government`s involvement, including concession agreements, shareholder agreements, or long-term purchased power agreements.
Recently announced international deals included:
– UtiliCorp United announced that Power New Zealand (PNZ), in which it holds a 78.6 percent ownership interest, agreed to transactions that will make PNZ that country`s largest operator of electric distribution lines. PNZ will purchase the assets of TransAlta`s lines business, and in turn will sell to TransAlta its own retail electric business. PNZ also agreed to purchase the electric lines assets of neighboring power company TrustPower Ltd. Robert K. Green, UtiliCorp`s president and chief operating officer and chairman of PNZ, said, “The new environment in New Zealand`s electric industry offers many commercial opportunities. However, we see achieving scale as the best way to begin delivering benefits to both consumers and shareholders.” He noted that UtiliCorp`s added investment in PNZ plus the TransAlta and TrustPower transactions comes to a total of about $700 million in new assets brought under its control in New Zealand.
– Central and South West Corp.`s subsidiary, CSW International Inc., and Scottish Power Plc announced a $320 million deal to build a 400 MW combined- cycle gas turbine power station at Shoreham Harbor in West Sussex, England.
– AEP Resources Inc., a subsidiary of American Electric Power (AEP), agreed to buy CitiPower, an electric power distributor in Melbourne, Australia, for $1.1 billion from Entergy Corp. Entergy bought CitiPower in 1996, but is now shifting its focus to international power development, nuclear power operations, power marketing and trading, and power generation to increase its profitability. AEP Resources already owns 50 percent of Yorkshire Electricity Group, a regional electric company in the United Kingdom; 70 percent of a two-unit power plant in
Nanyang City, Henan Province, China; and 20 percent of Pacific Hydro, an Australian company that develops and operates hydroelectric facilities. Entergy also sold London Electricity, a regional power distribution company in London, to Electricite de France, France`s national electrical utility, for $3.18 billion.
– Enron Corp. made a bid for a 2,000 MW liquefied natural gas (LNG) power project in India`s southern Tamil Nadu state. Enron is already involved with a power plant project in the western Maharashtra state. Dabhol Power Co., a joint venture in which Enron has a majority share, is completing the first phase of the Dabhol 826 MW power plant. The company plans a $1.8 billion, 2,450 MW LNG-based power plant in the second phase of the project.
– CMS Energy Corp. plans to invest about $800 million in Brazil within two years for gas transport and distribution, electricity generation and distribution, and oil and gas exploration and production. CMS projects a total investment of about $1.2 billion in Argentina, Bolivia, Brazil, Chile and Peru during this period. It is also considering the possibility of building electric transmission lines and tapping the electricity marketing business between Argentina and Brazil. A CMS-led group in September won the bidding for the privatization of the SENE power firm on Venezuela`s Margarita island. CMS also owns 90 percent of a $250 million, 520 MW project of Centrales Termicas Mendoza SA.
Within U.S. borders, mergers, acquisitions and divestitures continue. Several large utilities have embarked on the strategy of becoming national energy companies. As the top competitors gain economies of scale in generation, anyone else who wants to compete will have to keep up and purchase more generation, or else they will be at a disadvantage.
Many utility and industry experts predict that consolidation in power generation will leave only about 15 to 20 national electric suppliers by 2004.
Even though international investments carry their own set of risks (political, regulatory, and currency), the growth of the electricity sector worldwide is several times its growth in the United States. Therefore, U.S. utilities that invest their expertise and capital in those burgeoning markets have the potential to achieve faster earnings growth-and those earnings may translate into balance sheets strong enough for a utility to be one of the last left standing.
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