Electricity Restructuring Update
Increasing Efficiencies and Customer Choice
are Integral to the Market Transition
by Kenneth L. Lay
Chairman and CEO
Enron Corp.
Throughout our world, competition is the primary driver of significant market restructuring activities that are boosting economic growth and expansion. In Europe and North America, for example, the move toward greater electricity market restructuring is gaining momentum from substantial evidence that competition:
• Helps individual countries strengthen their economies and establish formidable global trading positions;
• Enables global energy companies to grow their businesses by expanding into markets with significant fuel requirements and energy efficiency needs; and,
• Delivers the attractive prices, innovative products and enhanced services that were slow to emerge in the rigid, regulated monopoly structure.
As we assess the progress of industry restructuring, the inconsistency of the liberalization process illustrates a wide girth of conflicting industry viewpoints. Early proponents recognize the numerous consumer and economic benefits that competition provides, while objectors are reluctant to cast aside their comfortable monopoly existence in order to implement the cost cutting, asset divestiture, new product development and workforce development activities that are essential to participating in the competitive market.
Regardless of the speed of market restructuring, the competitive electricity industry promises many more new products and services than are presently available. These potential products include 'green' kilowatts, weather-sensitive services, 'talking' digital meters that interact with users' PC control centers and smarter thermostats, to name a few.
As we near the 21st century, energy customers in North America and Europe can look forward to greater flexibility and reliability of market structures, competitive prices, increased efficiencies in power production, generation and delivery, and cleaner environments. The magnitude of change in these restructuring markets is immense, and the opportunities for energy companies to benefit by creating products and services that help customers are extraordinary.
Industry Restructuring in the U.S.
In 1997, the U.S. Energy Information Administration of the Department of Energy (DOE) estimated that restructuring of the U.S. electric industry would result in price savings of 6 to 13 percent within two years of inception and longer-term savings of 8 to 24 percent, depending on the intensity of competition.
Consistent with that analysis, many U.S. industry analysts such as the Brookings Institute have concurred that a fully competitive electricity supply industry will be more efficient and, as a result, will lower consumer electricity prices by 10 to 30 percent.
Industry restructuring in the U.S. is characterized by the sell-off of unbundled generating assets in select states, as well as reduced government involvement in the electric utility business. About $89 billion, or 40 percent of the $220 billion annual U.S. electricity market, is attributed to the 18 states that are most actively involved in the restructuring of their electricity markets (i.e., they have passed electricity deregulation laws or are deregulating under state Public Utility Commission orders).
Across the U.S., a wide variety of changes are underway. While all states are addressing transition cost recovery issues and cost reduction concerns, 4 states - California, Rhode Island, Massachusetts and New Hampshire - will achieve full retail competition in 1998.
The U.S. Federal Energy Regulatory Commission is leading deregulation efforts on the wholesale level, and the various state regulatory agencies and legislatures are the primary drivers of retail competition.
Highlights of Restructuring Activities in North America
California. California opened its market on April 1, 1998 for all customer classes to choose their supplier of energy and associated metering and billing services. Few savings can be offered to customers at present until the utilities' stranded costs are recovered under the Competitive Transition Cost, to be complete by December 2001. California also implemented an Independent System Operator which controls the transmission system and operates a market for ancillary services. The utilities in California have also implemented the Power Exchange, through which they sell and buy their power.
Many California-based utility affiliates are also actively buying generation assets in other states such as Texas and New York and across New England.
Arizona. Arizona's deregulation order provides for 20 percent of the market to open in January of 1999, and 100 percent in January 2001. This process has not been without its difficulties. While the Arizona Corporation Commission, as an independent agency, is attempting to balance the interests of all the stakeholders in opening the markets of the investor owned utilities, Salt River Project has the authority to write the rules for its own
competitive and monopoly service.
Pennsylvania. As the PUC completes the task of opening electricity markets to competition, the Pennsylvania model outlined in the Philadelphia Electric Company's (PECO) restructuring proceeding will provide customers with an immediate guaranteed 8 percent savings, additional savings from marketplace competition and greater efficiencies from new technologies such as automated metering.
Idaho/Washington. Both states typically have low-cost surplus power. They are moving more slowly toward a deregulated market due to less pressure from their customers while a few of these states' utilities are actively wheeling competitively priced power to supply other states.
Nevada. "Alternative sellers" may begin selling power and other unbundled services in Nevada on December 31, 1999. The Nevada Commission is in the process of establishing rules for licensing, consumer protection, and other issues associated with competition.
Oregon. Oregon, another low-cost power state, is addressing restructuring issues in a number of forums. Enron subsidiary Portland General Electric (PGE) is administering a 50,000 customer pilot to offer choice in Oregon, and has filed with the Oregon PUC to bring choice to 685,000 Oregon customers in the future. At the onset of nationwide electricity deregulation, PGE is maintaining its commitment to service while assisting
with the formation of a competitive electricity market in the Northwest. Its Customer Choice Implementation Proposal was filed with the PUC in December 1997 and the hearing process will commence in September 1998. The Legislature is expected to consider electric restructuring in 1999.
Restructuring Highlights in Other Key States and Canada
Maine. Retail competition becomes effective March 31, 2000.
Illinois. Electricity competition for sales to businesses begins in 1999. Full competition begins in 2002.
Maryland. Certain customers will have the ability to choose their electricity provider in 2000.
Montana. Has passed legislation for electricity deregulation. Large customers currently have choice through a program adopted by the Montana Commission.
Idaho. Has an ongoing industrial consumer pilot program for supplier choice.
Oklahoma. Has enacted restructuring legislation which provides for an interim rate freeze and full competition by July 1, 2002.
New Mexico. Texas - New Mexico Power has voluntarily opened its system to competition, which will be fully implemented in 2000. The Legislature is expected to consider electric restructuring in 1999.
Canada. Markets in several Canadian provinces are restructuring and opening to competition, too. In Ontario, for example, initiatives include the
separation of transmission and generation systems, setting timetables and consistent criteria for distribution restructuring and creating an independent agency to oversee the competitive market.
European Overview
As of February 19, 1999, about 25 percent of the large industrial electricity users across Europe will have the opportunity to change their supplier and shift from regulated tariffs to buying power based on freely negotiated market prices. Finland, Spain, Sweden and the U.K. are liberalized already, and Denmark, Germany and the Netherlands are moving quickly through the liberalization process.
Because fuel type, generation surplus and the presence of independent power producers are influencing factors in the openness of the European electricity markets, the European market overview will be discussed in conjunction with an analysis of these factors.
Power Plant Fuel Use
Electricity use has been increasing about 1.6 percent per year in Europe since 1990, compared to a 2.5 percent per year growth rate in the U.S., according to OECD and DOE data. Today, power plants in Europe generate about 2,850 billion kilowatt hours (BkWh) of power annually, second only to U.S. generation of 3,345 BkWh, according to the Edison Electric Institute.
In the EU, changes in the fossil fuel mix for power generation have resulted in a 0.3 percent per year decrease in the use of solid fuels and a 1 percent per year increase in gas use in power plants since 1990.
In the U.S., natural gas has been a steady replacement for fuel oil in power plants and has been growing at 0.6 percent per year since 1990, according to the 1996 Edison Electric Statistics Yearbook and U.S. DOE data.
Enron forecasts that by 2015, gas use for electricity generation worldwide will grow 4.5 percent per year as electricity competition from more efficient merchant plants intensifies and as more private power producers and utilities choose to build low capital cost gas-fired combined cycle plants. This worldwide growth compares to 2.3 percent per year gas use growth in the U.S. (Fig. 1) and 3.5 percent per year growth in Europe over the same period.
Virtually all of the coal used in the U.S. in 1996, 19.7 quads (Fig. 2), was consumed in power plants, almost three times more than the western European rate of 6.9 quads. As a result, significantly greater efficiencies in U.S. energy consumption and increased dependence on natural gas and renewables will be required to approach the Kyoto global carbon emission targets because of the high CO2 content of emissions from coal combustion. The Kyoto targets stipulate 8 percent and 7 percent reductions for CO2 in Europe and the U.S., respectively, by the year 2010.
Comparing Fuel Uses and Strategies
In Europe, the relative openness of electricity markets varies by country. France and Belgium, which are nuclear power oriented, appear more closed to access but are actively seeking increased power export and asset ownership opportunities outside their own borders. Finland, Norway and Sweden, all oriented toward hydro-based power, are favorably positioned to wheel surplus power to northern tier European industrial markets as those markets open (Fig. 3).
The Netherlands, with a high percentage of gas-fired power plants, and Germany, with a majority of coal-fired power plants, are establishing outward electricity marketing strategies. The current European generation capacity of 626 gigawatts is dominated by the large, privately held utilities in Germany and the slow-to-liberalize generators in France. The combined generation capacity of Germany and France represents 37 percent of total European generation capacity.
The EU power directive stipulates economic parity for member countries in the case of the actual level of electricity market opening, but the EU does not require direct member states to privatize their utilities. Each EU member's liberalization and competitive model is unique. To provide for open access, EU member states may elect one of three policy tools:
• The single buyer model;
• Negotiated third-party access; or,
• Regulated third-party access.
According to the EU directive, these options are expected to achieve equivalent economic results in each of the member states, resulting in a comparable opening up across electricity markets.
Some EU member states have been slow to embrace liberalization, although France, Germany, the Netherlands and Spain have made admirable strides to encompass the basic components of the EU power directive. Belgium, Greece and Ireland requested and obtained delays from the power directive of one, two and one years, respectively.
Delays that are accompanied by strong moves toward efficiency and lower costs may turn out to be acceptable delays after the fact. Delays designed to freeze the status quo, or those that fail to restructure or improve average unit of production costs and increase efficiencies, could cause their electric power entities to suffer non-competitive energy prices and even lose market share once increasingly efficient competitors begin to market kilowatts and new services in their former franchise area.
Cost cutting, job losses, divestiture and employee development are difficult to implement, but protecting wasteful spending practices or inefficient processes of the past is a poor alternative to developing an effective organization and shaping the asset portfolio for future competition.
The primary controls of the EU's speed toward competition and the impact of regulatory change will be the types of services and structures that are created and the changes in transmission tariffs. Low transmission and distribution tariffs encourage rapid development of power trading while high tariffs can be a barrier. All EU member state system operators will need to develop, set in place and publish open access tariffs.
Some tariffs may be able to include public service obligations for low income customers, hardship circumstances and green power costs. The transmission level will reflect, by country, the balance of power between the power companies, the industrial beneficiaries, the new entrants and the government regulators. The EU intent is to assure that eligible EU customers are not hindered by any serious obstacles.
Eligible industrial customers are the predominant drivers of market change and the earliest beneficiaries of savings. A state or utility that tries to protect itself by slowing the process will put its own industrial customers at a disadvantage.
A market in which competing utilities attempt to retain different classes of customers - where some customers are economically disadvantaged due to a lack of choices and options, yet others nearby benefit from improved economics and service levels - stands little chance of surviving. As traditional market economics illustrate, all customers will demand a more efficient energy system and the product and service innovations that naturally evolve in a competitive environment.
Trends Indicate Greater Gas Opportunities
Thermal fuel (coal, gas or oil) is used in 48 percent of European power plants, followed by nuclear, which accounts for 31 percent of the market (1995 data). Gas-fired power plant capacity in Europe is forecast to nearly double, from 8 percent in 1998 to 15 percent by 2010.
On a fuel-use basis today, coal, oil and hydro generate 32, 8 and 20 percent of Europe's power, respectively. Renewables combined represent a 1 percent share. Currently, more private power plant investors are choosing natural gas for power plant fuel because the capital cost of a combined-cycle gas plant is 50 percent less than a coal plant, and a gas combined-cycle plant emits 99 percent less SOx, 81 percent less NOx and 58 percent less CO2 than coal.
In addition, the higher utilization rates of the combined-cycle gas unit (up to 95 percent) offer much greater fuel-to-kilowatt hour efficiency compared to a 75 to 80 percent maximum utilization rate for coal plants, which require more maintenance downtime.
Warmer weather in 1997 and higher hydro levels due to greater snowfalls resulted in a 1.5 percent decrease in gas demand for heat and power in Europe. Still, gas use rose rapidly in Spain, Ireland, Italy and Denmark (Fig. 4). In the U.S., coal is the predominant fuel for power generation at 51 percent (Fig. 5), while the clean alternatives - gas, hydro and renewables combined - supply 27 percent of those fuel needs. In Europe, clean fuels account for 30 percent of power generation.
Electricity Outlook
The low electricity growth rate in most European markets may be a reflection of historically tight regulatory controls and relatively high electricity prices in many markets. In Germany, for example, the fragmented structure of regional monopolies can appear resistant to timely change, but given the extremely high electricity costs in some parts of the country, change is necessary.
German industry and banking groups support draft legislation that is consistent with the EU directives. As industrial rates on the continent decrease from the current 7 to 9 cents per kilowatt hour levels, the newly available revenue can be shifted into the hands of industrials for new investment purposes and for export product and trade development. As a result, industrial competitiveness in Germany, as well as across the European Union region, will improve.
France sees the opportunity to sell power and invest outward into the northern industrial tier of Europe (where electricity costs are often higher and over-capacity exists) but fears losses of market at home - the quid pro quo. Both the U.K. and the Nord Pool offer opportunities for spot transactions in the industrial tier to the north, where industrials may seek partial, lower cost supplies from the Nord Pool.
Spain already has a pool in operation and The Netherlands has a power pool under consideration. The pools will have both generator-sourced players and 'trading skill-based' brokers. As of March 1998, only the Spanish Pool and the Nord Pool allowed bi-lateral trading.
In the U.S. and Europe, contract sales and spot sales are being combined into a comprehensive electricity supply and services portfolio that addresses buyers' specific energy needs. Complexity in energy pricing, terms, options, quantity and service quality are increasing and incumbents are cutting costs to retain market share.
New entrants, meanwhile, are offering competitive prices and new products to win customers - causing downward pressure on prices and increasing the complexity and volatility of the marketplace. The new market environment is now evolving with new products and services such as swaps, spot markets, a futures market for power, new supply interconnect channels, power trading networks and even tolling arrangements, where traders market fuel and receive kilowatt-hours and other fuels in return.
In addition, markets in both Europe and the U.S. are already expanding the type and number of emissions trading transactions to help manage environmental protection risk in the power sector.
Market Efficiency, Strong Skill-Sets Will Benefit Consumers
The benefits of liberalization and competition far outweigh the near-term challenges of restructuring and change. As eligible customers and sellers rebundle delivered power, they are establishing new terms, paths and methods for brokering transportation and delivery. By buying and selling both the commodity and the financial instruments, energy companies are earning margins on their trades and on arbitraging the value of commodities or related assets.
Consumers, likewise, are saving money and reducing excesses in the system by choosing and paying for only the services, production and assets they want to use.
In the competitive market, the development of innovation and new talent, along with the design and use of new automated systems, will assure the optimal management of electric commodity price risk for both industrial companies and marketers. This is especially critical in today's environment - where asset-based profits can rise or fall due to the uneven match of capacity availability and market demand, and the borders that define markets continue to shift and vary over time.
Most importantly, increasing market efficiency in the electric industry, coupled with the skill-based talents of its participants, is adding tremendous value and providing a new growth paradigm in evolving markets on both sides of the Atlantic.
The bottom line is that customers will benefit significantly from these changes, and national economies will reap the dual rewards of competitiveness and innovation in the process. n
Kenneth L. Lay became chairman and chief executive officer of Enron Corp. in 1986 following the merger of Houston Natural Gas and InterNorth, Inc. Previously, he was president of Continental Resources Company before joining Transco Energy Company in 1981 as president, chief operating officer and a director. He joined Houston Natural Gas in June 1984 as chairman and chief executive officer. Mr. Lay was a Phi Beta Kappa graduate in economics from the University of Missouri, where he also received a master's degree in economics. He began his career in 1965 as a corporate economist with Exxon Company, U.S.A. Subsequently, he earned a Ph.D. in economics from the University of Houston. Mr. Lay served as an officer in the U.S. Navy, and held the positions of Technical Assistant to a Commissioner of the Federal Energy Regulatory Commission and Deputy Under Secretary for Energy of the U.S. Department of Interior. Additionally, while in Washington, Mr. Lay was an assistant professor at George Washington University, teaching graduate courses in micro- and macro-economic theory and government-business relations.
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