The electric industry hasn't seen so much upheaval since Thomas Edison threw the switch at the Pearl Street Station. Full retail access to competitive markets in generation and supply will challenge traditional ways of doing business. But no change will prove more dramatic for electric utilities than setting a competitive price (em that most fundamental of business decisions.
In anticipation of competition, utilities have been experimenting to discern what forms of the "product" (em electric power (em customers might want, and at what prices. One such experiment is real-time pricing.
Real-time pricing (RTP) is important; it can help convey the true cost of power in an industry whose costs vary hour by hour. Historically, wholesale electric markets in the U.S. have not operated on the basis of market-clearing prices, i.e., prices equal to marginal costs. Retail markets have set prices at average costs, calculated without time differentiation. For their inter-company transactions, utilities have used some form of split-savings approach, but these transactions serve as a crude proxy for competition. Recently, bilateral contracts between utilities have been set in reference to marginal costs with increasingly shorter time horizons. These contracts better reflect the marginal costs of sellers in bulk power markets.
As efficient, hourly signals, real-time prices can yield enormous savings for consumers. In restructured power markets, they will also support trading of risk-management services for customers seeking fixed or less volatile prices or other customized pricing options. Beyond consumer savings, RTP will help defer capacity needs and reduce peak loads for individual utilities. Eventually, these benefits might be seen on a regional level. In short, real-time prices built from competitive spot prices will provide the raw material for pricing and service packages (em the primary weapons of war in tomorrow's energy services market.
Early Rationale (em
a Proxy for Spot Markets
Today, many view a competitive power exchange, or "PX," as a cornerstone for electric restructuring. The typical PX would set spot prices that clear markets and ration power among competing users. It would offer price signals to aid capacity investments in new generation and load management. To offer some perspective, the history of real-time pricing programs in the U.S. can be thought of as a series of attempts by individual utilities to mimic the future operation of a PX (em to transmit prices that come closer to tracking marginal costs.
The bidding systems now contemplated by some power pools should yield spot prices that, in part, will reflect short-run marginal costs. Utilities' own systems already use short-run marginal costs as a basis for efficient dispatch of units in order to meet changes in customer demand. For the marginal-energy-cost component, present-day RTP starts with "system lambda," the short-run cost of power from the incremental unit in the dispatch order. To attain a complete proxy for a spot-market price, a second "capacity-rationing" or "scarcity-value" price component is added to system lambda to produce the hourly price.
We will not know how well current, real-time pricing programs have anticipated the future spot market until power markets emerge with independent system operators. Yet, it is a good bet the spot market will set at least two sets of prices (em a 24-hour-ahead price for generation scheduling and transmission purposes and an hourly price on the day of dispatch for real-time system balancing. The 24-hour "forward" price represents a workable compromise between the instantaneous cost changes system operators deal with, and the price signals consumers need to make intelligent reactions to them.
All existing RTP programs have provided participants with a 24-hour-ahead forecast of prices; a few have also used hour-ahead pricing. It is conceivable that future spot markets could add other methods of rationing power dynamically, such as setting up a priority-service system (em an advanced form of interruptible pricing. One example is the priority service methodology developed by the Electric Power Research Institute (EPRI) %n1%n. Our observations apply to all these alternatives.
Current Applications (em
Two Types of Programs
Thirty nine U.S. utilities have offered a form of an RTP program as of 1996. We surveyed twenty-one %n2%n (see figure 1). Most of the RTP programs are experimental and limit the number and the size of participants. For example, only customers with at least 5 MW of maximum demand are qualified to participate in Virginia Electric Power's RTP program, which means most participants are large industrial or commercial customers.
Five of 21 utilities surveyed have moved from the pilot stage to expanded, permanent RTP programs. All of these utilities are located in the Southeastern Electric Reliability Council. Their RTP load accounted for at least 5 percent of SERC's regional peak demand. Georgia Power Co., has the largest RTP program, with about 1,000 participants and a load under RTP that equals 20 percent of its system peak.
Regulated RTP programs are tariff structures that offer electricity prices reflecting the hourly profile of the electric utility's system costs. Some programs are approaching a decade of experience. RTP programs have been offered across all customer classes, with varying success in terms of recruiting customers and allowing them to use electricity in more efficient ways.
As voluntary alternatives to tariffs, but still regulated, RTP programs must meet a "revenue-neutrality" requirement, which means customers choosing real-time pricing should not see immediate changes in their bills. Changes should not be noticed until, in response to the new RTP price signal, customers adjust their pattern of energy consumption. The approach to achieving revenue neutrality broadly divides real-time pricing programs into two groups: one-part pricing and two-part pricing.
One-Part Programs. One-part pricing programs use the hourly price signal to achieve revenue neutrality. The hourly price starts from a chosen "surrogate" for the efficient spot market price and is adjusted with an additive or multiplicative factor, so that, on an annual average, the real-time price is equivalent to the tariff rates, generally on a customer-class basis. By construction, this method of achieving revenue neutrality deliberately distorts the price signal from the pure spot price surrogate, generally in the upward direction. This adjustment mechanism reduces the ability of consumers to compare their consumption hour by hour to the spot price. proxy and thus may reduce economic efficiency.
Two-Part Programs. The second type of program uses a two-part pricing approach that allows customers to perform an hour-by-hour usage comparison. Developed by the Niagara Mohawk Power Company and Georgia Power, the program's per-hour price is based exactly on the surrogate spot price. The customer is always exposed to the RTP prices for its full demand. Revenue neutrality is achieved through an "access charge" that customers incur in addition to
the real-time price. This non-distorting, lump-sum payment is calculated as the customer's base load (CBL, the customer's load profile over the prior year), charged at the usual tariff. This "vision" of the RTP contract serves as an effective marketing tool where real-time prices are expected to be quite low for the vast majority of hours each year.
The take-or-pay nature of the access charge gives the two-part approach the look of a derivative contract. It represents a contractual offer by the utility to charge last year's load at tariff rates, and, over the course of the year, either to buy back or supplement that obligation at the RTP rates. The lump sum payment thus acts as a hedge against the forecasted day-ahead prices. In this sense, revenue-neutral, two-part RTP programs implicitly bundle risk management into their pricing structures.
Utility Experience (em
Quantifying Effects on Utility Operations and Investments
In principle, this mimicking of electricity spot pricing by RTP
programs encourages customers to make efficient choices in their consumption. A properly designed RTP program can induce customers to reduce loads during high-cost hours, and increase load during low-cost hours, which can improve power system reliability and defer the cost of adding new capacity.
The important question is: How do customers respond to RTP, and how does that load response affect system peak for a specific utility or the region as a whole? Short-run forecasters and future power marketers should remain wary of neglecting responses to high spot prices. Conversely, RTP likely enhances revenue in periods of low prices; entrepreneurs building future merchant power plants may benefit from increased sales during these periods.
The evidence of customer response to price can be shown at Georgia Power, and Pacific Gas and Electric Co. Georgia Power's RTP customers reduced their load between 5 percent and 10 percent when electricity prices ranged between 5 cents and 10 cents per kilowatt-hour, and reduced load 10 percent or more when the price rose to 25 cents per kWh. Assuming the midpoint of a 7.5-percent response, RTP customers, during high-price hours, helped reduce Georgia Power's system peak by 1.5 percent %n3%n.
The load response at Georgia Power appears consistent with PG&E's RTP program, which is among the oldest RTP programs in the country. PG&E reported a 12-percent load reduction on "Load Management Price Signal Days" in 1994 %n4%n. While these amounts are not large in comparison to present regional loads, they represent extremely large savings opportunities for some suppliers and customers.
Consumer Reality (em
Dealing With Risk
In the U.S., regulated RTP programs generally do not address the broad spectrum of customer needs. In attempting to extend RTP program participation to medium-sized industrial and commercial customers, utility representatives often encounter difficulties. Customers might decide RTP pricing is too risky. For example, what happens, on that rare but fateful day when the price of a kilowatt-hour rises during some hours to
50 or 75 cents (em more than 10 times the tariffed rate? So, how do regulated RTP experiments deal with price risk and the risk preferences of customers?
While differences between one- and two-part RTP programs are important, the two plans are similar in one respect: They both leave the customer to bear the full risk of price variability. Economics dictates that additional risk will be born only if expected returns are higher. Hence, the most popular RTP programs have proven to be those that have offered the greatest cost savings for a given level of price risk. When developing a marketing approach to appeal to business managers and investors, one does not want to offer only the polar extremes of no-risk or high-risk. Customers will look for options in which risk can be managed by choosing the level and type of risks to match their risk-management skills and preferences.
Technology and Equipment (em
Winners and Losers
How well customers can take advantage of innovative rate forms, particularly those that vary over time, may depend on their capability to control equipment energy use to respond to changing or forecasted prices without sacrificing comfort and convenience. Equipment vendors that can help a customer meet this requirement will be in demand. In addition to equipment, control algorithms and their implementation into soft- or firm-ware really will make the difference. This may spawn two separate industries: one that provides control hardware and another specializing in control algorithms.
The smartest of these systems not only will control equipment, but also will provide price and bill forecasts, and bill computation. The
systems will provide inputs to the customer's financial and managerial accounting systems and early warnings about equipment maintenance problems.
Vendors could aggressively market such products by taking on the potential price and quantity risk directly. For example, energy service companies have offered so-called "chauffage" contracts (em fixed-cost contracts for the provision of heat and light, subject to standards of comfort and convenience, among others. Vendors of control equipment could take a similar approach, and offer a product that bundles price and quality risk management in a single package. This strategy would appeal to customers who want to go beyond price-hedging capabilities that contract for differences (em like derivatives offer.
Certain types of equipment are natural beneficiaries of pricing that is tied to fluctuating wholesale spot prices. Cool-storage technology for commercial buildings offers a straightforward example. Economical energy storage in any form (em thermal, electrical, mechanical (em is also attractive. While flywheel technologies have yet to develop commercially, their future potential should not be overlooked. Fuel cells and distributed renewable technologies will likewise contribute additional options.
Another group that will benefit from RTP is "kilowatt-hour repackagers." Beyond the near-certainty that the wires businesses (em the distribution and transmission companies (em will fall under some form of incentive or cost-of-service regulation, little else is clear. It is certain, however, that companies can be winners if they provide kilowatt-hours in the flavors that customers want.
Suppliers in the United Kingdom, which has had open access since 1990, show attempts at successful kilowatt-hour repackaging. Suppliers buy their power from a national spot market or from their own resources and repackage it for retail sale. Each spring, the majority of annual contracts expires and a competitive bidding process is used to re-sign customers. This process has provided a real laboratory in which preferred contract types evolve from open competition.
Pool-based contracts, which take the spot-market price (half-hourly in this case) and bill the customer at that price plus a surcharge, may have appeared more popular in the early years because many suppliers based fixed-price bids on overly bullish forecasts. Large retail suppliers do not actively promote this type of contract because of its thin profit margin. Normally, the pure, spot-market, high-volatility pricing option has held limited appeal for customers who are inflexible in their daily or seasonal operating regimes.
There are several popular contracts, which differ based on the following variables: the portion of the year bundled; the number of interruptible features; a use-demand charge (to cover access charges for wholesale transmission grid); and how the price and quantity risk is parceled out between the parties. Over time, the market has become segmented to provide customers with preferred options.
In fact, future restructured U.S. power markets will likely offer similar risk-management alternatives. Intermediate risk positions will be possible, using the tools already available for the pricing of financial options, futures and
forward contracts. Consumers can then determine what portion of the expected savings should be traded for risk avoidance.
In the long run, however, three distinct ideas should emerge that will govern the way that kWh repackagers develop a successful marketing strategy. First, unbundling is not likely to be the most successful retail route. The experience of other deregulated industries shows that any initial thrust into unbundling and separate competitive pricing is followed quickly by rebundling particular combinations of components into convenient, full-service retail products. Customers likely will not want to deal separately with generation suppliers, risk managers, and access providers, among others. Staying close to your customers and being prepared to offer the options they need marks the first key to success.
Second, although customers want choice, they do not want too many choices. A small number of well-designed packages that can be delivered and backed up faultlessly serves as a worthy goal for a supplier in the retail, open-access market. Product bundles must be constructed in a strategic manner. Not all services are equally desired by customers nor are they equally profitable. Bundling permits repackagers to combine the features that customers want the most and those which are less desired in a way that bundle as a whole is more profitable than when offered separately. Thus, a detailed understanding of the desirability of electric-service components and the cost of offering them will prove essential.
Communication Is Key
When the hourly price schedules for electricity change every day, communication between customers and utilities is crucial. There must be verification that customers did receive notification of the next day's prices at the agreed-upon time. Some programs provide the information via facsimile; others use electronic mail. Pagers are used to signal plant managers about significant differences in the hour-ahead and day-ahead forecasts.
A more sophisticated RTP communication system can be provided with computer software that stores both hourly prices and usage information. This software is a tool customers can use to simulate strategies for reacting to high- and low-price signals with changes in plant operations or building energy management systems. However, such communication systems are time consuming to set up and can require a high level of ongoing support.
The key relationship is the interaction between the utility account representatives and customers' operating personnel. It is here that RTP will produce a better understanding of basic energy needs. In the competitive world of the future, this relationship may well yield a reward greater than the deferral of new capacity additions (em the original motivation for real-time pricing. t
Phil Hanser and Joe Wharton are senior consultants in the Cambridge, Mass. office of The Brattle Group. Peter Fox-Penner, is director of the firm's Washington office. Phil Hanser previously managed the Demand-Side Management Program at EPRI, Joe Wharton managed the RTP program of the New England Electric System, and Peter Fox-Penner is author of PUR Publishing's forthcoming Electric Utility Restructuring: A Guide to the Competitive Era.
1Chao, Hung-Po, Shmuel Oren, Stephen Smith, and Robert Wilson, "Priority Service: Unbundling the Quality Attributes of Electric Power," Report EA-4851, Palo Alto, Ca: Electric Power Research Institute, 1986.
2Those surveyed included Alabama Power Co., Baltimore Gas & Electric, Consolidated Edison Co., Duke Power, Empire District, Florida Power & Light, Georgia Power, Gulf Power, Houston Lighting & Power Co., Illinois Power, Indiana Michigan Power Co., LA Department of Water & Power, Massachusetts Electric, Niagara Mohawk, Northern Indiana Public Service, Oglethorpe Power, Oklahoma Gas & Electric, Pacific Gas & Electric, South Carolina Electric & Gas, Tennessee Valley Authority, and Virginia Electric and Power.
31.5%=(20%x7.5%), where 20 percent is Georgia Power's RTP load as a percentage of its system peak.
4Pacific Gas & Electric, Real-Time Pricing Program 1995 Annual Report, Executive Summary, p. 1
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