PRICING

Eric Hirst, is a consultant in electric-industry restructuring in Oak Ridge, TN. This column is based on "Retail-Load participation in Competitive Wholesale Electricity Markets," a study he co-authored with Brendan Kirby. Published in January, it was prepared for Edison Electric Institute and the Project for Sustainable FERC (Federal Energy Regulatory Commission) Energy Policy. For more information on the study, contact Russell Tucker, manager of Wholesale Market Policy at Edison Electric Institute, rtucker@eei.org—202/508-5519.

Real-Time Pricing Could Tame The Wholesale Market

Policymakers should encourage electric customers to participate in the new types of demand-response programs that would induce consumers, through market incentives, to cut power consumption in response to prices that vary from hour to hour. Such programs save money for consumers and help system operators maintain reliability. But they also affect the entire market: Such cuts could dramatically reduce price spikes during period of peak demand on regional electric systems, because even small declines in demand at such times have a significant effect on price.

Indeed, if even a small fraction of retail electric customers participate in bulk-power markets, along with power suppliers, large spikes in the wholesale price of electric power, such as those that plagued markets in California and New York last summer, can be flattened. [This report does not address the situation in California that has occurred since then.]

But for this to happen, retail consumers must face real-time electricity prices. The problem today is that consumers are indifferent to electricity prices or have no interest in cutting power use during price spikes, primarily because state public utility commissions insulate them from price volatility. Fundamentally, commissions must decide whether they believe in competition or believe they must protect retail customers from such markets, because they can't do both.



The Real-time Reduction
Figure 1 illustrates the current disconnect between wholesale and retail markets. The graph (based on the generator offers to the California Power Exchange in June 2000 and similar to the curves also seen in the three northeastern independent system operators—ISOs) shows a typical supply curve, in which increasing amounts of generating capacity are offered at higher and higher prices. The graph also shows two possible consumer demand curves during an on-peak period. The vertical curve indicates complete consumer insensitivity to changes in electricity prices. This insensitivity is a consequence of the current status of electricity restructuring in which the vast majority of consumers, regardless of whether they have chosen another supplier, face time-invariant electricity prices.

The second demand curve illustrates the effects of price sensitivity during peak periods. If consumers are insulated from time-varying prices, the market, at 29 gigawatts (GW), clears at a price of $550 per megawatt-hour (MWH). However, if some consumers during this high-demand hour are even modestly sensitive to prices, the market clears at 27.5 GW at a price of $250/MWH. In other words, a 5-percent reduction in peak demand reduces prices by more than 50 percent! In this example, customers as a whole, not just those who respond to price, save almost $9 million an hour. In addition, such responses reduce price volatility.

Because large consumers account for such a large percent of electricity use, small consumers need not participate in demand-reduction programs. In other words, your grandmother need not worry about responding to real-time pricing. Indeed, not much participation is needed to realize large benefits. If even a small fraction (say, 20 percent) of retail load participates and even if this load exhibits a very low price elasticity (say, 0.1), the effects on price spikes, price volatility, market-power abuses, mix of new generation constructed, and overall electricity costs will be substantial.

Thus, federal and state regulators need not worry that offering financial incentives to large loads to participate will leave smaller ones holding the bag. That's because all ratepayers benefit when a few of them help flatten wholesale price spikes.

Dynamic Pricing
To acclimatize themselves to the world of dynamic pricing, customers must begin evaluating retail electricity purchases on an hourly basis. To that end, we urge adoption of a new breed of demand-response programs which, unlike traditional demand-side management programs run by utilities under regulatory oversight, are market-driven and emphasize the timing, much more than the magnitude, of electricity use. Customers are induced to participate because of the benefits, rather than penalized for noncompliance.

There are several examples of such programs:

• dynamic pricing programs, such as the kind offered by Georgia Power to about 1,600 industrial and commercial customers representing 5,000 MW of load; and
• shared-saving load-reduction programs (already in place at several utilities, including Portland General Electric, GPU Energy, and Wisconsin Electric), in which the supplier agrees to share with the customer some of the savings that occur when the customer reduces consumption during periods when prices are spiking.

Several ISOs have experimented with limited regional load management programs. Last summer, the California ISO operated a "demand relief program," in which about 65 MW of load could be shed whenever the ISO declared a Stage 1 emergency (which occurs when operating reserves are expected to fall below 7 percent of daily peak demand). The program was invoked 20 times during the summer.

The PJM Interconnection and ISO New England also deployed small-scale, voluntary pilot load-response programs last summer, though they were never used because summer temperatures in those regions were unseasonably mild. All three ISOs, as well as the New York ISO, plan to run larger programs in summer 2001.

In competitive electricity markets, load-serving entities (LSEs, a group comprising aggregators, energy-service providers, energy-service companies, scheduling coordinators, and marketing affiliates of distribution utilities) are the logical candidates to offer such pricing options. The entities could then bid price-responsive demand into ISO/power exchange day-ahead, hour-ahead, or real-time markets. But few LSEs offer pricing options today. The focus of LSE marketing efforts seems to be on building market share through price discounts.

Commissions Can Help
Before LSEs can adopt dynamic pricing programs, however, state regulatory commissions must rethink their decisions on standard-offer requirements (See Another Perspective in this issue) and competition for metering and related services. LSEs cite the tremendous regulatory uncertainty and obstacles related to standard-offer service, provider-of-last-resort requirements, the status of incumbent utilities, stranded-cost recovery, and ownership and access to metering and communications systems.

Commissions can play powerful roles in encouraging participation by customers. If commissions require local utilities to stand ready to serve any and all customers at a standard-offer rate and if that rate includes a discount, the opportunity, both for other suppliers and consumers, to have retail loads participate in wholesale markets is greatly blunted. As the stakeholders in California are realizing, any such discount, relative to the market price of generation, will ultimately be paid for either by utility shareholders or, more likely, by customers at a later time. There is no free lunch! Other suppliers will have great difficulty competing with an unfairly discounted price. Equally important, customers will have no incentive to accept the risks associated with dynamic pricing.

Regulatory commissions, as well as consumers, need to recognize that the traditional regulated electricity price includes two distinct components:

• the electricity commodity, i.e., the kilowatt-hours that customers consume whenever they want to in whatever quantities they choose; and
• an insurance policy that protects consumers from electricity price volatility.

If commissions establish a standard offer that explicitly recognizes those two components, then the entity providing that standard offer can earn a reasonable return, and customers will face a reasonable price, neither too high nor too low. (If the standard-offer price is too high, customers will find better deals elsewhere; if the price is too low, customers will almost surely be required to repay these costs at a later time.) In such situations, customers will have appropriate incentives to accept some of the risk premium in exchange for a lower electricity price. And alternative suppliers will have appropriate incentives to offer such price/risk combinations.

If the utility is required to provide standard-offer service and has a fuel- and purchase-power-adjustment clause, it has little incentive to manage price or quantity risks. Increases in electricity costs are passed through to customers, although with some delay. In such situations, customers face strong incentives to manage their electricity use; however, faced with time-invariant prices and monthly bills, customers have virtually no ability to respond to these temporal changes. This is the situation that electricity consumers in San Diego faced last summer.

On the other hand, if the utility is not able to recover fully its wholesale power costs and must provide standard-offer service, it temporarily faces all those quantity and price risks. In such cases, the utility will likely request a rate increase from the commission, and customers will eventually pay these costs. Correspondingly, retail customers face none of these risks in the short term. In this case, commissions should recognize the risk-management role that the utility plays and compensate it accordingly. Regulatory delays in permitting Pacific Gas & Electric and Southern California Edison to raise rates forced the companies into severe financial straits. Ultimately, retail consumers will repay the utilities for their wholesale power purchases, or the utilities will go bankrupt. Again, there is no free lunch.

Also, LSEs are not sure who owns and who has rights to the metering and communication infrastructure required to implement such programs, or to the data those programs produce. In many states, the regulatory commission has not yet determined whether these functions are to be provided exclusively by the distribution utility, subject to competition, or provided by any entity other than the utility. Until the rights and responsibilities for meters, meter reading, communications, and data are resolved, LSEs are reluctant to invest in the equipment.

Another barrier is the "immature nature" of the metering, communications, computing, and control technologies needed to realize these benefits. Regional transmission organizations should work with LSEs and other load aggregators to simplify their data and communications requirements. These regional entities should specify clearly the minimum metering and telemetry requirements consistent with reliability standards.

The convergence of wholesale competition, retail competition, and improved metering and communication technologies should greatly expand the type and magnitude of price-responsive demand. Encouraging retail customers to respond to dynamic prices will improve economic efficiency, discipline market power, improve reliability, and reduce the need to build new generation and transmission facilities.

© 2008 Edison Electric Institute