Competition in the Electric Industry: Emerging Issues, Opportunities, and Risks for Facility Operators (1996)

John L. Jurewitz

Southern California Edison Company

In California, as in the rest of the Union, the traditional structure of the electric utility industry has been typified by local franchises for distribution and retailing, with vertical integration all the way up to generation. Generation was regulated as to price on a cost-of-service basis. Voluntary transmission service was the rule prior to the Energy Policy Act of 1992.

The Energy Policy Act placed every state in a kind of intermediate position, in which there is wholesale competition, with mandatory wholesale transmission. Meanwhile, the Federal Energy Regulatory Commission (FERC) has moved in the past 5 to 10 years toward market-based price regulation for stand-alone generation, as well as utility generation in some circumstances.

The entire nation is likely to move in the next few years, state by state, toward retail competition all the way down to the individual customer. Local distribution franchises, regulated by state commissions, will probably remain. Utilities will undoubtedly face at least partial divestiture of generation assets; in California, utilities are being asked to divest themselves of 50 percent of the fossil generation within their service territories. Both Pacific Gas and Electric and the Southern California Edison Company, within the past five or six weeks, have filed proposed processes for making such partial divestitures.

It is important to recognize that generation is not, in fact, being deregulated. It is regulated by FERC under the Federal Power Act, and it would require an act of Congress to move away from regulation of

generation. What FERC has done instead is to adopt market-based pricing standards.

The significant change we are facing in California, as we move toward mandatory retail transmission access, is to abandon the traditional collective decisions about generation stations and supply sources statewide. Instead, those choices will be made by the market.

The potential benefits of retail access are substantial:

• Greater choice for customers. In the United States choice is of value in and of itself, even if customers happen to do the wrong thing or unlucky things with those choices. We all recognize the value of individual freedom to make our own choices and live with the consequences of those choices.

• Privatizing the risks of resource choices. The private sector, not consumers, will bear the risks of resource choices. U.S. utilities that have high costs generally do so for two main reasons: (a) investments in nuclear generation and (b) contracts entered into with so-called ''qualified facilities" (that is, independent power producers from whom utilities must purchase power pursuant to the Public Utility Regulatory Policies Act of 1978). In California these two factors contribute about equally to the high costs of utilities.

• Depoliticizing resource planning. Resource planning will be depoliticized. In the process that the California Public Utilities Commission has used, the only thing that all could agree on was that the biennial resource planning process, in which regulators would decide ultimately when and how resources would be added, had become unwieldy and politicized. Southern California Edison viewed it as something of a pork barrel for supply-side interests, through which utilities were required to add capacity that was not needed to maintain reliability. With the Commission's adoption of retail access, it has slashed this

Gordian knot by simply letting the market decide what is to be added.

• Reducing long-run costs. Costs will be reduced in the long run. In the short-term, on an instantaneous hour-to-hour and day-to-day basis, electricity markets are relatively efficient. For that reason, I believe we will find, as we get the Power Exchange underway, that spot market prices will not change much. There is already a very active wholesale spot market with many participants in the western United States. The price disparities within and between states are the result of long-term resource commitments, not the result of paying more or less on the spot market. Everyone pays just about the same amount on the spot market from hour to hour. In the long run, costs will be reduced because competition among suppliers will do a better job of holding down costs and stimulating innovation than to continued cost-of-service regulation.

Many concerns have also been raised about retail access:

• Jurisdictional concerns. Serious jurisdictional ambiguities and potential shifts in state and federal authority need to be addressed.

• Increased costs. Some costs may be higher. Transactions costs will certainly be higher; such costs will need to be offset by certain other benefits. The system may also lose least-cost dispatch, depending on how perfectly and frictionlessly the new market works. The Power Exchange and private dispatch operations, in my company's view, will combine to improve least-cost dispatch, through competition.

• Stranded system obligations. Stranded generating assets are obviously important concerns. These obligations should not be allowed to result in cost shifting among customers. Small customers fear they will be left to bear all of these costs if large customers go elsewhere for their generation. Utilities are concerned that their shareholders will bear these costs.

• Loss of support for public purpose programs. Loss of support for public purpose programs such as renewable energy, demand-side management, and low income rate assistance are all real concerns.

• Reliability. The reliability of the system, for which no single entity has complete control, is a serious, but we think resolvable, concern.

These concerns are not reasons for maintaining the status quo ante. They are reasons for going forward cautiously and deliberately, while developing reasonable solutions.

Ambiguities of jurisdiction between state and federal regulation are certain to be controversial as competition takes hold. The duty of regulators at both levels is to establish a clear dividing line between federal and state regulatory responsibilities and jurisdictions. Several serious issues deserve special attention.

Supplier regulation. One problem suppliers face in the new regime is the existence of long-term contracts with so-called qualified facilities. Under the federal Public Utilities Regulatory Policy Act of 1978, these independent generators must be paid on the basis of "avoided costs" by utilities, that is, according to a generous formula based on the costs the utilities would have incurred by adding equivalent amounts of their own capacity. Utilities view that requirement as inconsistent with a competitive market. Federal legislation would be required to level that playing field.

On the other hand, owners of qualified facilities fear that removing this requirement would not level the playing field, but rather tilt it in the opposite direction. They propose waiting until a competitive market has been established and tested. Their concerns are legitimate. It will be necessary simultaneously to ensure that competitive institutions are in place and that no group has an unfair advantage.

Nonqualified facilities sales are regulated by FERC. "Exempt wholesale generators" (i.e., independent generators exempted from the Public Utility Holding Company Act pursuant to the Energy Policy Act of 1992) cannot sell to retail customers—not even to the federal government.

Following the path that California is taking will require reexamining these prohibitions at the federal level.

Transmission access authority. FERC has the power to order mandatory wholesale wheeling, but the Energy Policy Act specifically forbids the Commission from ordering retail wheeling. On the other hand, states may not have the authority to order retail wheeling. They may be federally preempted from doing so. That issue will be litigated. In fact, nearly everything will be litigated, as interest groups appear on all sides of these jurisdictional issues.

Transmission pricing authority. FERC has authority over all interstate transmission pricing, and has affirmed that principle in its recent Order 888. States cannot set prices for retail interstate wheeling. But virtually all transmission is in interstate jurisdiction; even unbundled distribution service may be found to be in interstate commerce.

FERC would like to carve out for states a jurisdiction over distribution wire service, with a clear dividing line between state and federal jurisdiction. States would then be able to attach their charges for public purpose programs and stranded costs to the distribution tariffs or delivery charges.

Still, unbundling transmission and distribution services makes room for many different legal theories. One theory holds that unbundling transmission places the entire wire conduit, regardless of voltage level, under FERC jurisdiction. In other words, the theory implies, there really is no substantive distinction between transmission and distribution. The states would not be happy about such a finding.

Restructuring of the market. The high points of the California Public Utilities Commission decision were (a) the establishment of the Power Exchange, (b) the provision for direct access by 1998, (c) establishment of the Independent System Operator, (d) stranded cost recovery through a Competition Transition Charge, and (e) funding of environmental and public policy programs by nonbypassable charges.

The Independent System Operator's function is much like that of an air traffic controller. Some entity must ensure that the resources are in

balance with the loads and that the system is reliable. One should not regard it as simply regulatory meddling. The question is how best to structure that entity. The service must be provided on a nondiscriminatory basis, which is why California is moving toward an independent System Operator that has no commercial interest in any of the buyers or sellers.

California also has the Power Exchange, which conducts hourly auctions, as a spot market in power (with bids submitted the day before). If there were no formal power exchange, an informal power exchange would arise to serve the demand for hour-to-hour dispatch.

Customer choices. California customers' choices would appear to fall in four categories:

• Retain the current utility tariffed service. If a customer does not want to do anything in response to the new market structure, he or she will not have to do anything. The customer should not notice any change.

• Choose a real-time-pricing utility service tariff that will flow through to customers from the Power Exchange, allowing them to take advantage of hour-to-hour spot prices.

• Enter into "contracts for differences" (hedging contracts to protect customers from wide price swings). These contracts will probably not be regulated by FERC or state public regulators. They are pure financial hedges, which could be entered into today if there were a solid basis for writing them.

• Enter into bilateral contracts with generators or independent power producers.

Stranded costs. Under the traditional regulatory system, utilities made commitments to generation investments and to long-term contracts with qualified facilities, which are not currently economic. It is widely agreed that the low spot market prices and excess demand that now typify the markets mean that utilities cannot recover their full long-term investments simply through spot market pricing revenues. The deficiencies are "stranded" costs. Many utilities view the issue as a matter of contract; the traditional contract with society, in return for an obligation to serve,

involved a promise that these investments would be recovered (subject to reviews of the prudence of those investments).

Stranded costs fall into several categories: contracts with qualified facilities, utility-owned generation, regulatory commitments such as deferred taxes and nuclear decommissioning charges, and public purpose programs such as demand-side management, low income rate assistance programs, and perhaps also resource diversity programs.

Figure 1 puts the issue in economic perspective by looking at trends in utilities' embedded costs and market prices. In the 1970s, market prices (estimated by using utilities' marginal costs as a proxy) were generally above embedded costs, largely owing to high fossil fuel prices. Then, in the mid-1980s, market prices fell below embedded costs, as fossil fuel prices collapsed and utilities made substantial commitments to new resources, including nuclear plants and new contracts with qualified facilities.

FIGURE 1. The potential for stranded costs is the result of shifting economic relationships.

The Southern California Edison Company believes that, because utilities gave customers the benefits of embedded cost rates (through cost-of-service rates) when market prices would have been higher, they deserve the reciprocal treatment going forward: recovery of prudently incurred embedded costs, even though they may not be recoverable at current market prices. It is simply a difference between a long-term contract and a spot market contract. The long-term contract between utilities and society should be honored.

The Competition Transition Charge (CTC), through which stranded costs are expected to be recovered, is not an added customer cost. These costs are already reflected in rates. The CTC will be collected in California subject to no cost shifting through a nonbypassable charge. The plan is to show it as a line item on customers' bills. Rates will be capped at their level of January 1, 1996, so that recovery of stranded costs will not boost rates. Collection is to be completed by 2005, except for stranded costs related to qualified facilities, which will be collected over the lifetimes of the projects (which often extend for some time).

A hybrid method is being adopted in California for calculating stranded costs. The market valuation of each asset will be determined either by selling the asset or by obtaining an independent appraisal. Utilities will have five years in which to bring their fossil fuel resources to market and undergo market evaluation. Meanwhile, stranded costs will be calculated based on the difference between embedded costs and market prices during that period. When the utilities move to market valuation, the value of each resource will be assessed. That value will be compared with the book value of the resource, and the difference will be the stranded cost, which will be amortized over a period that cannot go beyond 2005.

Roles of utilities after restructuring. Utilities after restructuring will still provide distribution service. They will own the transmission system, but it will be under the control of the Independent System Operator. They will engage in retailing, with tariffs based on the time-weighted average exchange price, a real-time price. There may be other tariff options that will also persist.

Utilities will continue to own some generation, but will divest themselves of much of their generation. Nuclear and hydroelectric plants will apparently be retained by the utilities, at least for a time. Some of the

fossil-fueled generation will probably be moved over to unregulated subsidiaries of utilities.

Public purpose programs that are today funded in rates include low income assistance, women/minority/disabled veterans enterprises, renewable generation; environmental protection; local economic development; customer energy efficiency; and research and development. Some nonbypassable charge would be needed to continue funding such programs.

Customers can expect to receive bills with many line items on them. There will be a separate supply charge, generally reflecting generation costs, and a separate wires charge for transmission and distribution. There will probably be a continuing public goods charge. For a time there will be also a Competition Transition Charge.

The Southern California Edison Company is prepared to compete for customers' business in this new environment. It certainly wants to remain the provider of power for the federal government and other large customers.