Stranded In Sacramento
California Tries Legislating Electrical Competition

by Robert J. Michaels

Professor of economics at California State University, Fullerton; senior advisor to Hagler Bailly Consulting of Arlington, Virginia; and adjunct scholar of the Cato Institute. The views expressed in this article are not necessarily those of his affiliations or clients.

Hardly anyone in public life ever does what we economists know should be done. We usually cope with our frustrations by commiserating among ourselves, acknowledging the pitfalls of politics, and theorizing about new imperfections for government to remedy. Economists who casually observed electricity regulation once thought they saw an implicit long-term contract to allocate the benefits, costs, and risks of a vertically integrated natural monopoly according to principles of efficiency and fairness. Some even concluded that the belief provided a rationale for paying investors for utility assets that could not survive competition.

On the last day of the 1996 session, both houses of California’s legislature unanimously passed Assembly Bill 1890, a law to restructure the state’s electricity markets and streamline their regulation. Though touted as an ingenious mix of competition and fairness, on closer reading A.B. 1890 looks like politics as usual. Regulated utilities will fight to keep their gains, legislation will favor some parties with single interests over parties with diffuse interests, and consumers will remain ignorant of the choices made for them.

The new law approves the California Public Utilities Commission’s (CPUC) plan for a statewide power exchange and an independent system operator to control electrical generation and transmission. The exchange, however, may be inconsistent with real competition. Additionally, the independence of the operator is uncertain since the utilities being restructured are also owners of the transmission the operator will allocate.

On the consumer side, A.B. 1890’s scheme for rescheduling the recovery of stranded utility costs will delay competitive choices for small users in return for a negligible interim rate reduction. An off-budget state agency will finance the rescheduling. It will use the stranded assets to collateralize the bonds, thus giving the state an active and durable role in ensuring that utilities recover their claims. Stranding charges are nonbypassable; they cannot be shifted between large and small users. A.B. 1890 also maintains California’s tradition of regulatory attention to environmentalists, low-income advocates, and organized labor, while opening a new front in the conflict between the state’s corporate and municipal utilities.


The Road to Sacramento

On 20 April 1994 CPUC issued a landmark notice of rulemaking soon to be known as the "Blue Book." The Commission proposed that between 1997 and 2002, electricity users be granted "Direct Access" to suppliers of their choice. Transmission-owning utilities would "wheel" the power to consumers as they already do for one another in an active regional market. The Blue Book proposed full recovery of stranded investments. At CPUC’s first hearings, Pacific Gas & Electric (PG&E), which serves the northern half of the state, accepted Direct Access conditional on securing compensation for stranded assets.

The other two major corporate systems, Edison International (EI, then known as Southern California Edison) and San Diego Gas & Electric, introduced two variants of an alternative patterned after the short-term power pool market in Britain’s recently privatized system. EI called their alternative PoolCo. It would cover the western United States. According to the plan, centralized operators would take hourly energy requests from utilities. The number of requests would vary from hour to hour based on consumer demand for electricity. Generators of electricity, including utilities companies and other generators that sell power, would offer power at prices that would also vary over time. For example, during peak operation, a factory that usually sells excess energy might have little to sell and then only at a high price. The centralized operators would try to meet the demands for electricity by purchasing the needed amounts of power from the suppliers asking the lowest prices for the energy they generate. In that way, PoolCo would try to mimic the supply and demand operations of a true free market. In CPUC’s original direct access proposal, users could contract directly with suppliers, agreeing on any terms. By contrast, only utilities could purchase from PoolCo. They would remain monopoly suppliers of electricity to end-users.

Users would pay two classes of charges under PoolCo. They could either choose to buy energy at PoolCo’s fluctuating prices and adjust their consumption accordingly or, those that prefer steady prices could purchase financial instruments that shift pool price risks to others. Insurers of those instruments would, in effect, purchase energy from the pool in hopes of profitably reselling it to users at the contracted price.

Along with PoolCo’s energy charge, consumers would pay other fees. Those would be used to amortize utility powerplants and recover stranded investments. They would also be used to fund alternative energy programs, such as those using solar or wind energy, and they would be used as subsidies to help poorer citizens pay energy bills. PoolCo’s advocates stressed that their market was so close to a textbook ideal that anyone favoring the direct access proposal was either misguided or intended to profit from imperfections in the less transparent institution.


CPUC’s Plan

In May 1995, CPUC released a statement of its policy preference to implement a variant of the PoolCo proposal. That despite the fact that over the intervening year, PoolCo’s two utility backers had been unable to enlist the support of any interested parties other than a few environmental organizations and the planning-minded California Energy Commission. The proposal guaranteed full stranded cost recovery and a continuation of environmental and social programs funded by retail customers.

Unhappy that CPUC had seldom consulted them in so important a matter, state legislators introduced bills to give themselves new powers over the Commission and to inject themselves more actively into electricity policy. Understand-ably, neither PoolCo’s proponents nor its opponents wanted lawmakers to redesign the industry according to their intuitions. The result was a September 1995 Memorandum of Understanding (MOU). The utilities agreed to let direct access begin in 1998, but there would also be a voluntary statewide short-term power exchange.

Like PoolCo, the exchange would use bids and offers to produce a price that balanced supply and demand by the hour. Those who preferred bilateral dealings could bypass the exchange, their rights protected by an Independent System Operator (ISO). The ISO would be isolated from the bidding market. The isolation was intended to prevent transmission-owning utilities from manipulating the system. The operator would manage generation, ensure reliability, and schedule power transactions that buyers and sellers wished to make independent of conditions in the pool market.

In December 1995, a 3-2 CPUC majority recommended implementing most of the principles. The minority favored a regime of bilateral contracts, believing that if it was warranted, buyers and sellers would construct a pool on their own (as utilities had done earlier to facilitate their own power exchanges). The minority believed that a voluntary pool formed by actual traders would more accurately reflect their desires than a centrally-imposed arrangement. A.B. 1890 became law in September 1996. The media gave it little more publicity than rewritten press releases on the virtues of competition and the fairness of stranding recovery.


Building a Market

The new law codifies CPUC’s plans for a statewide power exchange kept at a distance from the independent system operator. So far, regulators have authorized utilities to spend $250 million on equipment and software (some still untested) that will allow startup on 1 January 1998. As proposed to the Federal Energy Regulatory Commission (FERC), which has jurisdiction over transmission and interstate power transactions, the exchange will provide a competitive spot market with hour-ahead and day-ahead auctions. For the first five years PG&E, EI, and San Diego will be required to make all of their purchases and sales within the system, with notable exceptions. Participation of all other entities is voluntary.

Hydroelectric power, nuclear units, utility purchases of power under existing contracts, and generators on "must-run" status are exempted from pool bidding. As in the past, utilities will sell power to end-users from those exempt sources at regulated prices that recover historical costs. Currently, there are substantial intervals in which exempted generation approaches or exceeds each utility’s load. When that happens, utilities will demand little or no power from the exchange, and whatever price appears there will be devoid of economic significance.

Since out-of-state utilities must use the power exchange to deal with the three large California utilities, some intervenors have raised constitutional issues of interstate commerce. On 18 December 1996 FERC rejected their contentions, supplementing its legal reasoning with the observation that coercion may be necessary to establish markets that will bring great future benefits. FERC did not explain why electricity was so exceptional that self-interested transactors would not form markets on their own.

Regulators want the exchange they designed to succeed, regardless of any imperfections. CPUC documents frequently refer to the exchange price as the market price. Actually, traders could devise superior prices in a market allowing them to devise deals on their own.

Since the exchange only produces a short-term energy price, financial commitments for the capital costs of a new plant cannot be made through it. Some utility generators are fully amortized and the capital cost of other utility-owned plants will be guaranteed recovery through stranding charges. Plants whose fixed costs are thus covered will be able to bid energy into the exchange at prices slightly above operating cost and still earn a profit. Guaranteed recovery for old plants, however, will discourage investment in new plants whose capital costs can only be recovered in the difference between operating cost and twenty years of randomly varying pool prices.

According to A.B. 1890, the power exchange will "provide an efficient competitive auction" that clears the market "at efficient prices." The possibilities for manipulating the auction will depend on details that still puzzle the economists assigned to design it. In a March 1997 filing at FERC, the California utilities proposed a mechanism to detect and police anticompetitive activities at the exchange. Even if some type of antitrust activity is needed, the market institution itself is probably a poor choice for an enforcement agency.

FERC’s recent Order 888 articulates both its interstate transmission policy and its willingness to cooperate on separation of federal and state jurisdictions. FERC recently accepted California’s jurisdictional proposals, but may have more difficulty in accepting California’s proposals on transmission pricing. California intends to allow transmission owners to charge economically rational premiums for the use of congested lines. FERC, however, often questions transmission rates that recover more than recorded costs on grounds that such rates may conceal monopolistic behavior by transmission owners.


Socializing Stranded Investment

In September 1996, the three large utilities tentatively estimated total stranded costs to be between $21 billion and $25 billion, most of which they intend to recover over a transition period that ends on 31 December 2001. The costs of uneconomic plants to be recovered include a return on equity equal to the utility’s cost of long-term debt. The legislature kept in place a CPUC provision requiring each of the three utilities to divest half of its California fossil-fuel powerplants.

Transition charges will be allocated among customer classes in proportion to power consumption. Customers who choose direct access between 1998 and 2001 will remain liable for their shares of the stranding bill. Since power users are paying off uneconomic costs in existing regulated rates, the law will have little direct impact on their bills. It imposes a rate freeze on industrial and large commercial customers over that period, and requires a 10 percent reduction in residential and small commercial rates until the end of the transition.

The law proposes to finance the rate reduction by authorizing the California Infrastructure and Economic Development Bank to issue or guarantee up to $10 billion in "Rate Reduction Bonds" for the utilities. Created in 1993 for other purposes, the Bank is so off-budget that it is unlisted in any state directory or Internet document. As security for the bonds, the bank can acquire stranded assets (referred to as "transition property") or utilities can pledge them as collateral. Legally, the bonds are not state liabilities and are not backed by California’s "full faith and credit." The bank’s security interest in the assets allows it to foreclose, but in case of a default, the state will prefer to find money for utilities rather than take over their nuclear plants or problematic contracts. The law intends for the bonds to be off-budget for the utilities by allowing an accounting treatment that will make them hard to find on the utilities’ financial statements. The Securities and Exchange Commission, however, has recently ruled that such securitizations do not qualify the utility to segregate the bonds and an equivalent amount of stranded assets from the rest of their accounts.

The only real benefit to small consumers lies in the difference between the interest payments on ordinary bonds and state-certified bonds. A.B. 1890’s promised rate reduction hides the effects of the longer period over which they will be paying out funds. Large users will not have to pay nor will they benefit from any rate reductions financed by the bonds. They will pay off their strandings and be free to seek their own power supplies after 2001. Small users, however, must remain with utilities until they have paid off the bonds that gave them the interim rate reduction, a process expected to extend through 2008. In return for the delay, small users receive little; their 10 percent reduction is computed prior to payment of interest and the bonds will not carry the low rates of tax-exempts.

To have bonds issued on its behalf, a utility must first apply to the CPUC for a "Financing Order." The utility must show that its small consumers will "benefit from reduced rates by issuance" of the bonds and identify assets to be treated as transition property. The Commission has 120 days to rule on the application, during which a utility can also proceed with its application to the Infrastructure Bank. Utilities must apply for financing orders by 1 June 1997. Subsequent requests are possible. Possibly, the hurried schedule attempts to ensure that the bonds are issued before the new legislature realizes what the prior one enacted.


Who Pays Stranded Investment Charges?

The simplicity of A.B. 1890’s allocation of stranding charges in proportion to power consumption may be illusory. Several strategies will be used to avoid stranding charges. First, new customers must pay the same transition fees as old customers unless they initiate their service through direct access. Departing customers pay no exit charges, probably due to constitutional considerations of interstate commerce. The multitude of legal methods for transferring ownership of California assets may produce a steady stream of ingeniously created new customers. Utilities will wish to exempt some of them from stranding charges to position themselves for future competition. Second, a customer who reduces load in the "normal course of business" enjoys a reduced stranding charge. He might attempt to make that reduction permanent by threatening to close in a politically visible way if relief is not forthcoming.

A final method for avoiding stranding charges will involve a reduction in electricity use stemming from increased power efficiency or fuel-switching, possibly to gas sold by regulated distributors. A.B. 1890 lets the California Energy Commission (CEC) determine whether power produced by on-site fuel cells constitutes acceptable switching. The efficiency of fuel cells is rapidly increasing, their economic scale is decreasing, and the CEC, a product of the Jerry Brown administration, generally encourages unorthodox, non-utility power sources. To discourage attempts at early bypass evasion, the law states that after 20 December 1995 self-supply of power by a utility customer will require a stranding payoff.

The law will probably advantage existing utilities in post-transition competition by allowing them to selectively exempt customers from stranding charges. It first provides that a utility may apply for a CPUC order exempting a rate schedule or "type of use of electricity" from the transition charge. Rate schedules can be constructed to apply to single customers, and legal ingenuity is the only limit in specifying types of power use. The law next eliminates CPUC discretion, stating that it "shall [is required to] authorize new optional rate schedules . . . that accurately reflect the loads, locations, conditions of service, cost of service, and market opportunities of customer classes and subclasses." Prior to a customer’s eligibility for direct access, a utility can attempt to foreclose future competition by forgiving the customer’s stranding charges in return for a long-term contract.

A.B. 1890’s impact on a utility’s ability to transfer unrecovered strandings among customers is unclear. The law’s "fire wall" between small and large customers appears to state that a stranding concession granted to a large customer can only be recovered from other large customers. Any attempted transfer of obligations must also respect the law’s general rate freeze. Another section of the law, however, states that the purpose of the fire wall is to, "protect residential and small business consumers from paying for statewide transition cost policy exemptions required for reasons of equity or business development and retention." Statewide exemptions are those ordered by regulations or laws. Rate schedules for individual utilities are not statewide in scope and thus may allow shifting.


Resocializing Municipal Utilities and Renewing Renewables

A.B. 1890 is replete with strategy, subtlety, and spite, particularly as it applies to municipal utilities. The last franchise changeover in California took place in the 1940s, but since then the state has seen nearly constant litigation and regulatory maneuvers by transmission-dependent municipal systems intent on dealing for their own supplies using lines that transmission-owning utilities are reluctant to share. The Federal Energy Policy Act of 1992 gave municipal and corporate utilities rights to obtain transmission service from each other, but the coming independent system operator poses a new strategic problem. California’s Constitution prohibits state regulation of municipal electric rates, and the CPUC apparently cannot compel municipalities to surrender control of their facilities to the system operator.

Municipal systems serve about 20 percent of the state’s load, including Los Angeles, Sacramento, Anaheim, Riverside, Palo Alto, and numerous smaller cities. They own some strategically important transmission facilities, including one of the three AC Interties between California and Oregon. Revenue-hungry cities are increasingly willing to put some municipal assets at risk to compete outside of their immediate areas. Los Angeles voters recently approved City Charter Amendments allowing increased activity outside of the city by its Department of Water and Power. The Department recently allied itself with Duke/Louis Dreyfus, a leading power marketer, to explore competitive programs for customer retention. Hoping for first move advantage, Sacramento intends to offer its customers Direct Access beginning later that year rather than in 1998. Municipal utilities with transmission can bypass the new power exchange and system operator, but can also choose to use them when advantageous. The corporate utilities restricted to using these institutions understandably wish to constrain municipals in the same way.

California regulators cannot compel municipal utilities to use the new exchange and operating arrangements. Federal policy, however, requires that municipals have the option of using them. Thus unless otherwise constrained, municipal utilities will have choices that the CPUC has made unavailable to the corporate systems it regulates. A.B. 1890 intends to remedy the asymmetry by allowing municipals to collect their own stranded costs if they surrender control of their transmission to the ISO. Some cities have per capita stranding exposures in nuclear and other uneconomic plants that exceed those of corporate utilities, so that may be an offer they can’t refuse.

Whether they accept the offer or not, all municipals must hold public hearings on direct access. A city that chooses direct access must impose a nonbypassable stranding charge. Thus, a city with bad investments cannot choose to swallow the losses in hopes of attracting a user whose alternative server is a corporate utility with strandings.

A.B. 1890 requires that the regulated rates of corporate utilities include divestitures for research, renewable resources, social programs, and assistance to displaced employees. Unlike before, the law also requires that municipal systems set aside proportional amounts for the same purposes. Municipal utilities typically pay a percentage of their gross receipts to the city, analogous to franchise and property taxes. The free power and $100 million in direct contributions that Los Angeles receives from its utility are currently the margin of the city’s solvency. The law now compels every municipal utility to state on every customer bill the amount it is contributing per year to city government.



Beyond any implicit long-term contract lies a more ordinary one in which management is to act as an agent to further the interests of utility investors. If the regulatory contract ever existed, it was an agreement between utility customers and investors, rather than managers. If competition terminates the bargain, stranding expenditures should be returned to investors in amounts consistent with the expectations they held before the competition. Proposed methods of stranding calculation uniformly disregard those expectations, and will probably leave investors with much lower returns than they anticipated. In California, the owner of an uneconomic plant will get the difference between its book value (purchase price less depreciation) and the revenue it can expect to earn in an unregulated market. That amount does not necessarily have any relation to the returns to investors.

For example, Edison International’s calculation of transition costs is $9.1 billion, more than enough to purchase every share of its common stock. It is sufficient to buy the company and to retire another billion dollars in debt. Yet EI’s recovery would add to investor returns that already substantially outperformed the market. From 1972 through 1992 Standard & Poor’s 400 unregulated industrial stocks returned 713 percent to investors (capital gains plus dividends reinvested). EI’s predecessor company returned 1,517 percent. Although the stock fell with the issuance of the Blue Book in 1994, as of then, it is back at its 1993 price. EI’s investors cannot possibly make a credible claim for $9 billion more, and regulators cannot possibly think it a fair return to them.

Even if the amount is justifiable compensation for investors, they will only receive it by accident. The law requires that users pay it to the utility, but imposes no corresponding requirement on managers to pay investors. Utilities are probably enjoying the largest free cash inflows of any industry in history. The flows are unencumbered because utilities are leaving the generation business. They do not need to reinvest in capacity that will increasingly be provided by the market. Supposedly, utility investors sought low, stable, regulated returns, but the protected part of the business is shrinking to less than half of its former size. Management has an obligation to return those transitional dollars to shareholders rather than invest them in unregulated lines of business that appeal to a different class of investor. Recent utility uses of the inflows include the purchase or formation of marketing organizations, acquisition of gas transporters and marketers, construction of powerplants (including overseas), telecom ventures, acquisitions of burglar alarm providers, real estate operations, and, for Otter Tail Power of Minnesota, purchase of a minor league baseball team. California’s utilities are in fact using an appreciable part of their inflows to repurchase stock and to buy down and restructure debt. There is little reason to expect that, without regulatory or legal compulsion, most utilities will return all of their stranded investments to investors.


Selected Readings

William J. Baumol and J. Gregory Sidak, Transmission Pricing And Stranded Costs in the Electric Power Industry. Washington: AEI Press, 1995.

Robert Michaels, "Stranded Investments, Stranded Intellectuals," Regulation (no. 1, 1996), 47-51.

Dan Garber, William Hogan, and Larry Ruff, "An Efficient Electricity Market: Using a Pool to Support Real Competition," The Electricity Journal 7 (September 1994):48-60.

Robert Michaels, "Wholesale Pooling: The Monopolist’s New Clothes," The Electricity Journal 7 (December 1994): 64-76.

Robert Michaels, "After Stranding Recovery, What?" Public Utilities Fortnightly (June 1, 1996) 14-17.

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