Electric restructuring weighs heavy on the mind these days. Drastic remedies are born more of hope than vision. Look at the April 20, 1994, proposal from the California Public Utilities Commission (CPUC) for mandated retail wheeling (the Electric Restructuring Order, often referred to as the "Blue Book").1
The Blue Book became a catalyst for national debate. But the Blue Book did not create the problem; it only reacted. The problem stems from a confluence of forces: the rise of nonutility generators (NUGs); the emergence of new smaller-scale generating plants; the rate impact of social engineering; and, for industrial rates in particular, the design of rates oblivious to markets or prices.
Retail wheeling by commission fiat is nothing more than a regulatory sanction of bypass: a means to make nonutility power available to large industrial ("direct access") customers. The initial California timetable, which was delayed again and again, would have made retail wheeling available to these customers by January 1, 1996. The presumption was that large customers could buy nonutility power at cheaper rates than the utility company could offer. But bypass under this mindset will only exaggerate (em not mitigate (em the enormously expensive issue of stranded costs. By any standard, a rush to mandatory retail wheeling signifies an extreme measure, an overreaction to a condition for which there is an easier and better remedy.
Mandated retail wheeling as proposed in California stemmed from a perception that electricity prices, particularly for large industrial customers, were too high (em that bypass would cut prices to "competitive levels." The economies of scale, the lower costs associated with bulk deliveries, and the economics of unutilized spare capacity have, more frequently than not, been downplayed.
California, for example, carries a surplus of electric generating capacity. Yet California fixes the generating cost component of regular tariff rates by adding in the assumed cost of an unneeded combustion turbine (to arrive at a "marginal cost" of generation) rather than looking at the savings in per-unit fixed costs achievable by improved plant use.
The simple remedy is to allow industrial prices to be set competitively at market value through incremental pricing. But it doesn't matter what words you use. Call it market-sensitive rates, market-responsive rates, market-based pricing, or just value pricing. For all practical purposes, these three terms are synonymous. Value-based rates geared to the market should replace cost-based rates divorced from the market.
And it is neither iconoclastic nor radical to suggest a change of thrust from cost to value. The history of natural gas and electric prices is replete with examples of value-based or incremental pricing (em from natural gas pipeline ratemaking by the Federal Energy Regulatory Commission (FERC), to the "variable" rates that the Bonneville Power Administration charges its aluminum smelter customers.
The Department of Defense, for itself and all other federal executive agencies, in comments on new California telephone regulation, is emphatic: "Incremental cost is the only relevant standard for analyzing the price floors for services that face effective price competition or a highly elastic demand function. ... Incremental cost identifies the minimum price that must be obtained from that service. A price above incremental cost yields a net financial improvement to the telephone company while one below incremental cost yields a net financial detriment."2
In November 1994, the California Energy Commission projected that three of the state's five largest electric utilities would have sufficient generating capacity for the next decade: Pacific Gas and Electric Co. (until 2004), Southern California Edison Co. (until 2005), and Los Angeles Department of Water & Power (surplus capacity of over 1,000 megawatts (MW) through 2005). The other two, San Diego Gas & Electric Co. and Sacramento Municipal Utility District, have an immediate need for additional capacity.3
The current surplus of generating capacity, teamed up with competition from NUGs, points overwhelmingly to market pricing. NUG rates are not burdened with the massive embedded costs of rolled-in utility rates. A requirement for rolled-in rates would effectively foreclose utilities in their role as utilities from being competitors. Such a rule would narrow competition, not enlarge it (em quite the opposite of what the retail wheeling proposals intend.
The PG&E Proposals
In a blockbuster proposal, Pacific Gas & Electric Co. proposed on February 17, 1995, to wheel and deal simultaneously (em to offer voluntary retail wheeling in exchange for the opportunity to negotiate a discounted generation price with its large industrial customers.4 That proposal follows on the heels of an earlier move, announced March 1, 1994, to adopt market pricing for a deregulated "Large Electric Manufacturing Class" (LEMC).5 Both ideas are under consideration at the CPUC.
The retail wheeling proposal of February 1995 essentially would allow a large customer to negotiate the generation price component of the bundled retail tariff already in place. Here's how that would work:
The customer could select any electric generator it preferred to provide its power supply, including PG&E. The customer and PG&E would negotiate a generation price. PG&E would then return to the bundled tariff, deduct a hypothetical cost assumed to be equal to the generation cost component of the tariff,6 and add back the negotiated price as a proxy for generating cost. The customer would then pay a traditional bundled tariff rate, albeit a tariff containing a separately negotiated generating cost element. This service amounts to retail wheeling (em not mandated, but offered voluntarily by the utility itself, at a de facto unbundled rate.
In return, PG&E would gain permission to compete for the customer's purchase with other alternative suppliers on an equal basis; that is, without regulatory constraint as to the prices it could negotiate. The result is competitive pricing fully consistent with incremental or value pricing. PG&E goes beyond the requirements of the theory, however, by agreeing to absorb any revenue loss resulting from the price it offers: "PG&E shareholders will be at risk for the difference between the applicable [regular tariff rate] and the price negotiated with the customer," and "lower revenues to the utility . . . [cannot] be offset through rate increases to other customers."
PG&E envisions the experiment extending statewide in California, with similar filings by the other utilities. The experiment would last for three years, beginning January 1, 1996.
PG&E's latest proposal to wheel and deal combines customer choice with pricing reform. In that sense, it builds and improves upon the earlier March proposal, which approached competitive pricing from a more orthodox direction. In that proposal PG&E recommended three different types of "customized/negotiated" contract offers, as part of its application to create a new business customer classification, the LEMC.7
The LEMC plan calls for three specific new tariffs: a Cogeneration Deferral Tariff, to induce the postponement of customer-owned cogeneration; a Business Retention Tariff, to avoid the loss of load to lower-priced electricity suppliers; and a Business Attraction Tariff, to promote increased sales to existing customers or encourage new customers to locate within the company's service area.
PG&E proposed that the rest of its electric customers would not be affected by the amount of revenue collected from the LEMC, including discounted-price customers as members of the class. PG&E advised that it would bear the financial risk "should its pricing and services not match LEMC customers' competitive options."
The Last Word
Should the issue of retail wheeling be tabled? No. Retail wheeling should neither be promoted nor prohibited by Commission fiat, provided the utility company is allowed to offer competitive rates to would-be bypassers.
But in a climate of high rates, surplus capacity, and rising competition, a two-pronged wheel and deal strategy grounded on value pricing can leave the customer free to choose and the utility free to compete. t
Roger L. Conkling, now adjunct professor at the University of Portland, is a retired senior vice president of Northwest Natural Gas Company where rate design was one of his responsibilities. He has been a consultant on regulated pricing and other economic issues to many major natural gas producers and several regulatory commissions. In the electric arena, he has been an executive of Bonneville Power Administration with staff responsibility for commercial power transactions (including rates), budgets, and power operations, for which he received the Department of Interior's Distinguished Service Award. Currently, Conkling is writing a book on electric and natural gas pricing.
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