Nearly three years on from the Yellow Book,1 after many long hours and thousands (em if not millions (em of pages, and following much bitter debate (linked with some murky politics), the California Public Utility Commission (CPUC) by a 3-2 majority has at last published an Order2 to introduce competition for retail customers.
The decision contains four main proposals:
s market structure
s access for customers
s stranded assets
s public policy
The Order follows the broad principles of the September Memorandum of Understanding (MOU)3 agreed between Southern California Edison (SCE), and representatives of power marketers, independent power producers (IPPs), and large customers. The Order requires the creation of an Independent System Operator (ISO) and a separate Power Exchange (Exchange) that will coexist with physical bilateral trades (the so-called flexible pool). The Order also addresses the issue of market power, which has bedeviled the market in England & Wales, where two generators control the margin (em hence prices (em most of the time, a result that has created considerable distortions and problems.
The ISO's responsibilities will be to ensure reliability and efficient operation of transmission, and
to offer nondiscriminatory and transparent transmission access to all players. To that end it will have operational control of transmission, plant scheduling, system balancing, and managing constraints, while the utilities retain ownership of their transmission assets. The ISO will have no financial interest in the market, nor any economic interest in any load or generation. It will be regulated by the Federal Energy Regulatory Commission (FERC). Although not spelled out, the board of directors of the ISO presumably will be structured either to balance competing interests or to avoid such interests.
To fulfill its responsibilities, the ISO will have to perform several tasks:
s Procure ancillary services, competitively where possible.
s Coordinate and schedule bilateral transactions between
generators, power marketers, and customers based on their nominations, together with transactions from the Exchange, in an economic and non-discriminatory manner.4
s Administer a system of transmission congestion payments and provide a set of tradable instruments to support long-term commercial transactions across locations in the system.
This arrangement meets the broad structure of the MOU, reflects the realities of the physics and economics of electric systems, and avoids the confusion from which some of the advocates of separation may have hoped to profit. The two organizations will effectively operate in an integrated manner.
The Order stresses the value of price revelation to customers, particularly small ones, since large customers can look after themselves. Based on the view that it will need a kick start, the Exchange will for five years be mandatory for capacity owned by the three major investor-owned utilities (IOUs), and voluntary for other parties. Like the ISO, the Exchange will remain independent, regulated by the FERC, and "prohibited from owning generation, transmission, or distribution facilities and will have no affiliation with any companies that own those facilities." It will operate in a nondiscriminatory and transparent manner.
Bids will be based on generators offering minimum-run prices for each unit for each period of either an hour or a half-hour (i.e., a "last price" auction), with users of electricity (distribution undertakings, power marketers, end-use customers) making demand bids. The bids will create an unconstrained schedule, which will be coordinated by the ISO with the bilateral nominations and, after taking account of constraints and iteration of bids, will form a constrained schedule.
Successful generator bidders will be paid the market-clearing locational prices determined by the ISO, but "end-use customers will see one clearing price." This is a curious provision that if taken completely at face value will undermine the Exchange. Not only will it lose the value (and equity) of locational price signals to customers and make it more difficult to hedge purchase risk by introducing "basis risk" between sales to and purchases from the Exchange; worse, customers in lower-price generation hubs would quickly gravitate to bilateral trading. Surely the wording is poorly drafted.
The CPUC learned from the major mistake in England and Wales of creating only three generators. The CPUC observes that, "[p]ractically speaking, the existence of market power can undermine our goals for restructuring and should be avoided." The CPUC envisions an important role for the ISO in mitigating vertical market power, but goes further. It wants the three IOUs to restructure themselves at the corporate level to separate their generation, transmission, and distribution businesses, and then not to contract between their own generation and distribution.
To mitigate market power in generation the CPUC asks Southern California Edison (SCE) and Pacific Gas & Electric Co. (PG&E) to voluntarily divest at least half of their fossil plant. To provide an incentive, the CPUC will increase the allowed rate of return on the equity component of the nonnuclear and nonhydroelectric stranded assets by 10 basis points for each 10 percent of such assets divested.
Access for Customers
Customers buying from generators or marketers will gain direct access for increasing increments of capacity, starting with 1,800 megawatts in 1998, leading to complete deregulation in 2003. Only a cross-section of customers will enjoy access, but there is no definition of which customers will be chosen, or how. Customers that remain with utilities will be offered either conventional tariffs, spot prices that they can hedge if they wish, or a rolling spot price. A phase-in schedule requires all sites above 100 kilowatts to introduce time-of-use meters by 2002, which seems very slow.
These proposals (em and the views expressed in the minority dissenting report (em are by far the weakest part of the Order because the debate focused on the wholesale market. Little thought has been allotted to the customer end of matters. The Order does not discuss how to unbundle the wires business from power retailing, whether and on what terms the utilities can own power retailing affiliates, or how to regulate either business. Both should be ring-fenced; the wires should be required to provide nondiscriminatory access. Then it becomes necessary to determine what should be done about metering, about right of access to metered data, and a whole host more of procedural, legal, computational, and system issues.
A fundamental difference separates electricity from all other products (including gas): Most products are sent from a factory to a customer, and a train of movement can be related to a sequence of money flows. Since electrons commingle, there is no physical relationship between production and consumption. Financial transactions have to be related to physical production and consumption via a settlement system, which sorts out who owes who how much for what.
Providing access for a few hundred or a few thousand large customers is easy. But the British found (to their cost) that extending access to tens of thousands of medium-sized customers is complex. The result was a data shambles, with hundreds of millions of dollars disputed, and recriminations all around. The proposals to extend competition to all customers involve a complex system, with estimates of $800 million for development and $125 million in annual operating costs (em all for a negligible customer benefit. Since pigs cannot fly, the absurd proposal will come to naught. But there are lessons for others.
While the debate raged over market structure (PoolCo vs. bilateral trading; direct access vs. virtual access), the main concern of the utilities lay with recovery of stranded assets.
The CPUC ruled that utilities should be able "to recover appropriate transition costs" through a nonbypassable Competitive Transition Charge (CTC), which is effectively a meter tax levied as a percentage surcharge on all customers. Although the CPUC hopes to enforce this provision by requiring customers to sign an agreement to pay their share of CTC as a condition of taking competitive supply, it would prefer legal backing.
The CTC would be assessed roughly as the difference between the allowed revenue on stranded assets less the amount they earn in the market, with an offset from the profit earned by hydro and geothermal plant, but capped so that prices do not rise in real terms beyond those prevailing on January 1, 1996. The CPUC's "goal is to get through this transition period as quickly as possible so that full competition can begin with minimal market distortions," and so generating assets will be market-valued by 2003 and (except for contracts) the costs of stranded assets should be settled by 2005.
Assets are uneconomic to the degree that book value exceeds market value (em transition costs represent the utility's net costs above market associated with its assets. The CPUC requires the net book value of all utility generation plants to be measured against the market within five years (by 2003), either by sale or independent appraisal, to form a final settlement. In the interim, it would calculate the CTC as the allowed income less income at market price.
The Order defines four categories of stranded assets:
1) nuclear plant, 2) fossil plant, 3) regulatory assets, and 4) very favorable contracts with qualified cogeneration and small power production facilities (QFs) mandated by the CPUC (which cost SCE an average of 8.5 cents per kilowatt-hour (¢/Kwh) of purchased QF power).
Nuclear plant in large measure has fallen out of the debate, as the utilities have already struck their own deals. The CPUC has published its ruling on San Onofre, which is owned by SCE and San Diego Gas & Electric. PG&E has a seemingly favorable deal over Diablo Canyon, by which it gets paid about 9¢/Kwh, and which it wished to protect at all costs. The CPUC requires PG&E to file an application with a proposal to price the plant's output at market rates by 2003 and complete recovery by 2005, while not increasing rates above 1996 levels. It is not yet clear whether this requirement will hit PG&E.
The Order allows the utilities to recover all the net book value of their fossil fuel units through the CTC. Nevertheless, the CPUC showed concern that utilities should retain an incentive to
minimize transition costs, that if utilities were indifferent they might be tempted to depress the market-clearing price to squeeze other generators, and that "customers should benefit at least to some degree." With a measure of sophistry, the CPUC claimed that recovery of transition costs is less risky than normal (cost of service) recovery, because the CTC carries no risk that plant will be found not used and useful. It thus ruled that the utilities should earn a reduced rate of return on equity, which it set at 90 percent of the net cost of embedded debt.
Assuming that one-half the capital cost is financed by equity at 11.5 percent, and the embedded cost of debt is 7 percent, then the difference of 4.5 percent points represents $2.25 million annually per $100 million of stranded investment treated in this manner. As noted (see discussion of market power on page 23), the utilities can augment their return allowance by divesting fossil plant.
The Order grants full cost recovery through the CTC for regulatory assets, which include various deferred costs and taxes, nuclear decommissioning, and other costs, and "reasonable employee costs incurred as part of the transition to competition, including early and retirement and retraining costs."
The QF and other contracts will be honored fully and recovered, but the CPUC hopes that the utilities will find incentives to renegotiate some of them to the benefit of both customers and utility shareholders.
The Order endorses special treatment for women, minorities, and disabled veterans, which will continue, but suggests that the legislature should adopt a "public goods charge" on retail sales to fund research, development, and demonstration, plus energy efficiency programs not otherwise provided by the competitive market that are in the broader public interest."
It also suggests that there is legislation authorizing a separate surcharge to fund low-income rate assistance and energy-efficiency programs, and recommends that the legislature consider whether continued support of economic development initiatives is warranted in a competitive environment.
Some Final Thoughts
The Order is a tour de force. The market proposals are economically sophisticated, while also democratic and politically astute, reflecting extensive consultation. Large customers and power marketers, who had some side agendas, had previously signed up to the MOU, which had included some careful ambiguities and so could be interpreted in different ways by different parties. But now the CPUC has turned the ambiguities into sense, and has set out to protect the smaller customers.
The Order shows leadership. The CPUC is exercising authority that it does not have. And while the Order is ostensibly about California, in reality it will restructure the entire market in Western North America. If the PoolCo works, it will spread across jurisdictions.
Two key questions remain: First, will the Order stick, or will key aspects be overturned by the FERC (unlikely), challenged in the courts (possibly), or upset by the
California legislature? Second, will it be possible by 1997 to negotiate the pool rules and the many other complex issues of regulation, governance, finance, and system
operation? If the Order sticks, radical change will follow (em only time will tell whether such change will mark progress. t
Alex Henney was formerly a director of London Electricity. He was involved in the privatization of the electricity supply industry in England & Wales. He set up EEE Limited, and has advised electric companies, governments, and regulators in a number of countries, including the United States and Canada.
1. "California's Electric Services Industry: Perspectives on the Past, Strategies for the Future," Cal. Div. of Strategic Planning, Calif. PUC, Feb. 1993.
2. Order Instituting Rulemaking on the Commission's Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulation, Decision 95-12-063, R.94-04-031, I.94-04-032, Dec. 20, 1995, as modified, Decision 96-01-009, Jan. 10, 1996 (Cal.P.U.C.), published at 166 PUR4th 1.
3. See, "Electric Restructuring and the California MOU," by Alex Henney, Public Utilities Fortnightly, Oct. 15, 1995, p. 44.
4. The Order makes it very clear that when transmission constraints occur, the transactions will be scheduled along with redispatch "to meet the twin objectives of assuring operational reliability and achieving least-cost use of the system." To this end, "the ISO will determine the locational [viz hub-and-spoke] marginal costs, incorporating the costs of generation, losses, and congestion that will define the market-clearing prices for the Exchange and the price of transmission use for the bilateral transactions. The marginal costs of redispatching to provide an increment of load at each location will define the purchase and sale prices through the Exchange." The ISO will notify bilateral traders and the Exchange of the prices, and accept increment or decrement bids from the bilateral traders and supply-and-demand bids from the Exchange to determine transactions across constraints.
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