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Proposal for Reform
of Northwest Electricity Delivery System

March 28, 1996

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To: Jim Davis, Douglas County PUD

From: Merrill Schultz

Subj: Proposal for Reform of Northwest Electricity Delivery System

A short time ago (March 7, 1996) I wrote you a memorandum containing some of my thoughts on the beneficial restructuring of the Pacific Northwest's electricity delivery system. That memo, in turn, relied upon a paper of mine (January 30 and February 26, 1996) which was the basis of a talk I gave to the NW Hydroelectric Association at the end of January. This paper is intended to present a comprehensive proposal for structural changes, including elements I have already expressed to you, and I hope you will forgive me if parts of the piece appear repetitious to you and other readers of those earlier papers.

Furthermore, I am aware of and agree with your intention of having the natural gas supply system of the region included in the Comprehensive Review of the Northwest Energy System. However, my expertise about the natural gas industry is so slight that I refrained from trying to venture any advice on that subject in this memorandum. That omission should not be taken, in other words, as a recommendation to limit the scope of the Comprehensive Review.

Conclusions and Recommendations

I conclude that:

  1. In the region's electric power system, competition may take a number of forms and may affect many products and services. Despite references by others to the current structure as the "monopolistic, regulated model", the existing structure includes numerous highly competitive markets of various kinds.

  2. Within the region, transmission access to resources over facilities of another party is already rather widely open to entities capable of performing adequately in the interconnected system. Access for other entities through mutually beneficial contracts for services with control-area operators is not uncommon.

  3. In operation, an alternating-current system must be vertically integrated.

  4. System control, peaking, backup and energy shaping are neither "ancillary" (in my dictionary's sense of "subordinate") services nor are they transmission services. They are generating capacity services of high value whose costs are traditionally treated as being fixed.

  5. Reasonable, relevant conditions tempering a purchaser's freedom of choice are not considered unduly restrictive in a truly competitive market. For example, it is not regarded as a restraint of the market for a property owner to insist on having a multiple-year lease agreement with a tenant -- in order to protect against stranded investment.

  6. No enhancement of competition in the current and near-future electricity market in the Northwest could reduce the region's overall variable cost of production significantly.

  7. Absent major congressional action or fundamental financial restructuring, the only way to reduce the fixed costs of the region's power supply system would be to default on established obligations.

  8. Given Conclusions No. 6 and No. 7, modifying the electricity market structure in the Northwest could produce only distributional effects, assuming no default.

  9. Transmission issues should be treated within the terms and conditions for use of transmission; likewise, power supply issues should be dealt with in the arrangements for power supply. That is, an owner of transmission should not use control of another's access to a market so as to thwart competition for such market. It appears that the only way to accomplish this separation might be to make sure that those responsible for negotiating transmission access have no power-marketing incentives. In a similar vein, measures designed to mitigate the stranding of power-supply investment should be incorporated in the agreement covering power supply -- and not in transmission conditions.

  10. Neither the English experiment nor the California program calls for divestiture of hydroelectric facilities. Because of the special obligations and liabilities associated with such resources, both Federal and non-Federal, divestiture would be difficult -- if not impossible.

  11. BPA, as a Federal agency, is necessary in the management and production of electric power generated at Federal projects (as well as at other resources acquired to date). However, its Federal-agency status renders the organization inefficient at acquiring new resources and commodity market trading.

  12. Central planning for the region's new power-supply resources, once an important process, is no longer meaningful.

  13. Many small, currently full-requirements public-agency customers of BPA could not practically survive as fully independent, vertically integrated utilities.

As a package of changes that stops far short of several other proposals now on the table, but nonetheless is seemingly herculean in absolute scope, I recommend that:

  1. The following would be repealed:

    1. Regional preference, except perhaps as a first right of refusal at a price.

    2. The Regional Power Act (PL 96-501) in its entirety, except to allow satisfaction of previous obligations made under its authorities. Mitigation of, and compensation for, the impacts on fish & wildlife of Federal projects would, of course, continue but would be made project obligations.

  2. BPA's role would be scaled back considerably, so as to resemble more closely that of WAPA's, functionally.

    1. BPA would market the output of the FCRPS, including non-hydro resources already acquired.

    2. Firm power would be sold, at a committed cost-based price, long term (five to ten years, perhaps on a rolling basis) and by subscription, take or pay. Limited amounts of "hydro-firming" purchases would be permitted in determining amounts available for firm sale.

    3. BPA would also sell unbundled capacity services, including the right of a customer to remain in BPA's control area (assuming BPA would still operate a control area).

    4. BPA would participate in the short-term wholesale market as it does now.

  3. All control-area operators would commit to devising, along with their wheeling tariffs required by FERC, cost-based tariffs for entities within their control areas appropriate to:

    1. Delivery of a resource of another entity inside the same control area,

    2. Delivery of a resource inside the control area to another control area and

    3. Delivery of a resource from another control area to the entity inside the control area

    If the ongoing proceedings regarding establishment of a new regional transmission structure produce an arrangement that includes such considerations, that result should, of course, prevail.

  4. All transmission owners and control-area operators would be committed by the new agreement to accommodating any and all transactions requested by entities within or outside their areas under relevant tariffs, limited only by physical transmission capacity. If valid complaints of applicants regarding refusal to provide such services reach a defined level, some designated authority would be empowered to require the establishment of an Independent System Operator who would thenceforth schedule all transactions in the region under a scheme to be prepared in advance of need, but held in readiness.

  5. A standard set of reasonable notice requirements for a change of power supplier would be established by agreement of a regional committee having broad representation. A supplier would have a one-time right to require any existing customer, at the time the new scheme goes into effect, to accept such notice requirements as a condition of the customer's being qualified to invoke the accommodation described in the prior recommendation.

Competition and Access in the Northwest

In the Northwest, to a degree unique in the country, there has always been competition among providers of electric power. There are many kinds of competition, and there are a number of products and services whose provision might be competitive. In the form of "yardstick" competition between or among neighboring providers, comparisons of price or quality of service at the retail level have influenced selections of sites in the region. Utilities with relatively low rates have been known to use published rankings as attractions of their service territories. And, of course, relatively high retail rates have always invited efforts to change the utility's form of ownership. At the wholesale level, there is a wide array of potentially competitive marketplaces. In power supply, there is the area of short-term, economy energy -- which itself might exist in several shades of duration and firmness -- and the hugely variegated firm-power market. Competitive markets for unbundled capacity services, such as peaking, control, backup, and daily and seasonal load-shaping, may exist. Furthermore, transmission is often not a natural monopoly. In the complex transmission grid of the Northwest, parallel paths of disparate ownership often exist between the same two points, and several entities have ownership-like rights on the Pacific Intertie. All of these areas, to one degree or another, have historically benefited from competition in the Northwest.

Since the beginning of interconnected system operation in the region, there has been open access for transactions of economy (non-firm) energy between control-area operating utilities in the region. Also, such utilities have taken almost for granted, for at least forty years, that long-term wheeling over another party's (mostly BPA's) existing or even new, purpose-built transmission would be available to integrate new firm resources located anywhere in the region. Probably because of the region's hydroelectric base, with most of the generation sited in the region's sparsely populated geographic center, Northwest utilities early on became used to dealing with resources remote from load and also depending on transactions with others to accommodate the ups and downs of hydroelectric energy. In contrast, it has not been unusual for access by Northwest utilities to other regions to be constrained by the market interests of the owners of the tie lines. "Retail wheeling", in the form of borderline loads, has been obtained by agreement of all parties. Utilities not operating control areas also have been able to rely on integration of remote firm resources through voluntary services-and-exchange or net-billing agreements.

Thus, it would be wrong to think that, because FERC's 1994 NOPR has ". . . Open Access . . ." in its title, access was closed prior to 1994. And it would be erroneous to conclude that, since many advocates of radical changes refer to their proposals as replacing the "regulated, monopolistic model" with a "competitive model," there was not competition before. Furthermore, utilities had acquired the output of resources developed and owned by others long before PURPA (1978) and had dealt with industrial customers' on-site generation earlier, too.

The electric power supply system of the Northwest, as it exists, is not describable in simple terms. It has some aspects of monopoly, but there is also a great deal of wide-open competition. Many kinds of transactions have virtually unhindered access to others' transmission, but some are constrained in transparently anti-competitive ways. There are well over one hundred entities independently serving customers at retail. Something on the order of half the region's consumers are supplied by entities which those consumers own and operate themselves -- and are not subject to retail rate regulation. Actors in the system include agencies of the Federal Government, municipalities, public (or peoples') utility districts, electric cooperatives and investor-owned utilities. Much of the power-supply base in the region is comprised of the Federal hydroelectric projects, which are authorized as multiple-purpose projects having important flood-control, navigation, irrigation and environmental responsibilities, in addition to power production. The system is a complex, multi-hued snarl -- but one should not forget that it has brought this region the cheapest electric power in the country.

Can the system be made better? Certainly it can, but the public interest demands that improvements be based on (1) careful, frank definition of the imperfections needing attention and (2) adoption of measures that are first subjected to the test of rigorous, skeptical debate (to make sure the cures are not worse than the ailments). Nothing should be sacrosanct, save the public interest, and slogans are no substitute for reason. Neither should something be done in the Northwest just because it is being done in some other industry or locale.

Caveat

As this discussion goes forward, it is essential that participants have at least some conceptual grasp of the workings of a multi-party, alternating-current electrical interconnection. That interconnection is a synchronous system in which all machines, whether motors or generators, operate at the same electrical speed. Putting load on a motor tends to slow it down, but it cannot operate at a different speed from the rest of the system; therefore, all machines, regardless of ownership, will tend to slow down (if the frequency in Edmonton is 59.95 Hz, the frequency in El Paso is 59.95 Hz). The entity responsible for that motor is only seeing its proportionate share of the impact, and it is therefore automatically receiving energy from others. This automatic backup is an intended benefit of interconnection, but reliance on it is acceptable only for a short while. Then the responsible entity must have increased the output of its own generators so that it is meeting its own load -- and finally the entity must later return the interim energy it "borrowed". Overly frequent and prolonged "borrowing" is considered stealing. It is not possible to write and implement a useful contract among the many control areas, so that the whole structure of interconnected system operation is based on good faith and responsibility coming out of enlightened self-interest. Control error in the interconnection is monitored assiduously, and identified delinquents are exposed to the scorn of all. This scheme of institutionalized peer-pressure has worked well so far. However, widespread abuse of the ability of a party to "lean on the ties", to the result that parties generally grow lackadaisical in their compliance with control standards, will lead to collapse of the very delicate, good-faith system.

This curious electrical system is not analogous to the structure of the garment industry, and the extent to which it resembles the natural gas supply complex is also quite limited. It must be vertically integrated, at least operationally if not by ownership, because the entity responsible for meeting the increase of load caused by a customer flipping a switch to "ON" must have arranged for some generator, somewhere, to pick up output by the same amount almost simultaneously. It would be convenient if one could simply adopt, for this system, an analogous set of rules to those already proven to work for that system, but no analogy extends very far. One should determine what is best for the electric system on its own merits, in full understanding that forcing existing control-area operators to tolerate what they perceive to be parasitic or irresponsible operation by new actors may lead to interconnected chaos -- and ultimately balkanization of the grid. Opening of switches has been threatened before; it is not action any traditional utility would take lightly, but it is not a risk to be taken lightly, either.

Another, perhaps more obvious point of difference between natural gas and electricity is that the proportions of investment represented by the respective supply, transmission and distribution segments of the two industries are not similar. The cost of power supply is a much greater fraction of the end-user's bill than is the well-head cost of gas supply. With no disrespect intended, a gas well is basically a hole in the ground, and it is much easier to imagine wells being drilled "on spec", or with only a short-term purchase commitment, than it is to conceive of an entity risking the capital necessary to build an efficient combined-cycle combustion turbine without the certainty of a lifetime revenue stream. There has been much talk to the effect that the new "competitive model" will shift the stranded investment risk from the rate-payer to the power-supply entrepreneur, the builder of the "merchant plant"; until there is a clear example of this phenomenon having actually occurred in the region, one would be well advised to be skeptical.

Causes of Our Situation

In the late 1970s, the price of fuel oil was very high, maybe 15-20 times in 1978 what it had been ten years earlier, and our Government determined that the effort to achieve independence from foreign oil sources was the "moral equivalent of war." At its regulated price, the U.S. natural gas supply was fully bespoken and Canadian gas prices had risen to match those of oil. Conventional wisdom, articulated by the most highly credentialed experts in the highest levels of Government, was that natural gas reserves were near exhaustion. Congress enacted the Industrial Fuels Use Act of 1978, which provided severe restrictions on the use of natural gas, especially for power generation. Oregon, as I recall, banned new industrial hookups of natural gas (for process use) altogether. At about the same time, the Public Utility Regulatory Policy Act ("PURPA") was also enacted. Among other things, this Act required investor-owned utilities to purchase the offered output of independently constructed generating resources at the utility's avoided cost, as determined by the State's public service commission. This, with the help of various tax incentives, was intended to encourage construction particularly of renewable resources too small otherwise to be of interest to the utilities. Electric load growth, bolstered by people's fears of oil and gas shortages, carried on unabated at annual rates in the PNW between five and seven percent. The Government continued to promote development of nuclear power as a matter of policy (while at the same time, as a matter of regulation, it continued to make nuclear construction ever more expensive), and utilities eagerly began building many such facilities. Utilities also turned to coal-fired generation in a big way, even reconverting to coal some plants in the East that had been converted to oil or gas for environmental reasons a few years earlier. Requirements for abatement of air and water pollution increased the costs of new coal-fired plant tremendously, as well.

Nuclear plants and coal-fired plants had to be big, their construction times were long (and becoming longer) and their initial costs had become very high. These costs were also the Avoided Costs used by the public service commissions in determining the amounts utilities would have to pay for the output of Qualifying Facilities (QFs) under PURPA. The California PUC was particularly avid in carrying out PURPA's mandate, and the infamous Standard Offer No. 4 sparked what has been called the "second California Gold Rush", as developers took advantage of the situation to force California utilities to buy what turned out to be several millions of Kilowatts of surplus, must-run generation at prices in the neighborhood of ten cents per Kilowatt-hour. The Southwest utilities continued construction of their nuclear plants during this process. Based on the fact that addition is commutative, some have argued that the surplus was equally attributable to the completion of SONGS Nos. 2&3, Diablo Canyon and Palo Verde, even though those plants were already in stream when the QFs were signed up.

Electric load growth virtually ceased, over the entire continent, starting in 1979 or 1980, and the early 1980s saw the abandonment of many nuclear power plant construction programs. However, at least partly because of the "used-and-useful" principle, a large number of projects well along in construction were completed, in the face of growing surpluses. At the same time, deregulation of natural gas was responsible for increasing the availability of that fuel, and in 1985 the price of natural gas collapsed. Electric energy generation using natural gas as a fuel, which had a variable cost of more than 6 cents per Kilowatt-hour in 1980, now cost 3 cents per Kilowatt-hour, or less. But also by the late 1980s, retail electricity rates in California, based on embedded costs, averaged well over 10 cents per Kilowatt-hour and were still climbing.

During these same years, technological advances in gas-fired simple-cycle and combined-cycle combustion turbines continued; both the heat-rates and costs dropped. Nowadays, one can purchase a combined-cycle combustion-turbine (CCCT) unit one-tenth the size of a typical nuclear plant, having a construction time about one-fifth as long, costing initially perhaps one-quarter as much (per Kilowatt), exhibiting higher thermal efficiency and burning cheaper fuel (per Btu). Thus, it is claimed by developers that a new CCCT can be acquired for a life-cycle levelized real cost about equal to BPA's proposed PF-Rate, 25 mills per Kilowatt-hour.

Here then is the problem, especially in areas with very high embedded costs (and therefore retail rates), such as New England and California. Those areas are facing severe blows to their economies as some industries relocate elsewhere, and others compound the upward rate pressures by turning to self-generation or finding new suppliers.

Was this problem caused by utilities' overbuilding? Partly. Was it caused by Government, through its enormously mistaken evaluation of natural gas supply and its resulting misdirected regulation and legislation, together with its promotion of nuclear power while making that power prohibitively expensive? Partly. Did the environmental movement cause the problem, by making coal-fired energy very expensive and by hindering development and efficient operation of hydroelectric projects? Partly. Could the problem have been avoided by having had more competition in electric power supply and transmission during the 1970s and 1980s? Absolutely not.

The Situation in the Northwest

It has been noted here that a new CCCT can be installed and operated for a cost that is a fraction of the retail utility power rates in California, and elsewhere it has been pointed out that the retail rates of the California investor-owned utilities are about 150% of the National average. Therefore, in California there is a real danger of utility investment being "stranded" (that is, increasing the cost of capital recovery to the remaining customers) by the large industrial customer by-passing the utility and finding another supplier or installing its own generation, or by moving its operation to another area, one served by a utility with lower rates.

I believe there is little threat in the Northwest of an industrial customer leaving the region to take advantage of lower rates elsewhere; even though retail rates have increased considerably in the Northwest over the last fifteen years, they are still considerably below the National average. If one could find an area with lower rates, the differential would not likely be sufficient to pay for a move. Also, I believe there is little threat in this region of end-use customers installing substantial amounts of on-site generation, other than cogeneration, or participating in the construction of new generation by another party. Although the raw bus-bar costs of new generation might be found to be slightly lower than the utility's rate, the costs of control, back-up and perhaps transmission would be substantial. Due to exogenous market forces, some of these customers might leave the region or might shut down, even if electricity were to have virtually no cost. Some industrial customers might elect to be their own power suppliers, especially with cogeneration, as they have historically, but probably not in amounts so as to threaten stranding of utility investment. Wholesale utility customers of BPA will install generation, as they always have -- and not always for obvious economic advantage -- but not likely at such a rate in the aggregate as to increase BPA's unsalable surplus. Thus, I conclude that the competition in the form of new non-utility generation already exists, is tolerable and needs no new structural attention one way or the other.

The new cause of real concern in the Northwest, in my estimation, is the competition presented by power supply from existing capacity or from currently unsecured capacity. These deals are being offered by utilities and non-utility traders alike at prices reflecting (1) that the resource is no longer in rate-base, (2) that all or a portion of the capital recovery requirement of the resource is being paid by someone else or (3) that the supplier is depending on continuation of the current abundant, cheap spot market. Typically these arrangements are for five years or less, and they have prices at or below the BPA PF-Rate (and, of course, the fully-allocated cost of new generation). In other words, the supplier will not acquire a firm generating resource for the purpose of fulfilling the commitment. It is this kind of transaction that the purveyors thereof and many large industrial customers have been pushing the regulators to facilitate. It is this kind of transaction that, in my view, has the potential for significant stranding of utility investment, both public and private.

The proposals to allow retail customers to have access to alternative power suppliers do not consider only large industrial customers. Both the British Pool experiment and the recent California PUC's policy call for eventual open access being made available to all customers, even residential consumers. In these schemes, it is recognized that a residential customer would not likely be able to deal directly with a supplier of generation, so that a new creature, the Aggregator, would appear. The Aggregator would supply a group of subscribers from an identified portfolio of resources, through the distribution system of the local utility; the utility would continue to meter the customer and would bill on behalf of the customer's selected Aggregator.

The antidote most frequently prescribed for avoiding the destructive effects of expanded transmission access at the wholesale level and even for retail customers is some form of compensation for stranded investment or a restraint on the customer's ability to make sudden changes of supplier. FERC has proposed such a charge to be applied to transmission tariffs, and the California PUC, in its recently adopted order, has indicated that the currently existing investment of suppliers will be protected against stranding. Thus, stranded investment protection seems to be rather broadly accepted, at least for cases where the existing covenant between supplier and consumer was executed at a time when open transmission access by non-control-area entities was unheard of -- and the need for the protection was considered equally unheard of.

Retail Wheeling

As stated earlier, an alternating-current power system must be integrated vertically, even if that integration is accomplished by contract rather than through ownership. Generation and load must be synchronized in virtual lockstep, instantaneously. There is a huge difference between (1) the services that a control area provides for two other control areas (wheeling) and (2) the services provided where one or both the delivering and receiving entities do not operate control areas (wheeling, control, shaping, peaking, backup). For example, if BPA is wheeling a delivery from Washington Water Power to Seattle City Light, both WWP and SCL control their own generation to ensure that their respective export and import agree at all times with the prearranged schedule -- here BPA is providing a bare transmission service. However, in the case where Acme PUD, heretofore a full-requirements customer of BPA, expects to wheel its power supply from, say, Washington Water Power, BPA would have to make up the difference, moment by moment, between Acme's load and the scheduled delivery from WWP to BPA. Now BPA is not only providing transmission service, but it is also providing firm capacity in various forms -- and if the source were not WWP, but rather a "merchant" plant in BPA's control area, BPA would not only be accommodating load fluctuations but also generator contingencies.

It appears that FERC has referred to these additional services as "ancillary transmission services"; if so, FERC is greatly mistaken. These are not transmission services, to begin with (litmus test: could they be provided by building additional transmission?), and putting a one-mill/kwh cap on them is, in my view, confiscatory. They are capacity services, requiring more than an AGC computer and some telemetry; they require generating capacity. BPA has dealt with deliveries of non-BPA power to non-control-area entities for many years, so that this kind of service should not be seen as being novel. The arrangement, though, is not called "wheeling" but, more appropriately, it is referred to as "services and exchange." And the appropriate charges in today's market should comprise the transmission tariff plus increments for all the other unbundled services included.

It is important to note that the functional distinction is whether an entity operates or does not operate a control area, and not whether it is a wholesale or retail customer.

Divestiture of Generation

One more time, the load-distribution-transmission-generation chain forms a synchronized system that must be integrated operationally. It has been noted that designated generation must be on hand to respond instantaneously to load fluctuations and generation contingencies. Generation and transmission are also interdependent operationally; generators supply a major portion of the reactive power absorbed by the operating transmission system, generation dispatch is adjusted to improve the distribution of power flows on the parallel paths of the grid, and remedial action schemes for transmission contingencies frequently involve generator tripping, among other linkages. Many reformers look for guidance to the English restructuring, and they should remember that when the CEGB was divested of its generation to form the National Grid Company, the CEGB's two big pumped-storage hydroelectric plants remained with NGC -- precisely to perform the kind of load shaping and other capacity services described above. The investment represented by these facilities is in the billions of dollars, and even FERC could not rationalize that a pumped-storage hydro plant is really a transmission facility. Too, the voluntary divestiture of generation being undertaken by the California IOUs at the behest of the PUC is limited to fossil-fuel plants.

Hydroelectric generation is, of course, by far the most economic kind of generation to provide the essential system integration service. It is also fraught with so many environmental burdens, multiple-purpose obligations and public-safety concerns expressed in license or authorization that assignment of rights to it would be inordinately difficult. For these reasons, it seems almost certain that hydroelectric generation would be exempted, as it is in England and California, from any kind of generation divestiture imposed on the Northwest. In England and California this means that the bulk of system generation is still subject to divestiture; in this region, though, only a very small proportion of generation, and none of the FCRPS's, would be spun off. Divestiture would serve no significant purpose in encouraging independent power production in the Northwest and would not, in my opinion, be worth the effort. I conclude that there should be no attempt to force divestiture of generation from its current owners. I also conclude that, with the Federal hydro electric resources remaining Federal, a Federal marketing agent will be necessary to transact the necessary business and also to direct the operation of the FCRPS, including Columbia Treaty Storage and BPA's other acquisitions, for power purposes. This might not be the BPA as we know it, but it will be a BPA nonetheless.

Public Power

As I have been given to understand, the restructuring order promulgated by the California PUC applies only to the IOUs in that State. Los Angeles Department of Water & Power (LADWP) is a very large municipal utility owning thermal generation and substantial transmission (interwoven with that of Southern California Edison's), including the southern terminal of the 3100-Mw Pacific D-C Intertie; also, LADWP operates a major control area. Smaller, less independent public agencies, such as SMUD and the Cities of Burbank and Anaheim, are all over the map of the State. I understand that the CPUC order does not apply to these utilities, but there is hope expressed that they will participate voluntarily.

Around half the electric utility customers in the Northwest are served by public agencies, and, as in California, these agencies are not subject to the jurisdiction of any State public service commission. These utilities were instituted by the people of various political subdivisions to provide themselves electric power, using their own facilities and resources (including purchases). Many have developed, or participate in, efficient and inexpensive generation. I can bear witness that the management personnel of these agencies are usually in very close touch with the people whom they serve. I do not believe that those people see themselves as victims of electric monopolies, and I do not think they are ready to dismember their agencies on the unsecured promise that the presence of individual choice will produce better service at lower cost. The possibility, therefore, that half the customers in the region might not want to see their low-cost, locally and popularly controlled utility vertically disintegrated -- and that there is no way short of draconian legislation to force such a change -- should be taken into account. I conclude that such restructuring has not been shown to be in the public interest and should be put out of consideration.

I have heard knowledgeable people assert that there are public agencies in which industrial customers have been assigned tariffs much in excess of reasonable, cost-based allocations. Such has been done, I am told, as an interclass subsidy favoring the residential consumers. If this is the case, it unquestionably heightens the pressure to achieve direct access to alternative suppliers. I conclude that, even in a clear-cut case of retail rate disparity within one or several utilities, however, it would be unwise to turn the region's structure of power supply upside-down to solve a perceived inequity internal to such utilities.

Several public agencies have significant generation and operate fully-fledged control areas in WSCC. Some have small amounts of generation and either (1) operate "best-efforts" control areas that are overlapped by BPA or (2) get their generation delivered through net-billing or services-and-exchange agreements with BPA. But most are simply distribution utilities within BPA's or another's control area. From the standpoint of efficiency the number of existing control areas in the Northwest is already excessive, and it would not help either efficiency or control performance to add more. It is important, I conclude, to make explicitly certain that as non-control-area entities are provided more and freer access to alternative power-supply sources, such entities are not forced nor given economic incentive to proliferate the number of control areas in order to secure such access. I believe the existing control-area operators can serve as "Aggregators" for their customers, and I recommend that such least disruptive means be given a reasonable trial before the region resorts to a major institutional restructuring.

Market Transition Fees

In the 1981 BPA Power Sales Contracts the parties agreed to a seven-year notice requirement for modifications of the exhibit of firm resources used for computed requirements. This provision was intended quite deliberately -- and unabashedly -- to prevent a customer utility from reducing its purchase from BPA by virtue of acquiring a new resource on shorter notice, unless BPA has a resource deficiency. It was openly designed to avoid stranded investment, without foreclosing reasonable choice. And it was not intended to protect BPA, per se; rather it was supposed to protect BPA's other customers. In the case where a BPA wholesale power customer wants to "wheel" a resource to one of its retail consumers, I understand there is some question about whether the portion of the retail consumer's load served by that resource would continue to be considered part of the wholesale customer's load for billing under the BPA Power Sales Contracts. One way or another, however, it is likely that BPA can either discourage a customer's providing such wheeling abruptly in the first place or make the customer regret having done so, using the Power Sales Contract.

In any case, my view of this issue is that its resolution belongs in the contract for power supply, and not attached to a transmission tariff. When a customer reduces its power purchase from its supplying utility by virtue of an alternative resource, it is not (usually) transmission investment that is stranded, assuming that tariffs for transmission and other unbundled services are properly established and applied. In other words, I conclude there should be, in general, no Market Transition Fee associated with transmission. The problem of stranded power-supply investment should, to the extent it is relevant, be treated in the contract for power supply.

The ultimate manifestation of vertical disintegration must be the English exemplar, in which an independent system operator serves the coincidental demands of a host of retailers each half-hour by accepting the lowest-cost parcels of energy offered by (in theory) a large number of generation companies. The highest-priced quantum of energy in the stack sets the System Marginal Price, which is the basis on which all retailers are charged and all generators are paid. Some knowledgeable commenters have suggested that no prudent provider of generation would take the risk of installing generating plant and recovering its capital cost through the mechanism of a half-hourly energy auction. Such providers would insist on long-term, take-or-pay contracts -- and the retailer might also seek such contracts as a means of achieving price certainty. These instruments are called "contracts for differences" and obtain the desired price by equal and opposite adjustments of the Pool price paid by the retailer and received by the generator. One may view the traditional power sales contract as a "contract for differences", and it clearly serves as the logical vehicle for tempering the risk of stranded power supply investment.

Is Stranded Cost Protection Unfair?

I submit that in a free, market economy, rational restraints on choice voluntarily entered into by customers are commonly accepted. When I went into business in 1988, I negotiated with a number of potential landlords, all of whom offered various levels of "build-out" in return for my agreeing to leases of various durations. These owners were willing to expend capital for my company's benefit -- but they reasonably expected some commitment on my company's part to reduce their risk of stranded investment. The take-or-pay contract is a commonplace where one party makes a capital investment for the benefit of the other. Security deposits and notice requirements are also devices routinely used to mitigate the risks of stranded investments. The whole notion of "computed-demand" billing is that BPA is acquiring capital resources sufficient to serve the customer under Critical Water conditions; and the customer will pay on that basis, even though in most water conditions much cheaper energy is available.

Problems That Need Fixing

I conclude that there are three main problems that need fixing in this region. First is that the industry's performance in today's conditions is hindered and distorted by statutory anachronisms that should be cleaned away before any new features are adopted. Second is that BPA is trying (or, in some cases is required) to behave in a way to which it is constitutionally ill suited. Third is that the lack of reasonable stranded power-supply investment protection, in some cases, has led to transmission owners attempting to protect that same investment through denial of transmission access or through establishment of excessive transmission tariffs. If transmission owners had confidence that their power-supply investments were reasonably protected, open transmission access at truly cost-based rates would be easier to achieve.

Recommendations

Even grizzled veterans, such as I, who find the talk about discipline of the market place, risk-management through hedging, optimizing efficiency by establishing universal, unhindered choice, separation of generation and transmission -- and so on and on --to be uncomfortably lacking in both reality and concern for the public interest, must recognize that the conditions in the region's electric power industry have changed. Low-cost, plentiful natural gas is a fact; the modern CCCT is a fact; the capability of non-utility entities to construct and operate competitive generating plants is a fact; the Endangered Species Act and its impacts on the regional hydroelectric system are facts; and very importantly, the general availability of non-firm energy for purchases in the bulk power market is a new fact.

Over the years, many rules and regulations governing the structure of the power business have been established by statute. These have been responsive to the needs of their times and have tended to accumulate, like a tangle of duct tape and baling wire, in layers. I believe that, when people decide the old rules should no longer apply, the right thing to do is to change the rule book, and not simply have all the players collectively ignore the rules. Too, I find the repeal of major organic legislation through virtually clandestine additions to complex appropriations bills to be poor public policy. As difficult -- and hazardous -- as it might be, I recommend the straight-forward repeal of a collection of statutory anachronisms that are either simply wasteful or actually hinder the industry's adaptation to the conditions of today.

Regional Preference once gave very meaningful protection to all classes of BPA's customers, by reserving the low-cost output of the FCRPS for the Northwest. Its value has diminished greatly since the early 1980s through a series of factors and actions, the most recent of which is the amendment included in the 1996 Energy and Water Development Appropriations Act (PL 104-46). Originally Regional Preference was construed to allow BPA to export from the region only energy for which there was demonstrably no market in the Northwest at any applicable BPA tariff. As times, markets and executives have changed, this Preference has evolved into a mere first right of refusal for Northwest customers, as provided in the aforementioned Appropriations Act. I believe this transformation should be documented carefully and comprehensively in new legislation clearly repealing the original statute. Since the original language was also included in contracts between BPA and its customers, new contracts should also confirm the changes.

The Regional Act (PL 96-501) should be repealed altogether, and this action should be combined with a reform of BPA:

As part of the same package, BPA would be reinvented:

Through some sort of new regional transmission arrangement now being discussed, all transmission owners would commit to providing open access, at transmission-cost-based rates, and all control-area operators would commit to providing unbundled capacity/shaping/backup services also at cost-based rates -- so long as satisfactory initial stranded-cost protection is provided. I believe that all utilities have, or should have, secured adequate stranded-cost protection in their existing power sales contracts with those customers thought, at the time of execution of those contracts, to have the ability to reach alternative suppliers. Other firm-power customers desiring access under the new structure should have to accept reasonable stranded-cost protection, in the form of notice requirements, before such access is permitted, even by another provider. Furthermore, no control area would have to provide capacity/shaping/backup services without fair compensation.

It might be found, based on justifiable complaints, that despite the commitments made by transmission owners and control-area operators in joining the new transmission agreement, the power suppliers are allowing their power-supply interests to affect their willingness to make access available, their speed of movement in doing so or the magnitude of compensation applied to the service. However, because setting up an Independent System Operator (ISO) would be so difficult, I recommend giving a fair trial to the new commitments regarding open access to be made by the existing transmission owners and control-area operators. As additional incentive for such owners to live up to their commitments, the pertinent agreement should provide that the parties will develop, and keep in readiness, a structure for establishing an ISO, to be triggered if a broadly based joint authority decides that a sufficient number of valid complaints have been lodged so as to warrant the action. The ISO would then schedule all transactions on the region's grid.

cc: E. L. Landin

W. C. Dobbins


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