Comments Of The U.S. Department Of Justice In Response To Notice Of Technical Conference And Request For Comments


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UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION

Inquiry Concerning the Commission's
Pricing Policy for Transmission Services
Provided by Public Utilities
Under the Federal Power Act

Docket No. RM93-19-000

COMMENTS OF THE U.S. DEPARTMENT OF JUSTICE IN RESPONSE TO
NOTICE OF TECHNICAL CONFERENCE AND REQUEST FOR COMMENTS

Anne K. Bingaman
Assistant Attorney General
Antitrust Division

Communications with respect to this document should be addressed to:

Mary E. Fitzpatrick
Assistant Chief
Economic Regulatory Section

Gregory J. Werden
Director of Research

Jonathan E. Henly
Michael A. Einhom
Economists
Economic Analysis Group

Robert E. Litan
Deputy Assistant Attorney General Designee

Roger W. Fones
Acting Chief

Jade Alice Eaton
Attorney
Transportation, Energy, and Agriculture Section

Antitrust Division
U.S. Department of Justice
Room 9104 Judiciary Center Building
555 Fourth Street, NW
Washington, D.C. 20001
202-307-6349

November 4, 1993


UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION

Inquiry Concerning the Commission's
Pricing Policy for Transmission Services
Provided by Public Utilities
Under the Federal Power Act

Docket No. RM93-19-000

COMMENTS OF THE U.S. DEPARTMENT OF JUSTICE IN RESPONSE TO
NOTICE OF TECHNICAL CONFERENCE AND REQUEST FOR COMMENTS

Executive Summary

Bulk power markets have become increasingly competitive in recent years, and competitive procurement has become an important means of acquiring long-term bulk power supplies.Competition can flourish only if buyers and sellers have access to long-term firm transmission, and competitors should have guaranteed opportunities to contract for long-term transmission rights on specified terms. With increasing reliance on competition to allocate resources, transmission prices will be important signals for resource allocation, and transmission and generation investment decisions will respond to these pricing signals. Resources are likely to be significantly misallocated if improper transmission pricing signals are sent.

The Commission should break from past policies on transmission pricing. For either long-term or short-term transactions, rates based on rolled-in, embedded costs cannot be justified on efficiency grounds, nor is the Commission compelled by law to adhere to past policies when there are sound reasons for a change. Rates for long-term transmission transactions should be based on long-run incremental costs. To reduce the need for explicit calculation of long-run incremental cost rates, the Commission should encourage long-term transmission access in the form of joint ownership or ownership-like arrangements, and it should encourage regional transmission groups and other voluntary arrangements. For short-term transactions, the Commission should allow owners of transmission rights broad discretion over pricing.

UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION

Inquiry Concerning the Commission's
Pricing Policy for Transmission Services
Provided by Public Utilities
Under the Federal Power Act

Docket No. RM93-19-000

COMMENTS OF THE U.S. DEPARTMENT OF JUSTICE IN RESPONSE TO
NOTICE OF TECHNICAL CONFERENCE AND REQUEST FOR COMMENTS

On July 7, 1993 the Federal Energy Regulatory Commission ("Commission") published a notice ("Notice") in the Federal Register requesting comments concerning possible revisions to its policies for pricing of electric power transmission services provided by public utilities under the Federal Power Act.(1) The Commission also made available a Staff Discussion Paper on transmission pricing issues. The U.S. Department of Justice ("Department") is keenly interested in the development of sound transmission pricing policies because transmission prices will significantly affect the nature and extent of investment in new transmission facilities, the location of new generating capacity, and the competitiveness of bulk electric power markets.

In the past, transmission pricing may not have significantly affected transmission investment, generation location, or market competitiveness for one simple reason. Apart from the transmission services electric utilities provided each other in reciprocal, pooling arrangements,(2) the volume of unbundled transmission services provided by most utilities had been relatively small. In recent years, however, the Commission has conditioned the approval of several mergers,(3) and the approval of market-based rates for bulk power sales,(4) on the filing of open access transmission tariffs. Moreover, the Commission has begun to exercise(5) the broad authority to compel transmission access granted by the Energy Policy Act of 1992.(6) Finally, electric utilities now rely heavily on competitive procurements of bulk power. A large number of non-utility generators ("NUGs") compete in markets for new generating capacity, and they require access to transmission.(7)

As described in the Notice and in the Staff Discussion Paper, the Commission has traditionally priced firm transmission service based on the rolled-in, embedded cost of a utility's transmission system.(8) Because the rate for transmission service within a utility's system was not dependent on origin or delivery points, or on the distance between them,(9) the Commission's usual pricing practice was described as "postage-stamp rates," based on the long-standing practice within the U.S. of having a single rate for letters, irrespective of distance!(10)

Recently, the Commission has permitted firm transmission rates based on the costs of incremental investments or the opportunity costs associated with transactions that must be foregone in order to accomplish a transmission transaction. The Commission has not, however, permitted rates arrived at by adding costs of incremental investments or opportunity costs to rolled-in, embedded costs."(11) Rather the Commission has required transmitting utilities to chose either a traditional rolled-in, embedded-cost rate or a rate based on just the costs of incremental investments or on just opportunity costs.(12) The traditional rate is often the greater of the two in either case, so the new policies often have not substantially affected the rates actually charged.

The Commission has permitted nonfirm transmission services to be priced somewhat more flexibly. For example, the Commission has permitted "three-way split-savings" for economy transactions.(13) In such an arrangement, the transmission charge is one-third of the difference between the incremental cost of the selling utility and the decremental cost of the buying utility.

The Department urges the Commission to take this opportunity to break from past policies. For either long-term or short-term transactions, rates based on rolled-in, embedded costs cannot be justified on efficiency grounds,(14) nor is the Commission compelled by law to adhere to past policies when there are sound reasons for a change.(15) Rates for long-term transmission transactions should be based on long-run incremental costs. To reduce the need for explicit calculation of long-run incremental cost rates, the Commission should encourage long-term transmission access in the form of joint ownership or ownership-like arrangements, and it should encourage regional transmission groups and other voluntary arrangements. For short-term transactions, the Commission should allow owners of transmission rights broad discretion over pricing. Three-way split-savings arrangements, which have been permitted by the Commission, would be a reasonable practice.

I. Important Aspects of Electric Power Transmission

Although transmission facilities account for only a bit more than ten percent of total investment in the electric power industry, the importance of transmission to the industry cannot easily be overstated. Transmission permits loads to be served from remote generation sources. In this way, transmission makes it possible to reduce the total costs of generation through the use of larger, lower-cost generating plants; through the use of a more efficient mix of base load, intermediate load, and peaking plants; and through the use of low-cost generation resources, such as hydroelectric projects, that are tied to particular sites. Transmission also makes it possible to reduce significantly the costs of producing energy from existing plants by optimizing dispatch over a broader area. At the same time, transmission can also increase the reliability of service by broadening the scope and diversity of generating resources that can serve particular loads.

Improvements in the transmission system over that last quarter century, in the form of longer distance and higher voltage lines, have made meaningful competition in bulk power markets possible.(16) Indeed, competition in the supply of bulk power is now a reality, as utilities rely to a considerable extent on competitive procurements of new capacity. There is even a significant prospect that costly and cumbersome price regulation can be drastically curtailed by limiting its scope to just distribution and transmission, which account for roughly a fifth of industry costs.

Electric power transmission is generally thought of as a transportation service. The analogy is useful, but electric power transmission is unlike other kinds of transportation. When a utility transmits power through its system, it does not act simply as a conduit for the power. In order to receive power at one point and deliver it at another, the utility must adjust the operation of all of its generating plants. In addition to any cost associated with the transmission facilities themselves, a transmission transaction may increase system operating costs by requiring the transmitting utility to use a higher-cost mix of its own generation or by precluding it from using its transmission system to purchase power where it is relatively cheap or to sell power where it is relatively expensive. The reverse can be true as well; a transmission transaction can reduce system costs if it involves a flow opposite to the prevailing flow on a part of the system. Because loads and generation sources vary, the effects of a transmission transaction may be very different at different times of the day, week, or year. Thus, determining the cost of transmission is a complicated issue even apart from any issues about the transmission facilities themselves.

Transmission transactions also affect the available transfer capability of facilities owned by third parties in a number of complicated ways. Electric power follows the path of least resistance, and that path is often quite different from the path over which the contract assumes that it flows. Although a contract may specify that power flows from A to B over one utility's lines, it may actually flow over the lines of several utilities. Indeed, little of the power may flow over the lines of the "transmitting" utility. Transmission transactions hundreds of miles apart, having neither common origins nor destinations, may significantly affect each other nevertheless. These external effects are labeled "loop flow" or "parallel flow," and though they generally reduce available transfer capacity, they can have the opposite effect as well.

The efficient design of transmission facilities is also complex from an engineering standpoint. Any one transaction necessarily affects others, so individual transactions cannot be analyzed in isolation. Rather, a utility's system must be analyzed as a whole because that is the way in which it must be operated. Moreover, what any one utility does necessarily affects its neighbors and even distant systems to some extent. Finally, major additions of transmission facilities require very long lead times to allow for the acquisition of rights of way, regulatory approvals, design, and construction. As a result, long-term regional transmission planning is essential.

Competitive bulk power procurements can and should be accommodated in the transmission planning process. Bulk power markets have become increasingly competitive in recent years, and competitive procurement has become an important means of acquiring long-term bulk power supplies. Competition can flourish only if buyers and sellers have access to long-term, firm transmission, and competitors should have guaranteed opportunities to contract for long-term transmission rights on specified terms.

II. Basic Issues in Transmission Pricing

As noted above, transmission is increasingly provided as an unbundled service. As a result, transmission prices are becoming important signals for resource allocation, and transmission and generation investment decisions will respond to these pricing signals. Resources are likely to be significantly misallocated if improper transmission pricing signals are sent.

From the Department's perspective, the greatest danger is that the Commission will adopt transmission pricing policies that provide insufficient incentive to make efficient new transmission investments. This would undermine the beneficial effects of transmission, and it could significantly lessen competition in the supply of bulk power. If existing capacity is more than adequate to meet foreseeable demand, low prices are not a problem, but if the new transmission investments are efficient, prices must provide the incentive to make those investments. Prices for transmission from existing facilities provide potential investors with the best indication of how service using new facilities will be priced, once they are placed in service. Thus, the surest way to undermine the incentive to invest in new transmission facilities is to set excessively low prices for transmission using existing transmission facilities.(17)

There is, of course, also a danger that transmission prices will be too high, either due to the exercise of monopoly power, or due to inflexible regulation. This would discourage some efficient transactions, and it could lessen competition by limiting the geographic scope of effective competition. It is also possible for high prices to induce inefficient investments in new transmission facilities. There will be an incentive to build new transmission capacity if transmission capacity can be built more cheaply than purchased, and the incentive to build may exist even when existing facilities are available at a lower social cost. If necessary,(18) owners of transmission should be able to avoid this "uneconomic bypass" by pricing particular transmission transactions on the basis of not just costs, but also the willingness of customers to pay.

Transmission pricing should also serve to allocate limited capacity among alternative uses. Existing transmission facilities may not be able to accommodate all demand at particular times and places.(19) When such is the case, efficiency considerations dictate that those willing to pay the most should be the ones to use the system. Efficiency considerations also dictate that owners of transmission rights should be able to reserve transmission capacity for economy transactions if they are the most desired, or to reallocate transmission capacity to such uses when opportunities arise.

Transmission prices that are either too high or too low would lead to inefficient generation investment decisions. Utilities increasingly rely on competitive procurement, rather than construction, to satisfy demands for new generating capacity. Competing suppliers locate plants in response to pricing signals, especially signals from transmission pricing. If transmission prices do not properly reflect the particular costs associated with transmission at each potential plant site, inefficient plant siting choices will be made. The traditional practice of postage-stamp rates is likely to send the wrong signals because prices do not vary with location within a particular utility's service area, although transmission costs are likely to vary a great deal.

III. Pricing for Long-Term Transmission Transactions(20)

Utilities make commitments with respect to significant capacity additions that generally are for at least ten years and typically are for much longer. Economic efficiency requires that the prices on which they base decisions reflect the full economic cost of both generation and transmission. Thus, as a general matter, prices for long-term transmission transactions should be based on long-run incremental cost. Such rates maximize the efficiency of resource allocation, and they would prevail in competitive markets.

The historical cost of existing transmission facilities is likely to be less than long-run incremental cost, so traditional rolled-in, embedded cost rates are likely to be inefficient. The Commission's more recent practice of allowing rates to be based on incremental facilities costs or opportunity costs does not address the problem. Incremental facilities costs and opportunity costs are neither meant to be reasonable approximations to long-run incremental cost, nor are they likely to turn out that way. Moreover, a common end result of the new policies is inefficient, traditional, rolled-in, embedded-cost rates.

Determining long-run incremental cost can be difficult for a variety of reasons,(21) but a number of principles can be articulated. First, the relevant capacity increment is an entire transmission line because, in the long run, that is the smallest unit of capacity that can be added.(22) Second, the true economic cost of a particular transmission line can be assessed only within the context of the network in which it is embedded. Any one transmission line affects the transfer capacity on others and overall system reliability. In addition, incremental transmission affects the operation of generating plants and therefore the costs of generation.(23) All of these effects should be accounted for in transmission prices. Third, if transmission is becoming increasingly scarce to any significant extent because of political and environmental difficulties in adding new lines, then prices should exceed current long-run incremental cost.

Fourth, transmission capacity should be added in efficient increments, as determined in the long-term planning process, and the capacity of an efficiently sized line typically is greater than that needed by a particular system user. Consequently, a line may not be fully utilized when placed in service. When the date at which a line is placed in service is moved up to satisfy a particular user, the appropriate rate for that user should reflect not only that user's pro rata share of cost, but also the interest charges for the unused capacity for the amount of time by which the in-service date of the line was moved up.

The Commission should avoid the formidable task of actually setting long-run-incremental-cost rates whenever possible. This can be achieved through maximum possible utilization of joint ownership, or ownership-like arrangements, which eliminate, or greatly reduce, the need for regulatory price setting. Entities that participate in transmission projects in such ways should have as much flexibility to use their transmission rights as is feasible under the circumstances. Both their rights (e.g., to sell transmission services to others) and their responsibilities (e.g., to pay system costs) should be as close as reasonably possible to those associated with ownership.

Transmission access through ownership is most easily achieved on new lines, and the Commission should take whatever steps it can to assure that all interested parties have an opportunity to participate in significant new transmission projects on a pay-as-you-go basis. Many transmission projects already have been built as joint ventures, and others are in the planning stages. There seem to be no great difficulties in providing open transmission access in this way. The Commission should also encourage utilities to auction long-term, ownership- like rights to existing transmission facilities as a means of providing open access.(24) While auctions may not always be feasible, it is possible to design auctions in which competing buyers bid for differing transmission rights that involve the use of common facilities to some extent. aids can be ranked according to the ratio of bid price to a schedule of preannounced base prices, for example, estimates of long-run incremental cost associated with different paths.(25)

The Commission should announce that, if an entity chooses not to take advantage of opportunities for transmission access through joint ownership of new facilities or ownership-like rights, then it will not be given a second chance to participate on better terms, such as service at traditional rolled-in, embedded cost rates. When two entities have had the same opportunities to acquire ownership or ownership-like rights, the Commission should not force one to provide transmission service, or transfer transmission rights, to the other. Of course, the Commission should allow voluntary trades.

Joint ownership and ownership-like rights are not likely to totally supplant more traditional transmission service. The Commission should attempt to further limit the extent to which it undertakes the determination of long-run incremental costs by articulating pricing principles and encouraging voluntary agreements with respect to transmission services. Such agreements may be bilateral, or multilateral, within regional transmission groups. The Commission also should not be quick to find voluntarily negotiated transmission rates unduly discriminatory.(26) No two transactions are likely to be entirely the same, and prices should vary with any number of differences.

IV. Pricing for Short-Term Transmission Transactions(27)

As a general matter, economic theory teaches that short-run prices should be equal to short-run marginal cost. Marginal-cost pricing causes scarce capacity to be rationed by price, with those willing to pay the most being the ones to use the system. Thus, short-run marginal costs are the transmission pricing signals to which the hour-to-hour operation of generating plants should respond.(28) The short-run marginal cost of transmission is essentially just line losses if there is more than enough existing capacity to satisfy all demands at a price equal to line loses. If existing transmission facilities cannot accommodate all demand, the short-run marginal cost of transmission reflects this scarcity by including a congestion-cost component.

Despite the theoretical advantages of marginal-cost pricing for short-run transmission transactions, there are also serious difficulties, and the Department recommends that the Commission not dictate such pricing. One reason for this recommendation is that the revenue produced by short-run marginal-cost pricing may fall well short of total costs. In that event, the use of marginal-cost pricing would necessitate subsidies to transmission owners, and such subsidies are unlikely to be forthcoming. Another important reason is that marginal congestion costs are not easily measured.(29) They would have to be assessed for all lines at all possible times and are likely to fluctuate widely depending on the time of year and the time of day.(30) The administrative costs of making these assessments would be considerable.

Transmission capacity also has an option value, which should be recognized in pricing. Holders of transmission rights can use them to make emergency sales or purchases, or economy sales or purchases, and those can be very valuable opportunities. Thus, transmission capacity that is not in use at a particular time may still have significant value. A utility that maintains transmission capacity for economy transactions should not be required to use that capacity to serve someone else--long term or short term--unless the compensation exceeds the expected value of the capacity in making the economy transactions.

As a practical matter, there is also a real danger that any attempt by the Commission to impose short-run marginal-cost pricing would not properly account for congestion costs and option value, resulting in rates that are uncompensatory and that send inappropriate signals. Investments in existing transmission facilities are "sunk;" the capacity will not leave the industry if rates fall to the level of line losses or even below that level. Rates that low would seriously undermine the incentive to make new investments in transmission, and efficient long-term transmission transactions, which are vital to competitive markets for bulk power, could be precluded by the lack of available capacity. Moreover, if prices for short-term transactions were well below those for long-term transactions, there would be significant substitution from long-term to short-term transactions to take advantage of the price differential. Thus, in addition to not being compensated for congestion costs and lost option value, utilities also might not be compensated for capital costs associated with transactions that are, in truth, long-term.

If prices for short-term transmission transactions were set too low, there would also be a need for some form of nonprice rationing of capacity at certain times. The Commission would have to determine on an hourly basis how much capacity each utility must make available to others rather than use to serve native-load customers. The administrative costs would be substantial, and significant inefficiencies likely would result from inevitable errors of judgment.

For all of the foregoing reasons, the Department concludes that the Commission should give utilities broad discretion over pricing of short-run transmission transactions. This course of action offers significant potential efficiency gains as well as substantial savings in administrative costs. There is some risk that transmitting utilities will be able to exercise monopoly power in pricing some transactions,(31) but the Commission should accept that risk for several reasons.

First, rents generated by pricing above short-run marginal cost are not necessarily monopoly rents; some or all merely reflect recovery of system sunk costs. Sunk costs are also likely to be recovered in a relatively efficient way, with the highest prices being charged for the transmission transactions on which users place the highest values.

Second, the magnitude of any monopoly power would be strictly limited by the fact that any transmission user unhappy about paying high prices for short-term transmission could avoid doing so by acquiring long-term transmission rights, which would be always available at rates based on long-run incremental cost. Moreover, with state and federal regulation, any monopoly rents generally would be passed back to native-load customers.

Third, there is a distinct possibility that some monopoly power in short-term transmission markets is necessary to make the system function properly. With no monopoly power, there would be a strong tendency for short-run prices to be competed down to short-run marginal cost. Transmission users might expect to get transmission cheaper by continuously purchasing it short-term and not investing in long-run transmission rights. With transmission users having no incentive to invest in long-term rights, much efficient transmission capacity might not be built in the first place.

Finally, even if monopoly power is not necessary to make the system function properly, there are not likely to be significant social costs associated with the exercise of monopoly power on short-term transmission transactions. Monopoly pricing on short-run transactions need not entail an inefficient output restriction because transmitting utilities can (and currently do) price discriminate, and perfect price discrimination results in the socially efficient level of output.(32) Transmitting utilities also have a strong incentive to make efficient transactions in order to minimize operating costs.

From the standpoint of pricing efficiency, it may be best to have no constraints on pricing for short-term transactions. Nevertheless, a price cap set at the level of prices for long-term transactions may be useful for two reasons.(33) First, the price cap would reduce the possibility of monopoly rents. Second, and far more importantly, the price cap at long-run incremental cost eliminates the possibility that utilities may have a disincentive to make long-term transmission rights available because selling short term may be more profitable. Although the Commission can compel utilities to sell long-term transaction rights, it is certainly preferable that they have an incentive to do so vo1untarily.(34)

V. Collaboration Among Utilities on Transmission Pricing

A certain amount of cooperation among utilities is essential for efficient development and utilization of the transmission grid. Cooperation on pricing, however, raises significant antitrust issues, and many utilities have expressed concerns about the legality of transmission-related cooperative activities. Utilities wishing an indication of the Departments enforcement intentions on a specific proposal should formally request that the Department conduct a Business Review of their proposed conduct.(35) Outside the context of a particular proposal, the Department can provide only limited guidance.

The antitrust laws condemn as illegal per se most agreements among competitors with respect to prices or price terms,(36) but not those incident to legitimate joint ventures that promote consumer interests.(37) Thus, agreements on pricing and other terms of transmission access, reached in legitimate power pools or in regional transmission groups, would not be per se illegal. Instead, their legality would turn on whether the agreement "is one that promotes competition or one that suppresses competition."(38)

Agreements relating to transmission pricing that are reasonably necessary to make transmission services available certainly meet this test,(39) and the Department will not challenge such agreements. Cooperative activity that generally promotes competition in bulk power markets by facilitating transmission also are likely to be found lawful, just as pooling arrangements have been, even when they involve cooperative price setting.(40)

The Department will also not bring enforcement actions to prevent utilities from entering into discussions on various transmission-related issues, including: joint studies for the purpose of transmission planning; joint analyses of parallel flows and possible means for mitigation of parallel flow problems; and discussions among utilities regarding the formation and terms of regional transmission groups, and possible compensation systems for parallel flows.(41) Such studies, analyses, and discussions are constructive and certainly may lead to enhanced competition.

  Respectfully submitted,

Anne K. Bingaman
Assistant Attorney General

Robert E. Litan
Deputy Assistant Attorney General Designee
Antitrust Division

_____________"/s/"_____________
Mary E. Fitzpatrick
Assistant Chief
Economic Regulation Section

_____________"/s/"_____________
Gregory J. Werden
Director of Research
Economic Analysis Group

_____________"/s/"_____________
Jade Alice Eaton
Attorney
Transportation, Energy and Agriculture Section

_____________"/s/"_____________
Jonathan E. Henly
Economist
Economic Regulatory Section

_____________"/s/"_____________
Michael A. Einhorn
Economist
Economic Regulatory Section

Antitrust Division
U.S. Department of Justice
Room 9104 Judiciary Center Building
555 Fourth Street, NW
Washington, D.C. 20001
202-307-6349

November 4, 1993


FOOTNOTES

1. 58 Fed. Reg. 36,400 (July 7, 1993). A subsequent notice extended the comment period to November 8. 58 Fed. Reg. 42,726 (August 11, 1993).

2. The price for transmission services in pooling arrangements typically has been nominal, sometimes zero, plus losses. Revenue from these transactions was not meant to recover any part of the investment in transmission. The important compensation has been the reciprocal use of other utilities' transmission systems.

3. Northeast Utilities Service Co., 56 FERC 1 61,269, at 62,0 1 1--24 (1992); Utah Power & Light Co., 45 FERC 1 61,095, at 61,280--83, 61,290--95 (1988).

4. See, e.g., Entergy Services, Inc., 58 FERC 61,234, 61,758--59 (1992); Pennsylvania Electric Co., 58 FERC 61,278 (1992); PSI Energy, Inc., 51 FERC 1 61,367, at 62,190 (1990).

5. See Florida Municipal Power Agency v. Florida Power & Light Co., 65 FERC 1 61,125 (1993).

6. 722, Pub. L. No. 102-486, 106 Stat. 2776, 2916 (1992).

7. Over the next two decades, purchases from NUGs are expected to account for over 20% of new generating capacity. U.S. Dep't of Energy, Energy Information Administration, Annual Outlook of U.S. Electric Power 1991, at xi (1991); North American Electric Reliability Council, 1990 Electricity Supply and Demand 45 (Nov. 1990).

8. A recent variation on this theme has been "subfunctionalized" rates, in which there is a separate charge for each major component of the transmission system. Pacific Gas & Electric Co., 53 FERC 61,146 at 61,520-21(1990).

9. While very much the exception, there are some distance-sensitive transmission rates under the Commission's jurisdiction. See, e.g., Southern California Edison Co., 50 FERC 61,138, at 61,409 (1990).

10. Transmission was priced in essentially the same way when sold bundled with generation (and possibly other services), since retail and wholesale rates were based on the same rolled-in, embedded cost pricing principles.

11. See Public Service Electric & Gas Co., 62 FERC 61,014 (1993); Pennsylvania Electric Co., 58 FERC 61,278, at 61,873 (1992); Northeast Utilities Service Co., 58 FERC ¶ 61,069 (1992).

12. See Public Service Electric & Gas Co., 62 FERC 1 61,014 (1993); Public Service Company of Colorado, 62 FERC ¶ 61,113 (1993); Pennsylvania Electric Co., 58 FERC ¶ 61,278 (1992); Northeast Utilities Service Co., 58 FERC ¶ 61,206 (1992).

13. E.g. Utah Power & Light Co., 45 FERC ¶ 61,095, at 61,295 (1988).

14. In addition, postage-stamp rates are justified only if the administrative expense of ascertaining locational differences in transmission costs is so great that there is no net gain in efficiency from the use of transmission rates that reflect locational differences in transmission costs.

15. See Environmental Action v. FERC, 996 F.2d 401 (D.C. Cir. 1993).

16. See Leonard W. Weiss, Antitrust in the Electric Power Industry, in Promoting Competition in Regulated Markets 135 (Almarin Phillips, ed., 1975); Richard Schmalensee and Bennett W. Golub, Estimating Effective Competition in Deregulated Wholesale Electricity Markets, 15 Rand J. Econ. 12 (1984).

17. Native-load customers are obligated to pay for these transmission investments over time through their retail and wholesale rates. Because they have undertaking the obligation to pay for transmission investments, native-load customers should get the benefits of the efficient transactions that the transmission facilities make possible, including economy sales and purchases and emergency sales and purchases. Transmission capacity is unlikely to be truly excess at the times when, and in the places where, it is most likely to be requested, and its price should reflect whatever value it has. Transmission rates that are too low force the native-load customers to subsidize others, who have not invested in the transmission system.

18. This may not be necessary for several reasons, not the least of which is that required regulatory approvals for new transmission facilities may not be forthcoming.

19. The cost of relieving a bottleneck may exceed the benefit, particularly if the bottleneck gives rise to congestion only infrequently. Moreover, even if it is economical to relieve a bottleneck, doing so may take considerable time. Therefore, scarce capacity must be rationed, and price should be the rationing device.

20. The Department distinguishes between long-term and short-term transactions but not between firm and nonfirm transactions. In practice, short-term transactions (at least the most common short-term transactions with durations of from an hour to a week) generally are nonfirm, and long-term transactions (at least the more typical long-term transactions of many years duration) tend to be firm. From a pricing standpoint, however, the important issue is whether a transaction involves a long-term commitment of transmission capacity.

21. Even ascertaining transmission capacity usage can be challenging, as it is with so-called "network service," in which the origin or delivery points for a transmission transaction may be changed from day to day or hour to hour.

22. In particular, the cost of adding capacity by relieving a minor bottleneck in the existing network is not the long-run incremental cost.

23. In addition to the need to reoptimize the dispatch of the generating resources on the system, as mentioned above, a transmitting utility may have to supply reactive power to support transmission transactions.

24. There is a danger that utilities would limit the amount of capacity they make available to drive up the price. Thus, the amount of capacity available to be auctioned, or otherwise made available, may have to be determined by the Commission.

25. There should be minimum bids in such auctions, perhaps based on traditional rolled-in, embedded-cost rates. Without minimum bids, there is a significant risk that transmission capacity that can best be used by its present owners will be used instead by others who place less value on it and are willing to pay little for it. Maximum bids may be desirable as well. Prices in such auctions might be reasonably capped at long-run incremental cost (if new capacity could be built instead) or at some multiple of long-run incremental cost (if new capacity could not be built for some reason). Such caps have the significant disadvantage that they require a determination of long-run incremental costs, so a multiple of embedded costs might be preferable.

26. If necessary to avoid uneconomic bypass, owners of transmission should be able to price particular transactions below long-run incremental cost. Transmission prices may provide an incentive for new transmission to be built by some prospective users even though existing facilities are available at a lower social cost. This is a likely scenario with traditional postage-stamp rates, and it is possible even with rates based on long-term incremental costs.

27. Exclusive reliance on long-term transmission rights through joint ownership or an ownership-like arrangements would reduce the need for any pricing system for short-term transactions. Owners of transmission rights would efficiently utilize those rights, treating the capacity payments to which they have committed as fixed costs, and responding to true short-run marginal costs.

28. See generally William W. Hogan, Contract Networks for Electric Power Transmission, 4 J. Regulatory Econ. 211(1992).

29. The Department understands that Georgia Power is experimenting with real-time pricing for industrial customers and that there is a transmission-congestion-cost component in their real-time prices. This experiment should prove very instructive.

30. Congestion cost should not be ignored on the grounds that a transmission system is underutilized on average. There, nevertheless, may be significant congestion problems at particular bottlenecks and at particular times. Ignoring occasional congestion is likely to significantly distort decisions to invest in the elimination of bottlenecks.

31. A more descriptive term in many cases would be "monopsony power" because the power would be exercised over sellers of power needing transmission access to reach potential customers.

32. As stated previously, the Commission should not be quick to find undue discrimination.

33. Capping prices this way has a serious drawback in that it necessitates a determination of long-run incremental cost prices, and as emphasized above, there are significant difficulties in making such a determination. On the other hand, precision is not nearly as important when the long-run incremental costs are used as price caps, which generally are not binding, rather than as prescribed prices. Rough estimates of long-run incremental cost should suffice, provided that there are safeguards against underestimation.

34. A price cap could prevent prices from efficiently allocating scarce transmission resources in some instances. To mitigate the potential misallocative effects of a price cap, the Commission should abstain from compelling transmission access for short-term transactions.

35. See 28 C.F.R. 50.6 (1993).

36. Catalano, Inc. v. Target Sales, Inc., 446 U.S. 643 (1980); United States v. Trenton Potteries Co., 273 U.S. 392, 396--401 (1927).

37. NCAA v. Board of Regents of the University of Oklahoma, 468 U.S. 85 (1984); Broadcast Music, Inc. v. Columbia Broadcasting System, 441 U.S. 1 (1979).

38. National Society of Professional Engineers v. United States, 435 U.S. 679, 691 (1978). See also Chicago Board of Trade v. United States, 246 U.S. 231 (1918).

39. Broadcast Music, Inc. v. Columbia Broadcasting System, 441 U.S. 1, 23 (1979).

40. See Central Iowa Power Cooperative v. FERC, 606 F.2d 1156, 1163 (D.C. Cir. 1979).

41. The Department does not recommend that the Commission take any specific action at this time to deal with such issues. The Department, however, encourages the Commission to consider the desirability of a compensation system for these external effects and to permit utilities to adopt such systems on an experimental basis. If the Commission finds such a system desirable, the Commission should also consider imposing it. Voluntary adoption of a compensation system may be frustrated by the ability of utilities that would be net payers in any system to veto its adoption. If the Commission were to impose a compensation system, however, there should be some opportunity for regional transmission groups or power pools to opt out of the system. They may find in-kind compensation or no compensation to be preferable under their.particular circumstances and should be able to use such alternatives.

Updated June 25, 2015