Remarks of
Carolyn A. Berry, Ph.D.
Office of Economic Policy
Federal Energy Regulatory Commission

“Congestion, Transmission Loading Relief, and Reliability”

INFOCAST Conference on Congestion Management
Washington, DC
March 25, 1999

	
I.
	There is a fallacy being perpetuated in the electric industry.  It goes as follows.  I built it, I own it, and therefore, I can use it as I please.  On first impression, the statement appears to be sound.  Private ownership and self-determination are fundamental tenets of our society.  But, in fact, when it comes to transmission assets, this is not true.  The reason is market failure.
	There are many circumstances in which the market can fail to achieve a competitive outcome:  imperfect information about prices or quality, economies of scale, the ability to manipulate the market price, or externalities among others.  It is principally the externality problem that plagues the transmission market.
	An externality occurs when the cost or benefit of an activity is borne in part by someone other than the person undertaking the activity. Externalities are found in many places in our economy.  A simple example is the loud party next door.  In the course of enjoying a blasting stereo, the music goers inflict a negative externality on their neighbors.  Since people to some extent have the right to peace and quiet, the ability of load music lovers to use their asset as they please is restricted by law.  
	The classical example of an externality is pollution.  A firm that pollutes the air in its production process, can increase the costs of other firms, say flower producers, or can increase the health costs of individuals.  The clearing of rain forests to make room for agriculture or development effects the world environment.  It degrades the world’s ecosystem and it eliminates a world treasure.  Social costs are ignored in the pursuit of private interests. 
	The same theory applies to the use of transmission.  When an integrated utility equates the private cost of using its transmission assets to the benefits, it may overuse the transmission asset because the utility does not consider the negative impacts that it has on third parties.   The marginal social cost does not equal the marginal benefit.  The market achieves an inefficient solution.
	The specification and allocation of clearly defined property rights can eliminate the externality problem.  Ronald Coase proved this in the famous Coase Theorem in 1960.  He showed that an efficient outcome can be achieved through competitive bargaining when property rights are clearly defined.  For example, if a manufacturing firm is given the right to pollute a river, then a boat rental firm can negotiate with it to reduce the amount of pollution.  The boat rental firm will be willing to pay to reduce pollution to the point where the marginal benefit is equal to the marginal cost of reducing pollution, the socially efficient outcome.
	At the turn of the century the radio spectrum was a little valued common good.  The development of long-distance radio transmitters brought value to this resource.  Progressive invasion (both a greater variety of wavelengths and the technical ability to discern between closer wavelengths) led to significant problems of interference among users.  To solve the problem, governments began to allocate portions of the spectrum to specific individuals or firms.  In this way, the externality was internalized.
	Unfortunately, even if property rights are clearly defined, an efficient outcome will not be achieved if, 1) transactions costs or bargaining costs are high, (for example, it is difficult to bring together a polluting firm and the thousands of people that it might effect) or 2) if firms engage in strategic bargaining behavior, and 3) if either side lacks information about the costs or benefits of reducing the externality.  In this case, tax or subsidy schemes by the government can bring these costs into agreement.  Or mergers can internalize the externalities.  For example, recreational site developers (ski areas, golf courses) often own and operate the motels, gas stations, and shops near their projects.  In this way, they are able to internalize the positive benefits that such developments provide to the surrounding service industries. 
	All three of these conditions hold in transmission markets:  high bargaining costs, strategic behavior, and incomplete information.  The solution for transmission markets is nodal pricing and regional transmission organizations.  Nodal pricing reveals the true social cost of using constrained transmission assets.  With this information, property rights can be defined, allocated and traded.  Bargaining costs are radically reduced.  RTOs serve the same purpose as mergers.  They internalize the externalities, loop flow, over large areas and help the market move toward a more efficient allocation of resources.      
	I want to pause for a moment and give you an economist’s view of the topic of this conference.  It has been said that people fear three things:  rejection, change, and success.  I would like to add one more thing to that list.  Congestion.  Unlike power engineers who have historically built the transmission system (arguable inefficiently) to avoid congestion, an economist’s view is that congestion is good.  We should expect to see it.  We should expect to see more of it.  We do not want to build transmission to avoid congestion when the costs of doing so are less than the marginal benefit.  We need to develop redispatch methods that work instantaneously, that use the price mechanism, and that market participants and power engineers have confidence in.  For example, we could adopt nodal pricing nationwide. 
	Zonal pricing is not the answer to the market failure in transmission.  I am always surprised by proponents of zonal pricing that say that nodal pricing is too hard.  These people vastly underestimate the ability of individuals to work out solutions to seemingly complex problems.  Frankly, if engineers can work out stability conditions in power networks, surely savvy traders can work their way through nodal pricing.
	Zonal pricing sets up a system where property rights cannot be clearly defined.  This occurs by definition, since zonal pricing ignores externalities within zones.  Zonal pricing does not curb market power, in fact it enhances market power.  It will allow the lowest cost generator to receive the price of the highest cost generator in the zone.  Zonal pricing does not necessarily increase liquidity in the market.  The introduction of nodal pricing in PJM was reported to have vastly reduced liquidity.  But this was a transitional issue.  The market has already adjusted to the new environment.  The real problem with zonal pricing is take it takes a very myopic view of electricity markets.  Basing zones on historical data and trading patterns is the wrong way to go.  Zones do not easily adapt to evolving markets.  Nodes do.  Zones do not inform investors about where to site new generation.  And the location of generation within a zone matters.  Consider the state of California.  It is divided into two zones, north and south.  I don’t think that anyone would disagree that the exact location of a new generator in a zone matters.  The precise location within the zone will have dramatically different effects on the system.  Yet, there are no price signals in California to guide the locational investment decision.  Nodes on the other hand give precise investment location signals.     
	In my view, zonal pricing sacrifices an efficient market structure, to pursue other goals.  In particular, equity or distributional goals.  In most places where zonal pricing has been adopted, Australia, California, etc., the choice was made in order to protect a particular group of customers from high prices.  This is equivalent to reducing the size of the pie or the total potential benefits of the market, to get a particular division of the pie.  In static world this rationale may be laudable, but in an evolving world, where firms maximize profits and firms produce innovations, the distributional problem will be creatively solved and everyone in the market will be better off.
	This same principle applies to all the new market rules that are being developed.  The primary goal should be to “get the market right”.  Equity problems should be considered separately.

II.
	Transmission loading relief, or curtailing transactions based on a set of arbitrary criteria is a primitive way to handle congestion.  I realize that it was the best thing we had last summer, but it wasn’t very good.  Consider an airline flight that is overbooked.  One option to relieve congestion is to bump the individuals who were last to purchase tickets.  (They don’t have any grandfathered rights.)  The airlines wouldn’t do that since those people probably paid the most for their tickets.  Another option is to bump the people that paid the least for their tickets.  Those people are kind of similar to nonfirm transmission customers.  Well, that wouldn’t be a popular strategy since there was a commitment there and airlines want to make people happy.  Airlines operate in a competitive environment.  Yet another option is to bump the people who purchased the biggest blocks of tickets.  Say Dynegy purchased 6 tickets, so the airline decides to target Dynegy and cut some of their seats first.  Well that would be ridiculous, since the airline knows that the size of the transaction has nothing to do with the value of the transaction.  This is precisely the point for TLR.  The airlines use a price mechanism to clear the market.  This way, those people who value the flight the least choose to give up their seats and the efficient outcome is achieved.  
	Pro rata curtailment embodied in transmission loading relief is inefficient.  It does not give the individuals that most highly value the transmission capacity the opportunity to use and pay for that capacity.  It results in non-optimal dispatch of generation.  It is also perceived as arbitrary and unfair.  And since TLR has not been applied to all transactions, it is not only unfair, but also terribly inefficient.  A centralized pricing mechanism would greatly enhance reliability.  The Commission has applauded the fair, efficient, and reliable nodal pricing and redispatch structure developed by PJM.  They are way ahead of the curve. 
	In its December 1998 TLR order, FERC recognized these problems.  FERC ordered public utilities to develop protocols for curtailing native load and network transactions.    FERC also ordered public utilities to identify and file interim redispatch solutions by March 1 of this year.
	In response, NERC filed a Policy Statement with the Commission.  In it NERC proposes to address the native load/network service problem by calculating the share of the transmission constraint that is attributable to firm point-to-point transactions using the Interchange Distribution Calculator.  Then, the remaining share of the constraint is due to Native Load and Network service.  With this information, the transmission provider will be able to curtail these transactions on a pro rata basis.  The difficulty is that the transmission provider will not be able to identify the portion of the constraint that is due to native load and network service in adjacent control areas.  NERC is studying the issue.  However, it will be essential to come up with some solution, otherwise, there will be no way to verify to actual portion of the constraint due to transmission owners own native load and network service.  This will lead to an arbitrary decision about how much the utility actually has to curtail its own transactions.  In addition, although this is a more equitable solution, it’s not necessarily more efficient.  The curtailments are still done on a pro rata basis and thus do not reflect the value of the underlying transaction.  
	NERC has also proposed a pilot redispatch program, that contains a “market redispatch option”.  A transmission customer can arrange a bilateral transaction that produces counterflows, which it can use in lieu of being curtailed.  This would apply to 13 identified flow gates that are most likely to be constrained.    NERC proposes to post information on flows and generation shift factors to allow parties to set up appropriate transactions.  There is a concern about how fresh and how complete this data will be.  The other big flaw with this proposal is that it is based on the inefficient pro rata curtailment determination.  That is once a market participant is told how much of certain transactions it must curtail, it can find the most efficient solution to the problem.  But the initial determination is not based on the value of the transaction.  So there is no way that market participants with high value transactions can buy their way through the constraint.  A more efficient solution would be achieved if parties were allowed to trade their curtailments in addition to arranging redispatch options.   
	In January, the NERC Interim Market Interface Committee made recommendations on congestion management.  Among those recommendations, were two options to redispatch generation to relieve congestion:  a Market Redispatch Option, which is a bilateral option and a System Redispatch Option, which would allow market participants to select options to insure against curtailment, direct the adjustment of generation to provide relief, and provide payment mechanisms for the participating units.  Unfortunately no guidance was given for this option in NERC’s Policy Statement.
	Other criticisms of TLR include: the need for objective criteria and the accountability of Security Coordinators.  The use of TLR needs to be justified and verified.  Violations of procedures should be penalized.  There is need for a credible enforcement mechanism.  When mistakes are made, effected parties should have recourse to compensation, to be paid for by the transmission provider, for whom a Security Coordinator is acting as agent.
	To truly ensure nondiscrimination, redispatch and key curtailment decisions must be made by an independent body, that is, Security Coordinators need to be independent from utilities. This could happen in the development of broad regional transmission organizations.  	
	A final note on TLR.  If a utility doesn;t want to curtail native load or network use of the system, it can simply look for a contingency on its system that allows it to reduce available transmission capacity, limiting the ability of third parties to schedule transactions.  In fact, if a utility doesn’t call for a TLR it might be suspect of withholding transmission capacity from the market—so little is offered that that TLR is never invoked.  This gets us back to the continuing problem of defining ATC, which goes hand in hand with capacity benefit margin calculation.  

III.
	Although the Capacity Benefit Margin if defined differently by each utility that uses it, in general, it is the reduction of Total Transmission Capability that acts as a substitute for generation reserve margins within a utility’s control area.  It is based on the assumption, that during generation outages, the utility will be able to call on neighboring utilities to supply power into its control area.  This is an antiquated concept that applies to a system of relatively isolated control areas and independent operation.  
	The CBM is an example of a good without a price, the externality problem.  The utility removes capacity from the transmission system in a private comparison of the costs of generation reserves and the costs of removing the capacity.  The utility does not consider the additional costs that this imposes on third parties.  This implies that the utility will overuse the CBM or leave too much capacity idle.  And further, its cost comparison must be somewhat arbitrary because the utility does not know what the price of power will be, if it needs it, or even if it will be available, because no specific contracts are actually in place.  
	The use of a capacity benefit margin is completely discretionary.  NERC does not provide a specific methodology for computing CBM nor does it require its use.  Utilities simply have the option to use it if they wish. More troubling is the fact that it is a transmission provider’s merchant function that calculates the benefits from using CBM and determines the amount of capacity that is set aside.  Since it is the merchant function that competes with alternative energy providers, CBM can be used to reduce competition.  The CBM is not compatible with competitive energy markets.  
	The adjustments that are made to total transmission capacity are substantial.  PJM removes 3500 MW of firm transmission capacity for this purpose.  ComEd removes 4500 MW.  Entergy removes 2900 MW.  This is a lot of capacity.  We need to move toward a solution that creates a price for this idle capacity.  We need to internalize the externality.  The solution could have distributional effects, but it could probably be most equitably dealt with by a regional transmission organization that set up objective and consistent criteria. 
	Although it might be somewhat painful for utilities to move away from CBM as it is currently used, it stands to create immense benefits by shining the light on the generation reserve issue.  What is the true value of reserves to the users of energy?  Are the assumptions used to determine reserve requirements appropriate?  As the demand side is given more options to get into the market, and is more informed about the price they are paying for reliability, we may find that the amount of needed reserves is much less than currently required.   

IV.
	The Commission will soon release a Notice of Proposed Rulemaking on Regional Transmission Organizations.  As part of this process it has been consulting State Commissions.  The results of those consultations have been varied in the amount of involvement that Commissions believe that FERC should have in the process, although no one denies the benefits of regional integration.  In general, the Midwest wants FERC to take a very active, prescriptive, and immediate role, whereas the Southeast feels that it can proceed on its own.  Western states want leadership, but lots of flexibility.  The restructured Eastern Pools think that RTOs are great but they don’t want new rules put on the structures that they’ve already created.  
	What is the role of the Federal Government and in particular FERC?  We should try to internalize the externalities and make the economic pie as big as possible.  We should identify missing markets and provide leadership in creating them. We should not allow parties to compromise the integrity of the market in pursuit of economic rents.  We should try to get all transmission into the market. Currently about one third of the system is unregulated by FERC.  FERC needs to ensure that the markets that are created are functioning competitively.  As the identity of utilities is changing, so to is the identity of FERC.  The Commission in the future will play less of a reactive role, and move into a more proactive role with respect to the firms that it regulates.  As part of the internal restructuring going on at the Commission and in response to requirements of the Government Performance and Results Act, the Commission now produces a strategic plan, which lays out goals and objectives to be achieved over a five-year horizon.  The Commission has created an office of Strategy and Organization Management to integrate all of its activities across natural gas, electricity, hydro and oil and move them in a common direction.   This is a paradigm shift.  It will necessitate a retooling of skills and a change in culture.  The Commission has accepted that challenge.
	I disagree with those parties that believe that the natural evolution of markets will get us to where we need to be.  There is a role for government in the creation of new markets.  We cannot achieve the goal of Order 888: nondiscriminatory comparable access to the transmission system, until regional institutions are formed.  Given the multitude of parties involved, variety of interests, and the potentially prohibitive bargaining costs, some up front guidelines established by FERC can move the market forward at a much faster rate.  The path of development matters.  Once institutions are formed, rules are put in place, and interests are sunk, it is very difficult to change the game.  We should try to get the most efficient structure in place from the outset.
	Are there fundamental truths in electricity markets? Yes.  There is loop flow.  	For markets to work competitively and reliably, every market participant must accept that its actions affect others.  You can’t do as you please.  Nodal pricing most effectively deals with this fundamental truth.  Nodal pricing will work best with the establishment of broad regional transmission organizations.
  
Thank you.