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Toward regional transmission provision and its pricing in New England
UtilitiesPolicy,Vol. 6, No. 3, pp. 245-256, 1997 Pergamon PIh S0957-1787(97)00020-9
© 1997 Elsevier Science Ltd. All rights reserved Printed in Great Britain 0957-1787/97 $17.00+0.00
Toward regional transmission provision and its pricing in New England Marija D. Ilia, Yong T. Yoon, Assef Zobian and Mary Ellen Paravalos
In this paper first a brief description of the present admin&trative division within the New England Power Pool (NEPOOL) is given. The NEPOOL proposal for restructured transmission provisions and pricing at the regional level is assessed in light of these administrative divisions. In the proposal differentiation among the types o f transactions to be served by the Regional Network Service (RNS) is made for the next 5 years to reflect previous ownership rights as the network evolves into a single administrative entity. Next, most likely transmission congestion interfaces within the New England region (NE) are described. Although the present proposal does not offer specific solutions for dealing with congestion, two different approaches to this problem under consideration are indicated and analyzed. Finally, results o f an earlier numerical study using realistic transmission costs of the ArE transmission grid (Pool Transmission Facility--PTF) are described to illustrate dependence of access tariffs on the cost allocation method used. The paper concludes with the authors' assessment o f what remains to be done. © 1997 Elsevier Science Ltd. All rights reserved. Keywords."Open access; Transmission pricing; Fixed cost allocation; Contract path; Postage stamp rate; MW-mile method, Wheeling; Transactions, Native load Introduction
As the electric power industry undergoes a transition to the mandatory provision o f open access transmission to all on an equitable basis, the allocation o f the cost of this service among the present owners o f horizontally * M. D. lli~:, Y. T. Yoon and A. Zobian are with the Massachusetts
Institute of Technology,Cambridge, MA 02139, USA. M. E. Parvalos is with the New England Power Service Company,Westborough, MA 01582, USA.
structured t power systems remains an important issue. Methods under consideration range from rather simple to fairly complex, and they are often advocated by parties who are the obvious financial benefactors o f using a specific method. In this paper, a brief description of a hierarchical organization within the New England Power Pool (NEPOOL) is first provided. Present and future users of the Regional Network Services (RNS) are categorized according to their belonging within the network hierarchy as well as according to their N E P O O L membership status. The restructured network service has recently been proposed to the Federal Energy Regulatory Commission (FERC), and it is intended to facilitate energy markets in a non-discriminatory manner. A summary o f this restructured New England Power Pool (NEPOOL) proposal for transmission provision is given. The proposal recognizes the existence o f the present horizontal structure within the New England region (NE) and develops non-discriminatory access and the open access tariff to all following a 5-year transition period. The access tariff for the first 5 years include transitional charges to certain types of transactions and non-uniform access tariffs to certain users. Next, a preliminary description of congestion interfaces within NE is given, together with an elaboration o f how these may change as the energy market evolves in the region. This is used to discuss the reasoning behind 2 strawman proposals for congestion pricing under consideration 2 by the NE groups formed to facilitate a workable transition to regional open access. Finally, the major portion o f this paper describes results o f a numerical study concerned with allocation o f embedded cost in the NE area for a set of hypothetical transactions in the region 3. The results enable one to estimate dependence o f transmission access fees on cost allocation method used and interpret details o f the present proposal in the context o f present administrative 245
Transmission pricing in New England divisions within the region. The paper closes with the authors' assessment that the interim proposal for transmission provision is created under very tight deadlines imposed by the FERC. Consequently, they may need to be thought through and modified as NEPOOL gains more experience with energy markets. As described in this paper, the proposal for transmission provision is made under very strong assumptions about the energy markets that the transmission system must serve. Particularly critical is the assumption of all market participants being price takers. Much work remains to be done to assess this assumption: the interdependence of its validity and effective pricing for transmission congestion. The NE region realizes the need to create governance mechanisms at its Independent System Operator (ISO) level, which would enable the evolution of present rules into better ones. As we all know, once something is in place, it is hard to change it. In light of this, and given the many open questions that stem from the novelty of the problems facing the industry, it is essential to provide for an evolution of this sort.
NEPOOL participants and non-participants There are presently over 130 entities that are participants in NEPOOL, meaning that their energy service is scheduled by NEPOOL. These participants include all of the traditional integrated electric utilities and most of the publicly owned electric systems in the NEPOOL control area, as well as a number of independent power producers, power marketers, brokers and load aggregators. NEPOOL uses the term 'bilateral transaction' to indicate a single market player (load/supplier) that is scheduled by NEPOOL and has a 'bilateral' financial agreement with others in the market for energy price hedging purposes. A direct physical transaction between 2 or more market players is referred to as 'selfscheduled' transaction. One could identify several types of transactions to be served by the transmission provider. They are differentiated on the basis of their geographic scope, with those transactions presently served by a Local Network (a utility within a pool) distinguished from those served by more than one Local Network (referred to as interchange transactions). Moreover, through or out transactions involving entities of outside NEPOOL are distinguished from interchange transactions. Among the through or out transactions further differentiation is made to single out so called excepted transactions which are identified as having invested into the regional transmission facilities and therefore having a special status during the 5-year transition period (not exclusively). At first glance this may appear to be a somewhat
246
unnecessarily complex categorization of transactions when all transactions are supposed to be served on equal basis. Nevertheless, this differentiation reflects an attempt to recover sunk transmission cost by owners of local networks when merging into a single RNS. Similar to the present proposal, which only deals with access fee allocation, it is likely that future proposals for congestion pricing may also attempt to preserve this differentiation, at least during the 5-year period 4.
New England Power Pool Transmission Facilities (PTF) The transmission in NE under the NEPOOL arrangement prior to the most recent proposal for restructuring has been provided over facilities defined as 'PTF' or 'Pool Transmission Facilities'. PTF includes "all transmission lines owned or leased by the NEPOOL Participants which contribute to the parallel carrying ability of the bulk power system within the NEPOOL Control Area and are rated 69 kV and above, along with the related transformers, circuit breakers and associated equipment" (NEPOOL Agreement, 1997). The existence of PTF implies functional unbundling of generation and transmission in NE. The New England Power Pool Transmission Facilities consist of those of 9 major transmission owning companies: Bangor Hydro Electric Company (BH), Boston Edison Company (BECO), Central Maine Power Company (CMP), Commonwealth Energy System Companies (CES), Eastern Utilities Associates Companies (EUA), New England Power Company (NEP), Northeast Utilities (NU), The United Illuminating Company (UI), and Vermont Electric Power Company (VELCO). Figure 1 shows the approximate horizontal structure (ownership division) of the PTF into these 9 major companies. Figure 1 also shows approximate locations of 7 hypothetical transactions to be studied in the later part of the paper. Table 1 summarizes the generation and the load entry points of these transactions. All transactions involve the power transfer of 100 MW or 1 +0 ipu. For purposes of determining the necessary cost recovery of the transmission providing utilities, the fixed costs of 9 major companies in the PTF are given as shown in Table 25. The figures represent an estimated company annual carrying cost for those PTF it owns.
System characteristics NEPOOL is an association of virtually all electric systems in NE, accounting for more than 99.5% of electric power production, imports, and transmission in the 6-state region. NEPOOL's primary responsibilities are to coordinate, monitor, and direct the operations of most of the generating and bulk transmission facilities in the region to assure both adequate reliability and maximum practical economy of bulk power supply. The
Transmission pricing in New England
electric bulk power facilities of all member companies are operated as a single power system by central dispatch of the lowest cost generating and transmission equipment available at any give time. This includes the sharing of operating reserves, economic imports through interconnections, and coordination of generator and transmission maintenance scheduling. Generation and transmission expansion plans of the various member systems are evaluated for consistency with NEPOOL's and the Northeast Power Coordination Council's (NPCC) reliability criteria and for consistency with the efficient operation of the power system. The NEPOOL bulk power supply system serves a diverse region that ranges from rural to dense urban, integrating widely dispersed and varied types of power supply resources to serve its load. The NE summer peak load geographic distribution is approximately 20% in the north: ME, NH, and VT, and 80% in the south: MA, CT, and RI. The winter peak load distribution is approximately 25% and 75% in the north and south, respectively. Although the land area of the north is larger than the south, the relatively larger southern load reflects
greater development and concentration in the urban areas. The amounts of generation installed in the north and the south are roughly proportionate to the respective area loads. Hydroelectric and baseload nuclear plants compose a relatively large proportion on the northern generation, especially compared to the south. This contributes to an economic dispatch of generation at various load levels that may not reflect the same geographic proportions as the installed capacity. The economic dispatch, including contractual and economy interchange with neighboring utilities and considering the generation availability results in multiple intra-NE power transfers of varying direction, magnitude, and duration. The NEPOOL bulk transmission system is comprised mostly of 115 kV, 230 kV, and 345 kV circuits• Transmission lines in the north are generally longer in length and fewer in number than in the south. The increased transmission density in the south reflects the larger load and power supply concentrations• NEPOOL is interconnected with NY through 2 325 kV ties, one 230 kV tie, one 138 kV tie, and 3 115 kV ties. Currently, NEPOOL
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Figure 1. The New England Power Pool Transmission Facilities (PTF) diagram. 247
Transmission pricing in New England Table l. The generation and load points of 7 hypothetical wheeling transactions Purchase
I. 2. 3. 4. 5. 6. 7.
Buyer
From New York Eastern UtilitiesAssociates VermontElectric Power CommonwealthEnergy System Maine Yankee unit New EnglandPower ConnecticutYankee unit United Illuminating Seabrook unit Hudson Municipal(off NEP system) Seabrook unit New EnglandPower FromNew Brunswick Boston EdisonCompany
and New Brunswick are connected through one 345 kV tie with a second 345 kV tie planned. There are also 2 HVDC interconnections with Quebec: a 225 M W backto-back converter at Highgate in northern VT, and a _+450 kV DC line with terminal configurations allowing non-simultaneous operation of either a 690 M W connection at Cornerford in northern NH or a 2000 MW connection at Sandy Pond in eastern MA. Proposed NEPOOL open access tariff
transmission provisions and
The material in this section draws heavily on the actual document submitted to FERC (NEPOOL Agreement, 1997) which states: These provisions are intended to provide a regional arrangement which will cover, on a comparable, non-discriminatory basis, all regional uses of the NEPOOL Transmission System. The arrangement has been designed and will be implemented to encourage and promote competition in the electric market to the benefit of ultimate users of electric energy. Any new regional use of the NEPOOL Transmission System must be furnished and taken by Participants under the NEPOOL Tariff and cannot be furnished by the Participants individually. The NEPOOL Tariff and Restated NEPOOL Agreement also include various transitional arrangements which are intended to phase in over 5- or 10-year periods the financial impacts of the changes resulting from furnishing of regional service under the NEPOOL Tariff. Under the historic regime, most regional uses of the NEPOOL Transmission System had to be obtained and paid for under the individual
tariffs of the Participants. Under the new regime, the service will be a NEPOOL service at rates which will not vary with distance and will cover all regional uses of the NEPOOL Transmission system. The NEPOOL Tariff has been based on the Open Access pro forma tariff in Appendix D to Order No. 888. When the transmission provisions of the Restated NEPOOL Agreement and the NEPOOL Tariff become effective, the entire existing embedded cost of the NEPOOL PTF transmission system, net of revenues derived from through NE (i.e. Canada to NY) and out of NE wheeling, will be assigned entirely to load. This assignment to load will be on the basis of average cost within each of the 9 corporate ownership zones during the first 5 years. Thereafter, there are 2 alternatives which will be presented to FERC for this distribution. One distributes this cost through a NE-wide postage stamp rate in year 6 and beyond. The other phases to the same point in year 11. Pool Planned Units and the Yankee transmission wheeling arrangement are grandfathered for 5 years only. All other long-term wheeling arrangements either terminate in year 6 or continue for their original term, depending on the alternative. In no case is new service available under the old terms and rates. A system of cash transfer payments will accompany this during the first 5 years such the net transmission cost impacts are minimized using 1994 as a base test year. New PTF transmission facilities will be paid for on a NE-wide load basis from day one. Thus, the only time generators will pay for incremental PTF facilities is when the delivery is out of NE and the cost is above the NE average (greater of test). The open access tariff will be based on the Order 888 tariff with substantial modifications. The network service portion essentially treats the entire NE load as network load with costs distributed as described above and transactions internal to NE available at no incremental cost on an equal priority basis. NEPOOL recognizes that FERC desires that tradable firming rights be available within the region and it commits to developing such a system by July 1, 1997. Through and out, point-to-point wheeling services will be available at the NE-wide average PTF rate.
Table 2. Annual PTF fixed cost per company Company
BH BECO CMP CES EUA NEP NU UI VELCO
248
Fixed cost ($)
650,000 53,500,000 13,700,000 4,500,000 8,000,000 81,750,000 78,500,000 15,900,,000 14,000,000
T r a n s m i s s i o n c o n g e s t i o n in n e w e n g l a n d
It is stated in the NEPOOL Agreement (1997) that Under normal system conditions, transmission congestion is not a problem within the NEPOOL Control Area. The transmission system has been designed and constructed to meet the needs of the NEPOOL Participants with the existing set of generating facilities operating under an economic and centrally dispatched regime. As a result load
Transmission pricing in New England
within the control area has historically had access to existing NEPOOL generation unconstrained by congestion across major interfaces. Based on the current lack of congestion, and the need to meet the Commission's filing deadline, the Participants have agreed to address transmission congestion, in the near term, through the 'own-load' dispatch as they have historically, until Part Three of the Restructured NEPOOL Agreement becomes effective. However, numerous bulk transmission system interfaces have been identified within NE and between NE and its neighbors through planning studies and operating experience. These interfaces, composed of one or more transmission facilities, have been defined to gauge the amount of power that can be transferred between or through various areas before a transmission limitation is reached. The limiting transmission facility(s) and contingency(s) which may restrict the power transfer through an interface may not necessarily be part of the interface but may be somewhere electrically in series or parallel with it. The transmission facility and critical contingency that limits the interface transfer may change depending on system conditions. All single contingencies and a limited number of double circuit contingencies of transmission facilities nominally operating at 230 kV and above are typically tested. Contingencies of lower voltage facilities may also be examined, as necessary. In addition, localized transmission limitations may also restrict system operation. All of the interfaces that have been defined may potentially constrain the operation of the bulk power supply system. Maintaining transfers within interface limits may restrict the operation of resources and require the operation of non-economic resources, or require adjustments in imports or exports with neighboring utilities. The potential for restriction by the various interfaces and the precise level of the interface transfer limit are affected by a number of factors including load level, generation availability and dispatch, pumped storage operation, imports and exports with neighboring utilities, and seasonal differences in transmission facility ratings. Determination of the interface transfer limits requires the evaluation of a large range of potential system conditions. Planning studies are periodically conducted which attempt to simulate system conditions reasonably anticipated during the next several years. These studies indicate that, with all transmission facilities in service, all existing and planned resources (i.e. new resources which have been approved through the NEPOOL review process) that are required for reliable and efficient system operation can be dispatched without encountering unacceptable restrictions resulting from constraints on the bulk power transmission system. Interface limits are assessed daily in actual system operation and in near-
term transmission operations planning. In addition, under the present situation in which several nuclear plants are not operational, flow patterns are restricted to the point of creating captive loads due to transmission congestion. As the energy market evolves, at least the interchange transactions within the region may change the flow patterns considerably and create congestion at previously unanticipated interfaces. Moreover, these may vary with the overall demand cycles. All these factors are likely to create much more dynamic and complex congestion interface patterns than at present. Currently the NE groups are actively working on establishing concepts under which congestion will be dealt with in this new environment, and how would it be priced for. The proposals range from suggestions to (1) charge all users of the system according to their relative use (MW) of the grid, or (2) charge users inside congested areas for congestion, and at the same time develop markets for transmission provision to deal with uncertainties in transmission congestion prices. It is our prediction that, given the deadlines imposed by the FERC, NEPOOL will again propose an interim solution for the next 5 years and work, meanwhile, on more comprehensive solutions.
Analysis of the proposed transmission tariffs To answer the question of equitable transmission charges, one must study at least 2 qualitatively different aspects of the problem, i.e. (1) potential for sunk transmission costs as the horizontally structured transmission evolves into a single service to all, and (2) issues of pricing mechanisms which differentiate users of high cost transmission facilities from those using inexpensive ones, as well as heavy users from light users of each particular transmission facility. It is clear from NEPOOL Agreement (1997) that additional provisions are made to deal with the transition during the first 5 years as the horizontally structured owners of smaller portions of the grid open to all potential users, inside and outside their territory. As described above, various types of transactions served are differentiated depending on their relative location to the region (through or out transactions) and special status because of previous contractual commitments (tie benefit) or co-ownership of some portions of PTF (excepted transactions). While the proposal (NEPOOL Agreement, 1997) reflects agreement of various parties for such differentiation during the first 5 years, Alternates A and B are proposed for dealing with excepted transactions after this period 6. In this paper we point out that this unresolved question could be studied by assessing the order of magnitude of cost differences in 2 cases.
249
Transmission pricing in New England In the remainder of this paper several methods for cost allocation are described and analyzed using realistic cost data of NE PTE Access tariff as a function o f cost allocation method used The newly proposed NEPOOL RNS transmission tariff is simply pro rata load share of the total PTF revenue. As such, it does not reflect the location nor time of use of the transmission system. Prior to this, NEPOOL transmission tariffs were based on contract path with postage stamp rate. In this section the new RNS tariff formula from the NEPOOL Agreement (1997) is described together with other possible cost allocation methods. Of particular interest in this paper is comparison of the MIT method proposed in Zobian and Ili6 (1996) with the better known MW-mile and contract path methods. The MIT method is based on the AC load flow model and is expected to more accurately represent actual power flows throughout the system than the traditionally utilized DC model. Formulae for estimating power flows caused by typical point-to-point transactions are developed in this method in order to avoid full blown AC load flow computation for each transaction. An approach is taken to decompose the flows into a main component, associated with each transaction, and an interaction component that is associated with the superposition of all transactions on the network. The interaction component is due to nonlinearity of the power flow equation and cannot be rendered to just one or a few transactions because a small percentage of all transactions contributes to this interaction component. The MIT method guarantees the full recovery of fixed costs and also meets the traditional revenue requirements. The remainder of this paper is organized as follows. First, we briefly summarize several costing methods for transmission service under open access 7. Then, we review the basic formulae of MW methodology and the MIT method. A comparison of the computed access charges based on these 2 methods, to the recently proposed formula is provided for 7 typical transactions. This is followed by identifying important issues related to each method.
A brief survey of various cost allocation methods In this section we present a summary of various pricing methods relevant to the MIT method that are either currently used in the industry or recently proposed to be used. These methods are all based on full recovery of fixed cost and meet the traditional revenue requirements. They differ, however, in the ways the fixed cost is allocated to each transaction.
250
Recently proposed transmission tariff." contract path with postage stamp rate This method is being widely used at present time in conjunction with the postage stamp rate method, and it has been accepted by FERC. The contract path method is applied to transactions that utilize more than one system to deliver power. It is based on the assumption that power flows through a certain, prespecified path between systems. Note that a 'system' here is defined as the transmission facilities owned and/or operated by a company. Such facilities operate as a part of an entire transmission grid; either as part of a particular electric control area, or as its own control area. The transmission owning entities within NE each have their own transmission systems which, along with generator resources, are operated as one electric control area by the regional power pool, NEPOOL. In the case of simple RNS tariff contract path method degenerates into a postage stamp method. In this method one first defines the least cost electrical path between generation and load points for a given transaction if capacity is available on that path. The transaction is then charged a postage stamp rate for each of the systems traversed along the defined path. A postage stamp transmission rate may be based on an annual systemwide fixed transmission cost divided by the peak system MW capacity. The charge for a particular transaction utilizing that system is calculated by multiplying the postage stamp rate by the peak MW involved in that transaction. The method, therefore, does not differentiate users of high priced transmission facilities within the system from those of inexpensive ones (Shirmohammadi et al., 1989). This method also leads to a pancake effect, where a transaction traversing multiple intervening systems in series may be charged multiple rates. The defined path may not be wholly related to the actual flows on the systems thus causing the loop flow problem, i.e. although power may flow over third-party transmission facilities, the third party may not be compensated for such flow. The recently proposed formula for the RNS tariff (NEPOOL Agreement, 1997) on transaction k, FC ~ is F C k= ~
1
Y.PRiFi
(1)
where PRi and F~ are the current Pool PTF Rate and the amount of transmission capacity reserved per day in system i, respectively. The MW-mile methodology For a given transaction, the transmission line capacity use measures transmission service usage by considering each transmission line within and between all systems. With the 'MW-mile methodology' (Mistr and Munsey,
Transmission p r i c i n g in N e w E n g l a n d
1992) the transmission line capacity use is defined as a function of the magnitude, the path, and the distance traveled by the transacted power; hence the name MW-mile methodology. In applying the method we first determine real power flows on all network lines using the DC power flow algorithm for each transaction• The equation approximating the relationship between the bus voltage angles and real power injections for a n-bus network whose nth bus, is the slack bus is given as follows: -
P=
Pi -
-Bll
P2
B21
.
_ P._ ;
B13 Bi,-i 7 - 61 B22 B23 '" B2n-1J C~2
Bi2
=
..
_I3.1
B.2
Bn3
" '
The M I T method In the MIT method we start by finding complex power flow on all network lines using AC power flow algorithm. The equation relating the complex powers with the node voltages and the currents for a n-bus system whose nth bus is the slack bus is given by: $2 $2
0 0
" "'
0 0
11 12 =diag(E*)I
B,,_
I
6._ j
where P is the (n - 1) vector of power injections at buses in a system, and ~ is the (n - l) vector of voltage angles except for at the slack bus. B is the (n - 1 ) × (n - l) sparse susceptance matrix 8, whose entries are given as the following: Bo= - b Ui # j
(3)
Bii=Ejb o
(4)
where b, is the susceptance of the transmission line connecting buses i and j. For transaction k, solving equation (2) yields the node voltage angles, i5', corresponding to that transaction. From i~* the flows on the transmission line connecting buses i and j, F~, can be calculated in the following manner: F ij-bijl( 8 i -
(5)
assuming that the voltage magnitudes at all buses in the system are 1 p.u. The total transmission cost related to transaction k is then calculated by: CTk= ELoW~jF~
(6)
where Li/ and ~ / a r e the length and the predetermined weighing factor reflecting cost per unit capacity of the line per unit length. The summation is performed over all transmission lines. This process is repeated for every transaction in the system. The allocation of the total transmission fixed cost allocated to transaction k, FCk, is then given by:
_Sn_ 1
0
0
0 •" En_ 1. -In-i~ (9)
where S,E* and 7 are the ( n - 1) vectors of complex power, conjugate of complex voltage, and complex current, respectively• Solving equation (9) for transaction k leads to the complex voltage, ~?k, and the complex current, i* corresponding to that transaction. The flows on the transmission line connecting buses i and j, F,~, are then given by: Fk.=E~'*Ik. q --I -q"
(10)
The allocation of fixed cost to transaction k is then calculated according to the following formula: ,
FC =xcc,
IF~I .
+ ECC o . . .
IFiyteracti°n[ peak k kE peak k
(11)
where CGi is the carrying charge for the transmission line between buses i and j and the summation is performed over all transmission lines. IF~I is the absolute value of complex power flow through the transmission line between i a n d j caused by transaction k, and -F! - q °tal is the total absolute value of complex power flow on the line caused by all transactions: F!Otal
] 7k 4- F 'interacti°n
,, - Zk - - i j - - 0
(12)
F~i~'emc'i°"in equation (12) arises from interactions among the transactions and is given by cross multiplying ~ , and 7k of different transactions. Finally, peak k is the peak MW involved in transaction k9.
(7) Numerical
where FC total q= E CT k"
-E T 0 0 E~
=B3
(2)
FCk =qCT k
may not sum to the total cost to be recovered FC t°tal,they are scaled by a factor q, so that the total payments equal the total fixed costs•
(8)
k
This step (7) ensures the full recovery of the cost of the transmission system; since the allocated costs CTk
examples
In this section, we compare the results of using flowbased methods, the MIT method and the MW-mile methodology with contract path method for hypothetical wheeling transactions considering the New England Power Pool Transmission Facilities (PTF) ~°.
251
Transmission pricing in New England
Estimated wheeling revenue by presently used contract path method The currently used contract path method in New England employs postage stamp rates for each company's system. For purpose of our analysis, a postage stamp rate is estimated for each company in Table 3. For each transaction 1-7 in Table 1, a contract path is determined and the appropriate rates are applied. For each transaction, the originating and intervening systems have wheeling charges associated with them, however the ultimate system is excluded from such wheeling charges. It is assumed that the transmission service across the ultimate system border delivered to its load is supplied via a 'network' transmission service, not the wheeling service described in this paper. A network service is charged to the actual connected load (native load) of a particular system. Table 4 shows the determined contract path and Tables 5 and 6 shows the wheeling revenue per transaction per company. The 'native' column in Tables 5 and 6 shows the cost allocated to native load use, and is equal to the company annual PTF cost minus total wheeling revenues received.
Estimated wheeling revenue by the MW-mile method In applying the MW-mile methodology, we first determine flows on lines due to each transactions and due to supply of native load by solving equations (2) and (5). The New England system is modeled with 1808 buses (1512 load buses, 295 generator buses and 1 slack bus) and 2565 transmission lines. For simulation purposes a representative steady state operating point 1~ is chosen and is taken as native load. On top of this native load, 7 hypothetical transactions are added as shown in Table 1. Wheeling charges are based on a transaction for 1 year. It should be noted that the supply of native load is treated as one of the transactions in this calculation. Then, we choose the appropriate weighing factor, W,, on transmission line in the equation (6) that reflects the
cost of using a particular transmission line per MW per mile. Usually, the line by line weighing factor, W0., is assumed to be provided by each utility in the system, but in absence of availability of such data, W,/is obtained by dividing total fixed cost of a company a, FC~, by the product of total length of transmission lines within the company, 2~i~L~i, and maximum capacity of each line, ~,:
FC~ w 0- ~ L ' N 'j .
By dividing by the maximum capacity of line, M o, the relative rather than the absolute use of line is measured satisfying the requirement for weighing factor. Because the relative use of line is used, in the equations (7) and (8) the factor q is needed in the fixed cost allocation for full recovery of cost. That is to say, the full recovery of cost is possible without the factor q in the equations (7) and (8) only if all transmission lines in the system are being used to their maximum capacities. The typical factor, q, in equation (7) is 1.7 to 4. Tables 7 and 8 shows the result of applying the MW-mile methodology to the model. Note that consistent to the contract path method application, no MW-mile wheeling cost is calculated for the ultimate system's utilization of its own system. The 'native' column in Tables 7 and 8 shows the cost allocated to native load use, and is equal to the company annual PTF cost minus total wheeling revenues received.
Estimated wheeling revenue by the MIT method Similarly, in the MIT method we first compute flows on lines due to each transaction and due to supply of native load as well as due to interaction among transactions and native load by solving equations (9) and (10) using the same 1808 bus New England system model. Unlike the MW-methodology case the flow corresponding to the native load cannot be regarded as one of the transactions
Table 3. PTF postage stamp rates per company Company BH BECO CMP CES EUA NEP NU UI VELCO
Annual Cost ($)
Load" (MW)
Rate b ($/kW yr)
650,000 53,500,000 13,700,000 4,500,000 8,000,000 81,750,000 78,500,000 15,900,000 14,000,000
275 2290 1320 965 930 4375 6360 1160 960
2.36 23.36 10.38 4.66 8.6 18.69 12.34 13.71 14.58
"Load data is representative of typical peak load. bRate=annual cost/load; rate developed for illustrative purpose only, may not be fully representative of actual rate methodology used by company (e.g. transmission related revenues and expenses, typically considered in rate making, are neglected here).
252
(13)
qE~
Transmission pricing in New England
Table 4. Contract path corresponding to each transaction Transaction 1 2 3 4 5 6 7
Contract path'
Ultimate system
NiMo-NU VELCO-NU-EUA CMP-NU NU NU NU NB-CMP-NU-NEP
EUA CES NEP UI NEP/Hudson NEP BECO
aAssuming all such wheeling transaction occur by described contract path method over PTF facilities, neglecting special contract/transmission rights that may be currently in existence between New England entities.
but requires separate calculation because in the problem formulation the current for each transaction is specified rather than the power assuming that the voltage at buses is close to 1 +j0. When only few buses in the system are concerned, this assumption is fair, but as the number of buses involved increases, this assumption is rather poor as in the case with native load. So, we can no longer specify the current injection corresponding to the native load assuming that the voltage at buses is close to 1 +j0. We then decide on the carrying charge, CCij, of transmission lines in equation (11) that conveys the cost of using a transmission line per MW. In absence of availability of line by line carrying charge, CCij is computed by multiplying the ratio of distance of line tj to
Table 5. Estimated wheeling revenue by contract path Transaction BH BECO CMP CES EUA NEP NU UI VELCO
1"($)
2($)
3($)
4($)
5b($)
6($)
7a($)
0 0 0 0 0 0 1,234,764 0 0
0 0 0 0 856,381 0 1,234,764 0 1,455,301
0 0 1,035,617 0 0 0 1,234,764 0 0
0 0 0 0 0 0 1,234,764 0 0
0 0 0 0 0 0 1,234,764 0 0
0 0 0 0 0 0 1,234,764 0 0
0 0 1,035,617 0 0 1,869,090 1,234,764 0 0
Table 6. Total wheeling revenue ($)
Native load ($)
Fixed cost ($)
0 0 2,071,234 0 856,381 1,869,090 8,643,348 0 1,455,301
650,000 53,500,000 11,628,766 4,500,000 7,143,619 79,880,910 69,856,652 15,900,000 12,544,699
650,000 53,500,000 13,700,000 4,500,000 8,000,000 81,750,000 78,500,000 15,900,000 14,000,000
BH BECO CMP CES EUA NEP NU UI VELCO
"Power originated from outside New England considered delivered at New England PTF borders transmission charges related to service outside New England not included. bHudson is a transmission dependent utility off of NEWs system and is treated as NEP's native load.
Table 7. Estimated wheeling revenue by the MW-milemethod Transaction BH BECO CMP CES EUA NEP NU UI VELCO
1($)
2($)
3($)
4($)
5($)
6($)
7($)
0 1,295,000 2,000 175,000 0 2,340,000 1,786,000 315,000 423,000
0 1,404,000 4000 0 503,000 2048,000 1279,000 55,000 404,000
1000 787,000 856,000 23,000 137,000 0 1243,000 12,000 84,000
0 43,000 0 1000 7000 205,000 1586,000 0 50,000
0 2,812,000 16,000 13,000 84,000 0 887,000 9000 90,000
0 878,000 18,000 24,000 139,000 0 910,000 10,000 76,000
0 0 1,520,000 7000 49,000 1,153,000 1,022,000 11,000 50,000
253
Transmission pricing in New England Table 8. Total wheeling revenue ($)
Native load ($)
Fixed cost ($)
1000 7,219,000 2,416,000 243,000 919,000 5,746,000 8,713,000 412,000 1,177,000
649,000 46,281,000 11,284,000 4,257,000 7,081,000 76,004,000 69,787,000 15,488,000 12,823,000
650,000 53,500,000 13,700,000 4,500,000 8,000,000 81,750,000 78,500,000 15,900,000 14,000,000
BH BECO CMP CES EUA NEP NU UI VELCO
Lii by the sum of distances of lines in a company, Ei~Lii the fixed cost of the same company, FC~. That is
3. Tables 9 and 10 displays the result of applying the MIT method to the model.
Comparison
C~=FC~ ELijLij"
(14)
ijEa
It should be noted that in contrast to MW-methodology the absolute use of line is measured in the calculation. Finally, the fixed cost allocated to each transaction is determined using equation (11). The cost of flow due to interactions between transactions is divided among transactions proportional to magnitude of real power load involved in transactions. For instance, the interaction component on a line in NEP gets distributed ls and 43.75 to the transactions and native load as the magnitude of load involved in native load in NEP is 43.75 time of that of each transactions as shown in Table
From the numerical results shown in Tables 5--10 it is readily evident that employing either the MW-mile methodology or the MIT method eliminates the problem of not differentiating users using high priced resources within the system from those using inexpensive ones or the problem of loop flow as in the case of postage stamp and contract path methods. For example, transactions 1, 2, 3, 5, and 7 are far more costly than transactions 4 and 6 because of the difference in distance of power being transferred. It does not, however, seem obvious whether using either the MW-mile methodology or the MIT method has advantages over each other from the tables. The real advantage of using the MIT method proposed in Zobian and I1i6 (1996) comes from a supposedly more accurate
Table 9. Estimated wheeling revenue by the MIT method Transaction
BH BECO CMP CES EUA NEP NU U1 VELCO
1($)
2($)
3($)
7000 1,815,000 91,000 187,000 0 2,730,000 1,949,000 369,000 578,000
7000 1,775,000 92,000 0 559,000 3,225,000 1,625,000 120,000 654,000
10,000 947,000 743,000 49,000 222,000 0 1,643,000 111,000 297,000
4($) 7000 296,000 90,000 26,000 112,000 655,000 1,845,000 0 225,000
5($)
6($)
7($)
7000 3,092,000 101,000 41,000 187,000 0 1,476,000 151,000 358,000
7000 1,032,000 102,000 50,000 221,000 0 1,140,000 61,000 215,000
0 0 1,447,000 38,000 181,000 2,118,000 1,837,000 165,000 440,000
Table 10.
BH BECO CM P CES EUA N EP NU UI VELCO
254
Total wheeling revenue ($)
Native load ($)
Fixed cost ($)
45,000 8,957,000 2,666,000 391,000 1,482,000 8,728,000 11,515,000 977,000 2,767,000
605,000 44,543,000 11,034,000 4,109,000 6,518,000 73,022,000 66,985,000 14,923,000 11,233,000
650,000 53,500,000 13,700,000 4,500,000 8,000,000 81,750,000 78,500,000 15,900,000 14,000,000
Transmission pricing in New England
calculation of power flows that allows to account for interaction components. Because the MIT method uses AC power flow with many more considerations such as reactive powers and resistances of lines, it models the reality more closely. Accounting of the interaction component, however small, is also important in the case of BH as transactions 1~5 do indeed affect the flows on lines in BH. Conclusion
The results in this paper confirm the expected: costs to individual transactions generally depend on the type of usage-based method. The most rudimentary, yet simple, contract path method reflects the fact that physical flows are not identical to the contractual energy exchanges. In a truly open access environment, free of ownership allocation issues, this may be sufficient to charge for the access charge viewed as a common good to all. Access charges based on the presently used contract path method in New England are different than the charges one could define according to the actual line flows and the percent usage of the equipment. It is interesting to observe that as the electrical distances over which the transactions occur increase, these differences become more pronounced. A transaction from New York into New England is more costly than what the estimated contract path-based method requires. Except for the accuracy argument, there is no other strong evidence favoring one method over the other. It is clear from the presented simulations that a genuine usage-based method which accounts for loop flows more realistically allocates access charges to individual members of New England system. It is not clear, however, that the demonstrated differences are significant enough to justify the development of algorithms like the MW-mile and the MIT approach. This paper shows that once the algorithm is developed, it is easy to use on a system consisting of 2000 buses like the New England representation used here. It is somewhat unrealistic to expect that the entire interconnection in the United States could be simulated as one entity serving all, and that accurate usage-based charges could be computed for real-time applications. If for no other reasons, one will have functional separation defined by creation of several Independent System Operators (ISO) rather than one. This leaves the methods described here limited to the usage on portions of horizontally structured entities within a much larger geographical area. It is suggested based on the experience with this study that real differences will be seen when clever power marketers attempt to sell power across vast geographical areas. This only makes sense to them, because the energy price differentials are large
when selling power from MAPP to NPCC, for example. In a scenario like this, 2 things could happen: (1) because of inaccuracies in estimating the actual use of the transmission grid, owners of heavily used portions of the grid may not be sufficiently compensated, or (2) the marketers will complain about the transmission tariffs being unreasonably high. Differences in transmission access costs could be significant to affect system efficiency in a major way. To put an end to this question, we must define clearly what is the 'system' within which the open access is provided to the transactions, and perform preliminary comparisons of the type presented in this paper to develop an insight about the order of magnitude of differences caused by using different methods for access charge. These results will greatly depend on the system studied and its size. As a start, we offer a sample study in this paper. The software available is sufficiently general that it could be used for similar cost comparisons on other systems, or for future studies on New England system as the market evolves. Resolving transmission congestion pricing is the next major task for NEPOOL. This research project was supported by New England Electric Power Services (NEP), and by the MIT Consortium for Transmission Provision and Pricing. The authors greatly acknowledge technical input to the paper by Mrs Masheed Rosenqvist o f NEP. ~The term refers to different utilities within a system as opposed to the term, 'vertically structured', which refers to generation, transmission and load within one utility. 2At the submission time of this paper no formal proposal has been made for managing congestion in NE. The targeted due date is July 1997. 3Although hypothetical the analyzed transactions are of direct interest. 4Issues are, however, predicted to be more complicated since congestion is intimately related to generation such as in case of transmission congestion. ~Data provided by NEP are estimated for illustrative purpose only. 6The FERC is expected to resolve this question. 7Only cost-based methods are discussed here, although the authors recognize that these do not necessarily provide sufficient incentives to enhance the transmission system of the future to best serve the evolving market. For treatment of this issue, see Lecinq (I 996) and Lecinq and Ili6 (submitted). 8This is the imaginary part of a more familiar admittance matrix. 9For actual calculations of the flows IF~I and [F~;"'~";'"I, see Zobian and 11i6 (1996). ~°As provided under section 13 of the New England Power Pool agreement. "The data are provided by NEP.
References
Lecinq, B. (1996) Peak-load pricing for transmission in a deregulated electric utility industry. Master of Science Technology and Policy Program Thesis, MIT. Lecinq, M. and I1i6, M. (1997) Peak-load pricing for electric
255
Transmission pricing in New England
power transmission. Proceedings of the 13th Annual International Conference on System Sciences 4, pp. 624-633. Mistr, A. and Munsey, E. (1992) It's time for fundamental reform of transmission pricing. Public Utilities Fortnightly 130(1), 13-16. NEPOOL Agreement (1997) The Restated NEPOOL Agreement and the NEPOOL Open Access Transmission Tariff
256
(January). Shirmohammadi, D. (1989) Evaluation of Transmission Network Capacity Use for Wheeling Transactions. IEEE Transactions on Power Systems 4(4), 1405-1413 Zobian, A. and Ili6, M. D. (1996) Unbundling of transmission and ancillary services. IEEE Transactions on Power Systems 12(2), 539-558.
© 1997 Elsevier Science Ltd. All rights reserved Printed in Great Britain 0957-1787/97 $17.00+0.00
Toward regional transmission provision and its pricing in New England Marija D. Ilia, Yong T. Yoon, Assef Zobian and Mary Ellen Paravalos
In this paper first a brief description of the present admin&trative division within the New England Power Pool (NEPOOL) is given. The NEPOOL proposal for restructured transmission provisions and pricing at the regional level is assessed in light of these administrative divisions. In the proposal differentiation among the types o f transactions to be served by the Regional Network Service (RNS) is made for the next 5 years to reflect previous ownership rights as the network evolves into a single administrative entity. Next, most likely transmission congestion interfaces within the New England region (NE) are described. Although the present proposal does not offer specific solutions for dealing with congestion, two different approaches to this problem under consideration are indicated and analyzed. Finally, results o f an earlier numerical study using realistic transmission costs of the ArE transmission grid (Pool Transmission Facility--PTF) are described to illustrate dependence of access tariffs on the cost allocation method used. The paper concludes with the authors' assessment o f what remains to be done. © 1997 Elsevier Science Ltd. All rights reserved. Keywords."Open access; Transmission pricing; Fixed cost allocation; Contract path; Postage stamp rate; MW-mile method, Wheeling; Transactions, Native load Introduction
As the electric power industry undergoes a transition to the mandatory provision o f open access transmission to all on an equitable basis, the allocation o f the cost of this service among the present owners o f horizontally * M. D. lli~:, Y. T. Yoon and A. Zobian are with the Massachusetts
Institute of Technology,Cambridge, MA 02139, USA. M. E. Parvalos is with the New England Power Service Company,Westborough, MA 01582, USA.
structured t power systems remains an important issue. Methods under consideration range from rather simple to fairly complex, and they are often advocated by parties who are the obvious financial benefactors o f using a specific method. In this paper, a brief description of a hierarchical organization within the New England Power Pool (NEPOOL) is first provided. Present and future users of the Regional Network Services (RNS) are categorized according to their belonging within the network hierarchy as well as according to their N E P O O L membership status. The restructured network service has recently been proposed to the Federal Energy Regulatory Commission (FERC), and it is intended to facilitate energy markets in a non-discriminatory manner. A summary o f this restructured New England Power Pool (NEPOOL) proposal for transmission provision is given. The proposal recognizes the existence o f the present horizontal structure within the New England region (NE) and develops non-discriminatory access and the open access tariff to all following a 5-year transition period. The access tariff for the first 5 years include transitional charges to certain types of transactions and non-uniform access tariffs to certain users. Next, a preliminary description of congestion interfaces within NE is given, together with an elaboration o f how these may change as the energy market evolves in the region. This is used to discuss the reasoning behind 2 strawman proposals for congestion pricing under consideration 2 by the NE groups formed to facilitate a workable transition to regional open access. Finally, the major portion o f this paper describes results o f a numerical study concerned with allocation o f embedded cost in the NE area for a set of hypothetical transactions in the region 3. The results enable one to estimate dependence o f transmission access fees on cost allocation method used and interpret details o f the present proposal in the context o f present administrative 245
Transmission pricing in New England divisions within the region. The paper closes with the authors' assessment that the interim proposal for transmission provision is created under very tight deadlines imposed by the FERC. Consequently, they may need to be thought through and modified as NEPOOL gains more experience with energy markets. As described in this paper, the proposal for transmission provision is made under very strong assumptions about the energy markets that the transmission system must serve. Particularly critical is the assumption of all market participants being price takers. Much work remains to be done to assess this assumption: the interdependence of its validity and effective pricing for transmission congestion. The NE region realizes the need to create governance mechanisms at its Independent System Operator (ISO) level, which would enable the evolution of present rules into better ones. As we all know, once something is in place, it is hard to change it. In light of this, and given the many open questions that stem from the novelty of the problems facing the industry, it is essential to provide for an evolution of this sort.
NEPOOL participants and non-participants There are presently over 130 entities that are participants in NEPOOL, meaning that their energy service is scheduled by NEPOOL. These participants include all of the traditional integrated electric utilities and most of the publicly owned electric systems in the NEPOOL control area, as well as a number of independent power producers, power marketers, brokers and load aggregators. NEPOOL uses the term 'bilateral transaction' to indicate a single market player (load/supplier) that is scheduled by NEPOOL and has a 'bilateral' financial agreement with others in the market for energy price hedging purposes. A direct physical transaction between 2 or more market players is referred to as 'selfscheduled' transaction. One could identify several types of transactions to be served by the transmission provider. They are differentiated on the basis of their geographic scope, with those transactions presently served by a Local Network (a utility within a pool) distinguished from those served by more than one Local Network (referred to as interchange transactions). Moreover, through or out transactions involving entities of outside NEPOOL are distinguished from interchange transactions. Among the through or out transactions further differentiation is made to single out so called excepted transactions which are identified as having invested into the regional transmission facilities and therefore having a special status during the 5-year transition period (not exclusively). At first glance this may appear to be a somewhat
246
unnecessarily complex categorization of transactions when all transactions are supposed to be served on equal basis. Nevertheless, this differentiation reflects an attempt to recover sunk transmission cost by owners of local networks when merging into a single RNS. Similar to the present proposal, which only deals with access fee allocation, it is likely that future proposals for congestion pricing may also attempt to preserve this differentiation, at least during the 5-year period 4.
New England Power Pool Transmission Facilities (PTF) The transmission in NE under the NEPOOL arrangement prior to the most recent proposal for restructuring has been provided over facilities defined as 'PTF' or 'Pool Transmission Facilities'. PTF includes "all transmission lines owned or leased by the NEPOOL Participants which contribute to the parallel carrying ability of the bulk power system within the NEPOOL Control Area and are rated 69 kV and above, along with the related transformers, circuit breakers and associated equipment" (NEPOOL Agreement, 1997). The existence of PTF implies functional unbundling of generation and transmission in NE. The New England Power Pool Transmission Facilities consist of those of 9 major transmission owning companies: Bangor Hydro Electric Company (BH), Boston Edison Company (BECO), Central Maine Power Company (CMP), Commonwealth Energy System Companies (CES), Eastern Utilities Associates Companies (EUA), New England Power Company (NEP), Northeast Utilities (NU), The United Illuminating Company (UI), and Vermont Electric Power Company (VELCO). Figure 1 shows the approximate horizontal structure (ownership division) of the PTF into these 9 major companies. Figure 1 also shows approximate locations of 7 hypothetical transactions to be studied in the later part of the paper. Table 1 summarizes the generation and the load entry points of these transactions. All transactions involve the power transfer of 100 MW or 1 +0 ipu. For purposes of determining the necessary cost recovery of the transmission providing utilities, the fixed costs of 9 major companies in the PTF are given as shown in Table 25. The figures represent an estimated company annual carrying cost for those PTF it owns.
System characteristics NEPOOL is an association of virtually all electric systems in NE, accounting for more than 99.5% of electric power production, imports, and transmission in the 6-state region. NEPOOL's primary responsibilities are to coordinate, monitor, and direct the operations of most of the generating and bulk transmission facilities in the region to assure both adequate reliability and maximum practical economy of bulk power supply. The
Transmission pricing in New England
electric bulk power facilities of all member companies are operated as a single power system by central dispatch of the lowest cost generating and transmission equipment available at any give time. This includes the sharing of operating reserves, economic imports through interconnections, and coordination of generator and transmission maintenance scheduling. Generation and transmission expansion plans of the various member systems are evaluated for consistency with NEPOOL's and the Northeast Power Coordination Council's (NPCC) reliability criteria and for consistency with the efficient operation of the power system. The NEPOOL bulk power supply system serves a diverse region that ranges from rural to dense urban, integrating widely dispersed and varied types of power supply resources to serve its load. The NE summer peak load geographic distribution is approximately 20% in the north: ME, NH, and VT, and 80% in the south: MA, CT, and RI. The winter peak load distribution is approximately 25% and 75% in the north and south, respectively. Although the land area of the north is larger than the south, the relatively larger southern load reflects
greater development and concentration in the urban areas. The amounts of generation installed in the north and the south are roughly proportionate to the respective area loads. Hydroelectric and baseload nuclear plants compose a relatively large proportion on the northern generation, especially compared to the south. This contributes to an economic dispatch of generation at various load levels that may not reflect the same geographic proportions as the installed capacity. The economic dispatch, including contractual and economy interchange with neighboring utilities and considering the generation availability results in multiple intra-NE power transfers of varying direction, magnitude, and duration. The NEPOOL bulk transmission system is comprised mostly of 115 kV, 230 kV, and 345 kV circuits• Transmission lines in the north are generally longer in length and fewer in number than in the south. The increased transmission density in the south reflects the larger load and power supply concentrations• NEPOOL is interconnected with NY through 2 325 kV ties, one 230 kV tie, one 138 kV tie, and 3 115 kV ties. Currently, NEPOOL
7,New Bruns
....... ..................
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I.NY i
=
...........
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. .................... -..... 3.NEP NU ............ -222222222222-...
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,'
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Figure 1. The New England Power Pool Transmission Facilities (PTF) diagram. 247
Transmission pricing in New England Table l. The generation and load points of 7 hypothetical wheeling transactions Purchase
I. 2. 3. 4. 5. 6. 7.
Buyer
From New York Eastern UtilitiesAssociates VermontElectric Power CommonwealthEnergy System Maine Yankee unit New EnglandPower ConnecticutYankee unit United Illuminating Seabrook unit Hudson Municipal(off NEP system) Seabrook unit New EnglandPower FromNew Brunswick Boston EdisonCompany
and New Brunswick are connected through one 345 kV tie with a second 345 kV tie planned. There are also 2 HVDC interconnections with Quebec: a 225 M W backto-back converter at Highgate in northern VT, and a _+450 kV DC line with terminal configurations allowing non-simultaneous operation of either a 690 M W connection at Cornerford in northern NH or a 2000 MW connection at Sandy Pond in eastern MA. Proposed NEPOOL open access tariff
transmission provisions and
The material in this section draws heavily on the actual document submitted to FERC (NEPOOL Agreement, 1997) which states: These provisions are intended to provide a regional arrangement which will cover, on a comparable, non-discriminatory basis, all regional uses of the NEPOOL Transmission System. The arrangement has been designed and will be implemented to encourage and promote competition in the electric market to the benefit of ultimate users of electric energy. Any new regional use of the NEPOOL Transmission System must be furnished and taken by Participants under the NEPOOL Tariff and cannot be furnished by the Participants individually. The NEPOOL Tariff and Restated NEPOOL Agreement also include various transitional arrangements which are intended to phase in over 5- or 10-year periods the financial impacts of the changes resulting from furnishing of regional service under the NEPOOL Tariff. Under the historic regime, most regional uses of the NEPOOL Transmission System had to be obtained and paid for under the individual
tariffs of the Participants. Under the new regime, the service will be a NEPOOL service at rates which will not vary with distance and will cover all regional uses of the NEPOOL Transmission system. The NEPOOL Tariff has been based on the Open Access pro forma tariff in Appendix D to Order No. 888. When the transmission provisions of the Restated NEPOOL Agreement and the NEPOOL Tariff become effective, the entire existing embedded cost of the NEPOOL PTF transmission system, net of revenues derived from through NE (i.e. Canada to NY) and out of NE wheeling, will be assigned entirely to load. This assignment to load will be on the basis of average cost within each of the 9 corporate ownership zones during the first 5 years. Thereafter, there are 2 alternatives which will be presented to FERC for this distribution. One distributes this cost through a NE-wide postage stamp rate in year 6 and beyond. The other phases to the same point in year 11. Pool Planned Units and the Yankee transmission wheeling arrangement are grandfathered for 5 years only. All other long-term wheeling arrangements either terminate in year 6 or continue for their original term, depending on the alternative. In no case is new service available under the old terms and rates. A system of cash transfer payments will accompany this during the first 5 years such the net transmission cost impacts are minimized using 1994 as a base test year. New PTF transmission facilities will be paid for on a NE-wide load basis from day one. Thus, the only time generators will pay for incremental PTF facilities is when the delivery is out of NE and the cost is above the NE average (greater of test). The open access tariff will be based on the Order 888 tariff with substantial modifications. The network service portion essentially treats the entire NE load as network load with costs distributed as described above and transactions internal to NE available at no incremental cost on an equal priority basis. NEPOOL recognizes that FERC desires that tradable firming rights be available within the region and it commits to developing such a system by July 1, 1997. Through and out, point-to-point wheeling services will be available at the NE-wide average PTF rate.
Table 2. Annual PTF fixed cost per company Company
BH BECO CMP CES EUA NEP NU UI VELCO
248
Fixed cost ($)
650,000 53,500,000 13,700,000 4,500,000 8,000,000 81,750,000 78,500,000 15,900,,000 14,000,000
T r a n s m i s s i o n c o n g e s t i o n in n e w e n g l a n d
It is stated in the NEPOOL Agreement (1997) that Under normal system conditions, transmission congestion is not a problem within the NEPOOL Control Area. The transmission system has been designed and constructed to meet the needs of the NEPOOL Participants with the existing set of generating facilities operating under an economic and centrally dispatched regime. As a result load
Transmission pricing in New England
within the control area has historically had access to existing NEPOOL generation unconstrained by congestion across major interfaces. Based on the current lack of congestion, and the need to meet the Commission's filing deadline, the Participants have agreed to address transmission congestion, in the near term, through the 'own-load' dispatch as they have historically, until Part Three of the Restructured NEPOOL Agreement becomes effective. However, numerous bulk transmission system interfaces have been identified within NE and between NE and its neighbors through planning studies and operating experience. These interfaces, composed of one or more transmission facilities, have been defined to gauge the amount of power that can be transferred between or through various areas before a transmission limitation is reached. The limiting transmission facility(s) and contingency(s) which may restrict the power transfer through an interface may not necessarily be part of the interface but may be somewhere electrically in series or parallel with it. The transmission facility and critical contingency that limits the interface transfer may change depending on system conditions. All single contingencies and a limited number of double circuit contingencies of transmission facilities nominally operating at 230 kV and above are typically tested. Contingencies of lower voltage facilities may also be examined, as necessary. In addition, localized transmission limitations may also restrict system operation. All of the interfaces that have been defined may potentially constrain the operation of the bulk power supply system. Maintaining transfers within interface limits may restrict the operation of resources and require the operation of non-economic resources, or require adjustments in imports or exports with neighboring utilities. The potential for restriction by the various interfaces and the precise level of the interface transfer limit are affected by a number of factors including load level, generation availability and dispatch, pumped storage operation, imports and exports with neighboring utilities, and seasonal differences in transmission facility ratings. Determination of the interface transfer limits requires the evaluation of a large range of potential system conditions. Planning studies are periodically conducted which attempt to simulate system conditions reasonably anticipated during the next several years. These studies indicate that, with all transmission facilities in service, all existing and planned resources (i.e. new resources which have been approved through the NEPOOL review process) that are required for reliable and efficient system operation can be dispatched without encountering unacceptable restrictions resulting from constraints on the bulk power transmission system. Interface limits are assessed daily in actual system operation and in near-
term transmission operations planning. In addition, under the present situation in which several nuclear plants are not operational, flow patterns are restricted to the point of creating captive loads due to transmission congestion. As the energy market evolves, at least the interchange transactions within the region may change the flow patterns considerably and create congestion at previously unanticipated interfaces. Moreover, these may vary with the overall demand cycles. All these factors are likely to create much more dynamic and complex congestion interface patterns than at present. Currently the NE groups are actively working on establishing concepts under which congestion will be dealt with in this new environment, and how would it be priced for. The proposals range from suggestions to (1) charge all users of the system according to their relative use (MW) of the grid, or (2) charge users inside congested areas for congestion, and at the same time develop markets for transmission provision to deal with uncertainties in transmission congestion prices. It is our prediction that, given the deadlines imposed by the FERC, NEPOOL will again propose an interim solution for the next 5 years and work, meanwhile, on more comprehensive solutions.
Analysis of the proposed transmission tariffs To answer the question of equitable transmission charges, one must study at least 2 qualitatively different aspects of the problem, i.e. (1) potential for sunk transmission costs as the horizontally structured transmission evolves into a single service to all, and (2) issues of pricing mechanisms which differentiate users of high cost transmission facilities from those using inexpensive ones, as well as heavy users from light users of each particular transmission facility. It is clear from NEPOOL Agreement (1997) that additional provisions are made to deal with the transition during the first 5 years as the horizontally structured owners of smaller portions of the grid open to all potential users, inside and outside their territory. As described above, various types of transactions served are differentiated depending on their relative location to the region (through or out transactions) and special status because of previous contractual commitments (tie benefit) or co-ownership of some portions of PTF (excepted transactions). While the proposal (NEPOOL Agreement, 1997) reflects agreement of various parties for such differentiation during the first 5 years, Alternates A and B are proposed for dealing with excepted transactions after this period 6. In this paper we point out that this unresolved question could be studied by assessing the order of magnitude of cost differences in 2 cases.
249
Transmission pricing in New England In the remainder of this paper several methods for cost allocation are described and analyzed using realistic cost data of NE PTE Access tariff as a function o f cost allocation method used The newly proposed NEPOOL RNS transmission tariff is simply pro rata load share of the total PTF revenue. As such, it does not reflect the location nor time of use of the transmission system. Prior to this, NEPOOL transmission tariffs were based on contract path with postage stamp rate. In this section the new RNS tariff formula from the NEPOOL Agreement (1997) is described together with other possible cost allocation methods. Of particular interest in this paper is comparison of the MIT method proposed in Zobian and Ili6 (1996) with the better known MW-mile and contract path methods. The MIT method is based on the AC load flow model and is expected to more accurately represent actual power flows throughout the system than the traditionally utilized DC model. Formulae for estimating power flows caused by typical point-to-point transactions are developed in this method in order to avoid full blown AC load flow computation for each transaction. An approach is taken to decompose the flows into a main component, associated with each transaction, and an interaction component that is associated with the superposition of all transactions on the network. The interaction component is due to nonlinearity of the power flow equation and cannot be rendered to just one or a few transactions because a small percentage of all transactions contributes to this interaction component. The MIT method guarantees the full recovery of fixed costs and also meets the traditional revenue requirements. The remainder of this paper is organized as follows. First, we briefly summarize several costing methods for transmission service under open access 7. Then, we review the basic formulae of MW methodology and the MIT method. A comparison of the computed access charges based on these 2 methods, to the recently proposed formula is provided for 7 typical transactions. This is followed by identifying important issues related to each method.
A brief survey of various cost allocation methods In this section we present a summary of various pricing methods relevant to the MIT method that are either currently used in the industry or recently proposed to be used. These methods are all based on full recovery of fixed cost and meet the traditional revenue requirements. They differ, however, in the ways the fixed cost is allocated to each transaction.
250
Recently proposed transmission tariff." contract path with postage stamp rate This method is being widely used at present time in conjunction with the postage stamp rate method, and it has been accepted by FERC. The contract path method is applied to transactions that utilize more than one system to deliver power. It is based on the assumption that power flows through a certain, prespecified path between systems. Note that a 'system' here is defined as the transmission facilities owned and/or operated by a company. Such facilities operate as a part of an entire transmission grid; either as part of a particular electric control area, or as its own control area. The transmission owning entities within NE each have their own transmission systems which, along with generator resources, are operated as one electric control area by the regional power pool, NEPOOL. In the case of simple RNS tariff contract path method degenerates into a postage stamp method. In this method one first defines the least cost electrical path between generation and load points for a given transaction if capacity is available on that path. The transaction is then charged a postage stamp rate for each of the systems traversed along the defined path. A postage stamp transmission rate may be based on an annual systemwide fixed transmission cost divided by the peak system MW capacity. The charge for a particular transaction utilizing that system is calculated by multiplying the postage stamp rate by the peak MW involved in that transaction. The method, therefore, does not differentiate users of high priced transmission facilities within the system from those of inexpensive ones (Shirmohammadi et al., 1989). This method also leads to a pancake effect, where a transaction traversing multiple intervening systems in series may be charged multiple rates. The defined path may not be wholly related to the actual flows on the systems thus causing the loop flow problem, i.e. although power may flow over third-party transmission facilities, the third party may not be compensated for such flow. The recently proposed formula for the RNS tariff (NEPOOL Agreement, 1997) on transaction k, FC ~ is F C k= ~
1
Y.PRiFi
(1)
where PRi and F~ are the current Pool PTF Rate and the amount of transmission capacity reserved per day in system i, respectively. The MW-mile methodology For a given transaction, the transmission line capacity use measures transmission service usage by considering each transmission line within and between all systems. With the 'MW-mile methodology' (Mistr and Munsey,
Transmission p r i c i n g in N e w E n g l a n d
1992) the transmission line capacity use is defined as a function of the magnitude, the path, and the distance traveled by the transacted power; hence the name MW-mile methodology. In applying the method we first determine real power flows on all network lines using the DC power flow algorithm for each transaction• The equation approximating the relationship between the bus voltage angles and real power injections for a n-bus network whose nth bus, is the slack bus is given as follows: -
P=
Pi -
-Bll
P2
B21
.
_ P._ ;
B13 Bi,-i 7 - 61 B22 B23 '" B2n-1J C~2
Bi2
=
..
_I3.1
B.2
Bn3
" '
The M I T method In the MIT method we start by finding complex power flow on all network lines using AC power flow algorithm. The equation relating the complex powers with the node voltages and the currents for a n-bus system whose nth bus is the slack bus is given by: $2 $2
0 0
" "'
0 0
11 12 =diag(E*)I
B,,_
I
6._ j
where P is the (n - 1) vector of power injections at buses in a system, and ~ is the (n - l) vector of voltage angles except for at the slack bus. B is the (n - 1 ) × (n - l) sparse susceptance matrix 8, whose entries are given as the following: Bo= - b Ui # j
(3)
Bii=Ejb o
(4)
where b, is the susceptance of the transmission line connecting buses i and j. For transaction k, solving equation (2) yields the node voltage angles, i5', corresponding to that transaction. From i~* the flows on the transmission line connecting buses i and j, F~, can be calculated in the following manner: F ij-bijl( 8 i -
(5)
assuming that the voltage magnitudes at all buses in the system are 1 p.u. The total transmission cost related to transaction k is then calculated by: CTk= ELoW~jF~
(6)
where Li/ and ~ / a r e the length and the predetermined weighing factor reflecting cost per unit capacity of the line per unit length. The summation is performed over all transmission lines. This process is repeated for every transaction in the system. The allocation of the total transmission fixed cost allocated to transaction k, FCk, is then given by:
_Sn_ 1
0
0
0 •" En_ 1. -In-i~ (9)
where S,E* and 7 are the ( n - 1) vectors of complex power, conjugate of complex voltage, and complex current, respectively• Solving equation (9) for transaction k leads to the complex voltage, ~?k, and the complex current, i* corresponding to that transaction. The flows on the transmission line connecting buses i and j, F,~, are then given by: Fk.=E~'*Ik. q --I -q"
(10)
The allocation of fixed cost to transaction k is then calculated according to the following formula: ,
FC =xcc,
IF~I .
+ ECC o . . .
IFiyteracti°n[ peak k kE peak k
(11)
where CGi is the carrying charge for the transmission line between buses i and j and the summation is performed over all transmission lines. IF~I is the absolute value of complex power flow through the transmission line between i a n d j caused by transaction k, and -F! - q °tal is the total absolute value of complex power flow on the line caused by all transactions: F!Otal
] 7k 4- F 'interacti°n
,, - Zk - - i j - - 0
(12)
F~i~'emc'i°"in equation (12) arises from interactions among the transactions and is given by cross multiplying ~ , and 7k of different transactions. Finally, peak k is the peak MW involved in transaction k9.
(7) Numerical
where FC total q= E CT k"
-E T 0 0 E~
=B3
(2)
FCk =qCT k
may not sum to the total cost to be recovered FC t°tal,they are scaled by a factor q, so that the total payments equal the total fixed costs•
(8)
k
This step (7) ensures the full recovery of the cost of the transmission system; since the allocated costs CTk
examples
In this section, we compare the results of using flowbased methods, the MIT method and the MW-mile methodology with contract path method for hypothetical wheeling transactions considering the New England Power Pool Transmission Facilities (PTF) ~°.
251
Transmission pricing in New England
Estimated wheeling revenue by presently used contract path method The currently used contract path method in New England employs postage stamp rates for each company's system. For purpose of our analysis, a postage stamp rate is estimated for each company in Table 3. For each transaction 1-7 in Table 1, a contract path is determined and the appropriate rates are applied. For each transaction, the originating and intervening systems have wheeling charges associated with them, however the ultimate system is excluded from such wheeling charges. It is assumed that the transmission service across the ultimate system border delivered to its load is supplied via a 'network' transmission service, not the wheeling service described in this paper. A network service is charged to the actual connected load (native load) of a particular system. Table 4 shows the determined contract path and Tables 5 and 6 shows the wheeling revenue per transaction per company. The 'native' column in Tables 5 and 6 shows the cost allocated to native load use, and is equal to the company annual PTF cost minus total wheeling revenues received.
Estimated wheeling revenue by the MW-mile method In applying the MW-mile methodology, we first determine flows on lines due to each transactions and due to supply of native load by solving equations (2) and (5). The New England system is modeled with 1808 buses (1512 load buses, 295 generator buses and 1 slack bus) and 2565 transmission lines. For simulation purposes a representative steady state operating point 1~ is chosen and is taken as native load. On top of this native load, 7 hypothetical transactions are added as shown in Table 1. Wheeling charges are based on a transaction for 1 year. It should be noted that the supply of native load is treated as one of the transactions in this calculation. Then, we choose the appropriate weighing factor, W,, on transmission line in the equation (6) that reflects the
cost of using a particular transmission line per MW per mile. Usually, the line by line weighing factor, W0., is assumed to be provided by each utility in the system, but in absence of availability of such data, W,/is obtained by dividing total fixed cost of a company a, FC~, by the product of total length of transmission lines within the company, 2~i~L~i, and maximum capacity of each line, ~,:
FC~ w 0- ~ L ' N 'j .
By dividing by the maximum capacity of line, M o, the relative rather than the absolute use of line is measured satisfying the requirement for weighing factor. Because the relative use of line is used, in the equations (7) and (8) the factor q is needed in the fixed cost allocation for full recovery of cost. That is to say, the full recovery of cost is possible without the factor q in the equations (7) and (8) only if all transmission lines in the system are being used to their maximum capacities. The typical factor, q, in equation (7) is 1.7 to 4. Tables 7 and 8 shows the result of applying the MW-mile methodology to the model. Note that consistent to the contract path method application, no MW-mile wheeling cost is calculated for the ultimate system's utilization of its own system. The 'native' column in Tables 7 and 8 shows the cost allocated to native load use, and is equal to the company annual PTF cost minus total wheeling revenues received.
Estimated wheeling revenue by the MIT method Similarly, in the MIT method we first compute flows on lines due to each transaction and due to supply of native load as well as due to interaction among transactions and native load by solving equations (9) and (10) using the same 1808 bus New England system model. Unlike the MW-methodology case the flow corresponding to the native load cannot be regarded as one of the transactions
Table 3. PTF postage stamp rates per company Company BH BECO CMP CES EUA NEP NU UI VELCO
Annual Cost ($)
Load" (MW)
Rate b ($/kW yr)
650,000 53,500,000 13,700,000 4,500,000 8,000,000 81,750,000 78,500,000 15,900,000 14,000,000
275 2290 1320 965 930 4375 6360 1160 960
2.36 23.36 10.38 4.66 8.6 18.69 12.34 13.71 14.58
"Load data is representative of typical peak load. bRate=annual cost/load; rate developed for illustrative purpose only, may not be fully representative of actual rate methodology used by company (e.g. transmission related revenues and expenses, typically considered in rate making, are neglected here).
252
(13)
qE~
Transmission pricing in New England
Table 4. Contract path corresponding to each transaction Transaction 1 2 3 4 5 6 7
Contract path'
Ultimate system
NiMo-NU VELCO-NU-EUA CMP-NU NU NU NU NB-CMP-NU-NEP
EUA CES NEP UI NEP/Hudson NEP BECO
aAssuming all such wheeling transaction occur by described contract path method over PTF facilities, neglecting special contract/transmission rights that may be currently in existence between New England entities.
but requires separate calculation because in the problem formulation the current for each transaction is specified rather than the power assuming that the voltage at buses is close to 1 +j0. When only few buses in the system are concerned, this assumption is fair, but as the number of buses involved increases, this assumption is rather poor as in the case with native load. So, we can no longer specify the current injection corresponding to the native load assuming that the voltage at buses is close to 1 +j0. We then decide on the carrying charge, CCij, of transmission lines in equation (11) that conveys the cost of using a transmission line per MW. In absence of availability of line by line carrying charge, CCij is computed by multiplying the ratio of distance of line tj to
Table 5. Estimated wheeling revenue by contract path Transaction BH BECO CMP CES EUA NEP NU UI VELCO
1"($)
2($)
3($)
4($)
5b($)
6($)
7a($)
0 0 0 0 0 0 1,234,764 0 0
0 0 0 0 856,381 0 1,234,764 0 1,455,301
0 0 1,035,617 0 0 0 1,234,764 0 0
0 0 0 0 0 0 1,234,764 0 0
0 0 0 0 0 0 1,234,764 0 0
0 0 0 0 0 0 1,234,764 0 0
0 0 1,035,617 0 0 1,869,090 1,234,764 0 0
Table 6. Total wheeling revenue ($)
Native load ($)
Fixed cost ($)
0 0 2,071,234 0 856,381 1,869,090 8,643,348 0 1,455,301
650,000 53,500,000 11,628,766 4,500,000 7,143,619 79,880,910 69,856,652 15,900,000 12,544,699
650,000 53,500,000 13,700,000 4,500,000 8,000,000 81,750,000 78,500,000 15,900,000 14,000,000
BH BECO CMP CES EUA NEP NU UI VELCO
"Power originated from outside New England considered delivered at New England PTF borders transmission charges related to service outside New England not included. bHudson is a transmission dependent utility off of NEWs system and is treated as NEP's native load.
Table 7. Estimated wheeling revenue by the MW-milemethod Transaction BH BECO CMP CES EUA NEP NU UI VELCO
1($)
2($)
3($)
4($)
5($)
6($)
7($)
0 1,295,000 2,000 175,000 0 2,340,000 1,786,000 315,000 423,000
0 1,404,000 4000 0 503,000 2048,000 1279,000 55,000 404,000
1000 787,000 856,000 23,000 137,000 0 1243,000 12,000 84,000
0 43,000 0 1000 7000 205,000 1586,000 0 50,000
0 2,812,000 16,000 13,000 84,000 0 887,000 9000 90,000
0 878,000 18,000 24,000 139,000 0 910,000 10,000 76,000
0 0 1,520,000 7000 49,000 1,153,000 1,022,000 11,000 50,000
253
Transmission pricing in New England Table 8. Total wheeling revenue ($)
Native load ($)
Fixed cost ($)
1000 7,219,000 2,416,000 243,000 919,000 5,746,000 8,713,000 412,000 1,177,000
649,000 46,281,000 11,284,000 4,257,000 7,081,000 76,004,000 69,787,000 15,488,000 12,823,000
650,000 53,500,000 13,700,000 4,500,000 8,000,000 81,750,000 78,500,000 15,900,000 14,000,000
BH BECO CMP CES EUA NEP NU UI VELCO
Lii by the sum of distances of lines in a company, Ei~Lii the fixed cost of the same company, FC~. That is
3. Tables 9 and 10 displays the result of applying the MIT method to the model.
Comparison
C~=FC~ ELijLij"
(14)
ijEa
It should be noted that in contrast to MW-methodology the absolute use of line is measured in the calculation. Finally, the fixed cost allocated to each transaction is determined using equation (11). The cost of flow due to interactions between transactions is divided among transactions proportional to magnitude of real power load involved in transactions. For instance, the interaction component on a line in NEP gets distributed ls and 43.75 to the transactions and native load as the magnitude of load involved in native load in NEP is 43.75 time of that of each transactions as shown in Table
From the numerical results shown in Tables 5--10 it is readily evident that employing either the MW-mile methodology or the MIT method eliminates the problem of not differentiating users using high priced resources within the system from those using inexpensive ones or the problem of loop flow as in the case of postage stamp and contract path methods. For example, transactions 1, 2, 3, 5, and 7 are far more costly than transactions 4 and 6 because of the difference in distance of power being transferred. It does not, however, seem obvious whether using either the MW-mile methodology or the MIT method has advantages over each other from the tables. The real advantage of using the MIT method proposed in Zobian and I1i6 (1996) comes from a supposedly more accurate
Table 9. Estimated wheeling revenue by the MIT method Transaction
BH BECO CMP CES EUA NEP NU U1 VELCO
1($)
2($)
3($)
7000 1,815,000 91,000 187,000 0 2,730,000 1,949,000 369,000 578,000
7000 1,775,000 92,000 0 559,000 3,225,000 1,625,000 120,000 654,000
10,000 947,000 743,000 49,000 222,000 0 1,643,000 111,000 297,000
4($) 7000 296,000 90,000 26,000 112,000 655,000 1,845,000 0 225,000
5($)
6($)
7($)
7000 3,092,000 101,000 41,000 187,000 0 1,476,000 151,000 358,000
7000 1,032,000 102,000 50,000 221,000 0 1,140,000 61,000 215,000
0 0 1,447,000 38,000 181,000 2,118,000 1,837,000 165,000 440,000
Table 10.
BH BECO CM P CES EUA N EP NU UI VELCO
254
Total wheeling revenue ($)
Native load ($)
Fixed cost ($)
45,000 8,957,000 2,666,000 391,000 1,482,000 8,728,000 11,515,000 977,000 2,767,000
605,000 44,543,000 11,034,000 4,109,000 6,518,000 73,022,000 66,985,000 14,923,000 11,233,000
650,000 53,500,000 13,700,000 4,500,000 8,000,000 81,750,000 78,500,000 15,900,000 14,000,000
Transmission pricing in New England
calculation of power flows that allows to account for interaction components. Because the MIT method uses AC power flow with many more considerations such as reactive powers and resistances of lines, it models the reality more closely. Accounting of the interaction component, however small, is also important in the case of BH as transactions 1~5 do indeed affect the flows on lines in BH. Conclusion
The results in this paper confirm the expected: costs to individual transactions generally depend on the type of usage-based method. The most rudimentary, yet simple, contract path method reflects the fact that physical flows are not identical to the contractual energy exchanges. In a truly open access environment, free of ownership allocation issues, this may be sufficient to charge for the access charge viewed as a common good to all. Access charges based on the presently used contract path method in New England are different than the charges one could define according to the actual line flows and the percent usage of the equipment. It is interesting to observe that as the electrical distances over which the transactions occur increase, these differences become more pronounced. A transaction from New York into New England is more costly than what the estimated contract path-based method requires. Except for the accuracy argument, there is no other strong evidence favoring one method over the other. It is clear from the presented simulations that a genuine usage-based method which accounts for loop flows more realistically allocates access charges to individual members of New England system. It is not clear, however, that the demonstrated differences are significant enough to justify the development of algorithms like the MW-mile and the MIT approach. This paper shows that once the algorithm is developed, it is easy to use on a system consisting of 2000 buses like the New England representation used here. It is somewhat unrealistic to expect that the entire interconnection in the United States could be simulated as one entity serving all, and that accurate usage-based charges could be computed for real-time applications. If for no other reasons, one will have functional separation defined by creation of several Independent System Operators (ISO) rather than one. This leaves the methods described here limited to the usage on portions of horizontally structured entities within a much larger geographical area. It is suggested based on the experience with this study that real differences will be seen when clever power marketers attempt to sell power across vast geographical areas. This only makes sense to them, because the energy price differentials are large
when selling power from MAPP to NPCC, for example. In a scenario like this, 2 things could happen: (1) because of inaccuracies in estimating the actual use of the transmission grid, owners of heavily used portions of the grid may not be sufficiently compensated, or (2) the marketers will complain about the transmission tariffs being unreasonably high. Differences in transmission access costs could be significant to affect system efficiency in a major way. To put an end to this question, we must define clearly what is the 'system' within which the open access is provided to the transactions, and perform preliminary comparisons of the type presented in this paper to develop an insight about the order of magnitude of differences caused by using different methods for access charge. These results will greatly depend on the system studied and its size. As a start, we offer a sample study in this paper. The software available is sufficiently general that it could be used for similar cost comparisons on other systems, or for future studies on New England system as the market evolves. Resolving transmission congestion pricing is the next major task for NEPOOL. This research project was supported by New England Electric Power Services (NEP), and by the MIT Consortium for Transmission Provision and Pricing. The authors greatly acknowledge technical input to the paper by Mrs Masheed Rosenqvist o f NEP. ~The term refers to different utilities within a system as opposed to the term, 'vertically structured', which refers to generation, transmission and load within one utility. 2At the submission time of this paper no formal proposal has been made for managing congestion in NE. The targeted due date is July 1997. 3Although hypothetical the analyzed transactions are of direct interest. 4Issues are, however, predicted to be more complicated since congestion is intimately related to generation such as in case of transmission congestion. ~Data provided by NEP are estimated for illustrative purpose only. 6The FERC is expected to resolve this question. 7Only cost-based methods are discussed here, although the authors recognize that these do not necessarily provide sufficient incentives to enhance the transmission system of the future to best serve the evolving market. For treatment of this issue, see Lecinq (I 996) and Lecinq and Ili6 (submitted). 8This is the imaginary part of a more familiar admittance matrix. 9For actual calculations of the flows IF~I and [F~;"'~";'"I, see Zobian and 11i6 (1996). ~°As provided under section 13 of the New England Power Pool agreement. "The data are provided by NEP.
References
Lecinq, B. (1996) Peak-load pricing for transmission in a deregulated electric utility industry. Master of Science Technology and Policy Program Thesis, MIT. Lecinq, M. and I1i6, M. (1997) Peak-load pricing for electric
255
Transmission pricing in New England
power transmission. Proceedings of the 13th Annual International Conference on System Sciences 4, pp. 624-633. Mistr, A. and Munsey, E. (1992) It's time for fundamental reform of transmission pricing. Public Utilities Fortnightly 130(1), 13-16. NEPOOL Agreement (1997) The Restated NEPOOL Agreement and the NEPOOL Open Access Transmission Tariff
256
(January). Shirmohammadi, D. (1989) Evaluation of Transmission Network Capacity Use for Wheeling Transactions. IEEE Transactions on Power Systems 4(4), 1405-1413 Zobian, A. and Ili6, M. D. (1996) Unbundling of transmission and ancillary services. IEEE Transactions on Power Systems 12(2), 539-558.