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RTOS, Transmission and Tariff Design

 

Task 2 of this study examined a range of transmission and distribution pricing systems across eleven different regions in whic

Designing Tariffs for Electricity Transmission and Distribution in Taiwan§

 

Dr. Rajat Deb, Dr. Keith White, Lielong Hsue

Abstract

Taiwan is restructuring its electricity industry and currently evaluating alternative pricing protocols for transmission and distribution. A review of transmission and distribution pricing protocols in 11 regions in the U.S., Europe, and the Asia Pacific provides valuable insights for Taiwan. The efficiency and transparency of tariffs generally depend on the extent of functional unbundling and intensity of competition. Given the particular features of Taiwan, the emulation of the most sophisticated practices elsewhere is not always, and indeed is rarely, a sensible approach. The key is to formulate simple and transparent fee structures that contribute to open access and enhance competition.

Keywords

Distribution, Restructuring, Taiwan, Tariffs, Transmission

Table of Contents

 

1.     Electricity Industry Restructuring. 1

2.     Access and Usage Charges. 1

3.     Connection, Congestion, and Loss Charges. 3

4.     Ancillary Services. 4

5.     Distribution Services. 5

6.     Communication and Software Systems. 6

7.     Summary and Conclusion. 7

References. 8

 

 


1.          Electricity Industry Restructuring

             Taiwan is planning to restructure its electric power industry, and has begun to investigate alternative pricing protocols for transmission and distribution. Across the globe, the restructuring of the electricity industry has proceeded at different speeds and in several directions. An analysis of 11 regions in the U.S., Europe, and the Asia Pacific holds several lessons for the design of transmission and distribution pricing protocols in Taiwan.

The protocols for pricing transmission and distribution are inevitably diverse. In England and Wales, France, Norway and New Zealand, the transmission system is owned by a single entity, but in four U.S. regions,[1] Germany, Australia and Japan, it is owned by multiple entities. In Europe, trade in electricity has enhanced open transmission access. In Norway, transmission is separate from generation or retailing, but in France and Germany, the three are linked. By contrast, in Japan, New Zealand and England and Wales, the transmission system is relatively isolated, and the trajectory of restructuring has been influenced more by ownership and institutional circumstances than by international trade. In England and Wales and New Zealand, the transmission system is independent of the rest of the electricity business and is viewed as a universal carrier. In Japan, transmission is provided by vertically integrated utilities having considerable operating flexibility.

            The efficiency and transparency of tariffs generally depend on the extent of functional unbundling and intensity of competition. If transmission and/or distribution is linked to generation and retail, pricing and access tend to be less transparent and open. If an independent system operator manages a transmission grid having several owners, as in U.S. regions and Australia, then advances and innovations in transmission access and pricing are considerable. Competition in generation has motivated open transmission access. De-integration and independent transmission operation have enhanced competition and diversity in generation, and open distribution access has enhanced competition and diversity in retailing.

2.         Access and Usage Charges

Access and usage charges are used to recover costs that are embedded, or sunk, and not attributable to particular grid users, especially the capital costs of the grid itself. The most straightforward method to recover embedded costs is via system-wide postage stamp fees per MWh and/or per peak MW of grid access. Several increasingly complex approaches, such as charges based on time of use, transaction type, location (i.e. zone or access point), and usage of, or impact on, the grid. Actual access and usage charges for embedded cost recovery are mathematically and theoretically simple, but often have other dimensions that address practical considerations, such as economic or political concerns.

The four U.S. regions have independent grid operators and multiple transmission owners, and their access charges are typically simple license plate fees per maximum MW (MWh in California) of load served or service requested, based on the zone in which the buyer is located. Texas and New England are moving towards a single grid-wide postage stamp access fee. The grid operator is independent from transmission owners, and obtains required revenues through a separate postage stamp fee, as in California, or through several service-specific fees. The four U.S. systems use simple and transparent access charges that facilitate open access to transmission systems having multiple owners as well as considerable imports, exports, and wheeling. In New Zealand, the single state-owned transmission operator charges access fees to loads at a single flat rate, per kW of “maximum anytime demand” (i.e. the average of the 12 highest demands over the measurement period), similar to U.S. methods in simplicity and transparency.

In Norway, England and Wales and Australia, grid operation is independent of generation and retailing, and access charges vary by location not because of transmission ownership but because of the desire to send economic signals as regards the value and cost of generation and load at different locations on the grid. Locational access is charged on a peak MW basis to loads, as in Australia, or to both generators and loads, as in England and Wales and Norway, and is complemented by postage stamp fees per MW or kWh. As a result, locational fees recover only part of embedded costs. In Australia, locational pricing is based on simulations to calculate how incremental load at different locations utilizes different network elements. In Norway, it is based on net flow at each location during the regional peak load. At locations where peak demand exceeds generation, the locational (but not other) access fees apply to loads. In England and Wales, locational access fees are based on the transmission investment necessitated by incremental load and generation, and calculated through a simplified simulation of optimal system expansion.

In Germany, France and Japan, restructuring is less advanced, and transmission operation remains linked to generation and retailing. Access fees are more complex and less transparent, and vary by season, time of use, level of utilization, as well as voltage and/or power factor. In Germany and Japan, separate fee structures for the different owners’ grids are complex and lack transparency, and thus complicate transmission. It is unclear whether or not the cost to a third-party user is similar to the one that a transmission owner would have to pay for using its own grid.

Taiwan has a single transmission and distribution owner, limited but increasing competitive generation, a “radial” type of grid, no transfers (i.e. imports, exports, or wheeling) beyond Taiwan, and no history of transmission ownership independent from the State. Load is concentrated in the north, south, and parts of the west coast, and congestion is limited, concentrated in the summer months, and occurs on lines running from the central to the northern regions.

For Taiwan, four conclusions seem warranted. First, there is no obvious need to break embedded costs into separate geographic zones or functional accounts, or to unbundle transmission from distribution. Second, open nondiscriminatory access may be fostered by a simple access fee that allocates embedded costs to wheeling customers on the basis of their share to total MWh of transactions, peak MW of demand, or both. Third, locational access charges should be considered only if loads or generation in different locations are found to put very different burdens on the system, such as congestion or expansion requirements. And fourth, if the required information systems are available, then any congestion may be addressed most efficiently by marginal cost methods, such as zonal pricing or uplift costs. Otherwise, any significant congestion could be addressed by zonal access charges. Such charges, however, could have substantial effects on local communities, and potentially have political ramifications.

Charges for connecting specific users or for initiating specific service generally recover direct capital costs of connection. Other indirect connection charges, for example, for system studies, upgrades, and expansion, vary considerably in their application, and appear to be most common in the four U.S. regions. They can reflect and recover the costs of grid upgrade and expansion, especially where, as in the four U.S. regions, there are no locational access fees for this purpose. However, as a substitute for locational pricing, comprehensive case-specific connection charges can be inefficient, opaque, and potentially discriminatory.

The protocols for charging for congestion costs, due to network constraints, vary considerably. Under the first general approach, if congestion is rare and deregulation and unbundling are incomplete, then the grid operator/owner may internalize congestion costs in a bundled electricity price, as in Germany, France and Japan. Congestion costs are also internalized through an overall revenue requirement in England and Wales, with performance incentives for reducing congestion, but the underlying reason is a concern that locational pricing would increase the potential for exercise of market power.

Under the second general approach to congestion pricing, congestion costs become obvious under deregulation and open access, when users are denied their “open” access, but either the costs are small or a system is lacking for allocating those costs to specific users responsible for congestion. Congestion costs, for redispatch, are allocated to a general pool of grid users, typically on an hourly postage stamp (per MWh) basis. The approach is currently used in New England and Texas but is up for replacement. In California, it is used to allocate, among transmission owners, intra-zonal congestion costs that are subsequently passed on to users via access fees.

Under the third general approach to congestion pricing, congestion costs are assigned to specific users whose requested use of constrained transmission causes congestion. The approach best reflects cost causation and signals the locational value of transmission, loads, and generation. However, it requires increasingly sophisticated monitoring, data, and computation systems to determine both locational market-clearing electricity prices and the responsibility of different users for redispatch costs. PJM and New Zealand use nodal electricity pricing, but California and Australia, both with radial grids, use zonal electricity prices to calculate the price of congestion on key inter-zonal interfaces. In New England, the plan is to implement zonal electricity pricing in future, and in Norway, separate congestion pricing zones are declared when congestion is sustained.

Congestion pricing based on locational electricity prices generates surplus revenues accruing to the transmission owner and/or purchasers of transmission rights. However, if congestion pricing is based on actual redispatch costs allocated to all users or, as planned for Texas, to users responsible for congestion, there are no surplus revenues. If transmission costs are assessed for specific constrained lines or interfaces, then owner-provided transmission rights or flexible market-based financial contracts for differences can hedge grid users’ risks of congestion costs

In Taiwan, congestion and supply competition are insufficient to warrant congestion pricing based on nodal electricity prices or a detailed allocation of redispatch costs. Another possible barrier is the availability of data and software required for sophisticated methods. Taiwan has five alternatives.

  • Bundle congestion costs in delivered energy costs. This is inconsistent with open access and transparent pricing.
  • Allocate congestion costs to all system or zonal users on an hourly postage stamp basis. This is transparent but suffers from weak cost causation and economic signaling.
  • Allocate congestion costs based on zonal electricity prices. This is attractive only if zonal prices are technically feasible and politically acceptable.
  • Use locational access fees to signal the costs of congestion. This is done in England and Wales and Norway, and may partly motivate locational access pricing in Australia. It imperfectly addresses cost causation, but may be an efficient compromise if congestion is limited in magnitude and complexity.
  • Indirectly allocate congestion costs to new wheeling or connection services on the basis of system impact (i.e. security and reliability) studies. This could be discriminatory and could also be impractical when there are many new users.

Apart from congestion, losses are another marginal cost. The treatment of losses can be divided in four. First, in France and Japan, restructuring is limited, and losses may be made up by the transmission provider and bundled in overall grid charges. Second, in New England, Texas, Germany (for each voltage level), and PJM to some extent, losses may be charged on a system-wide basis, generally to loads, and typically based on power-flow scenarios that are periodically updated. Third, in Norway and, with hourly application of factors, Australia, loss factors may be calculated for, and applied to, different locations on the grid on the basis of a limited number of periodically updated power flow cases. Finally, in California and England and Wales, for inter-zonal losses in Australia, and for New England and PJM in future, losses may be re-calculated dynamically for each settlement interval (typically hourly or half-hourly), using detailed modeling and data. The approach is used in theory, if not always in practice, in conjunction with locational electricity pricing.

For Taiwan, the method for treating losses depends on the choice of electricity pricing and power-flow modeling. At a minimum, loss charges should be unbundled from overall access fees and should be based on power-flow cases that reflect important variations in conditions and, in the event of open distribution access, distinguish between transmission and distribution losses.

 Ancillary services (AS) are energy products that complement transmission capacity in order to maintain the reliability, security, and quality of electricity transmission. They can be broadly divided in three. The first is “capacity-based” ancillary services, under which generators provide dependable MW of output and the ability to adjust it with varying degrees of precision and rapidity of response. Capacity-based AS generally include regulation and frequency response, spinning reserves, and supplemental reserves. The second AS category is other generator-based AS, such as reactive supply (i.e. voltage support), black start, and sometimes, local area reliability must-run, require generators with specific characteristics and/or locations. The third AS category is grid operator services, such as balancing, scheduling, system control, and dispatch.

The approaches to AS provision and pricing can be divided in three. Under the first approach, as implemented in Germany, France and Japan, AS are bundled within overall grid access charges. AS are not competitively supplied and transparently priced. The approach is generally used in regions where deregulation and vertical de-integration have been limited. Some AS may be priced individually, but not competitively.

            Under the second approach, unbundled pricing with some competitive procurement involves separate charges for particular AS, and typically combines the procurement of generator-based services through contracts or other arrangements, including periodic bid solicitation. The approach is used in England and Wales and Australia, and to procure specialized (not “capacity-based”) generator AS in the four U.S. regions, New Zealand, and Norway. Under the third and final approach, representing the most advanced stage of deregulation, AS are unbundled and market-based. Capacity-based ancillary services are obtained via robust hourly markets, often in day-ahead and hour-ahead time frames. Grid users may be allowed to self-provide capacity-based services. The approach clearly requires organizational and technical sophistication, as well as supply competition, and is used in the four U.S. regions and New Zealand, and partly in Norway and Australia.

 AS in Taiwan are unlikely to reach the most advanced deregulated stage for some time, until technical and organizational arrangements increase in sophistication, and supply competition intensifies. At a minimum, the pricing of capacity-based and other AS should be unbundled and made transparent as soon as possible. Other grid management charges should also be unbundled from charges recovering embedded grid ownership costs, especially if ownership is to be separated from operation. Depending on the state of generation competition, certain AS could be procured by competitive contracting that quickens the transition to price transparency and unbundling. Even prior to market-based procurement of AS, grid users might be permitted to self-supply some AS.

 Distribution services are broadly divided in three: first, customer connection service, for assets and services to connect and integrate individual customers or customer groups; second, customer service, including metering, billing, and communications; and third, wires services, involving the actual power transportation, mainly capital costs. Distribution is fully bundled with transmission in most of the 11 power systems surveyed, and thus distribution pricing cannot be separately evaluated. As in Germany, France, Australia and Japan, generators can use bilateral contracts to serve loads having no energy arrangements with the grid. As in Norway and England and Wales, generators may have open transmission access to a pool from which distribution utilities draw power, and do not have direct access to retail loads. As a result, final customer tariffs include bundled energy, transmission, and distribution, and restructuring affects only the wholesale market.

The unbundling of distribution from transmission, but with a continuation of bundling internally, represents an intermediate stage of restructuring. At the retail consumer level, distribution charges are independent of the cost of generation and transmission. Texas has installed such an arrangement in January 2002, and direct access is available for non-residential customers in California as well as for all customers in New England and PJM.

Finally, the unbundling of individual distribution services represents the greatest extent of restructuring, and is implemented in New Zealand. Customers seeking connection services may negotiate with any distribution company,[2] and may contract with suppliers of connection equipment. Generally the local distribution company provides metering and other customer services, but the customer’s energy retailer may make other arrangements. Wires services are priced and billed by the owner/operator of the relevant grid, and each distribution grid offers its customers a choice of distribution wires tariffs.

Taiwan’s current system integrates the transmission and distribution systems, and there is no obvious need to unbundle. Any transmission/distribution tariff has to include the three basic distribution services: connection, customer services (billing/metering), and wires service. To promote openness and efficiency, Taiwan Power may wish to utilize accounts that distinguish between distribution, transmission, and generation costs, as well as separate wires costs from other distribution costs. It may also wish specifically to address questions of both equity and efficiency during the design of transmission and distribution tariffs.

Since a single company now provides both transmission and distribution services, Taiwan Power should develop a bundled wires service that includes both transmission and distribution, similar to those in Australia, using a methodology that transparently reflects locational costs of distribution expansion.

 

 Communications systems are an essential element of efficient, non-discriminatory grid access, and the information protocols of the 11 regions span a wide range. At one extreme is the Open Access Same-Time Information System (OASIS) mandated by the U.S. Federal Energy Regulatory Commission (FERC). FERC establishes minimum data standards to support participation in wholesale energy markets. At the other extreme, systems in Japan, France, Germany, Texas, which is outside FERC’s jurisdiction, and England and Wales make little information available. Australia, New Zealand and Norway are close to the OASIS model, although they provided somewhat less detail.

The information systems in California are the most detailed, transparent, and public. Very detailed data are available in a standard format designed to integrate with the management systems of market participants. The system is being revised to replace the flat-file format with more flexible database query forms. Both California and New England report historical bid data with a 180-day lag and a disguise of bidder and resource identities in order to minimize the tendency for collusion. Unlike the three other U.S. regions, Texas has adopted participant confidentiality as a core principle, and does not publish information about system conditions or outcomes. Instead, market participants retain the responsibility for securing generation, transmission, and loads to complete transactions.

Communications systems in Taiwan should include the automated publication of timely information on expected system conditions, including forecasts of loads and the availability of transmission capacity. The use of the Internet should be part of the plan. The use of flat “template” files with flexible database querying techniques, as contemplated in California, could be a model for Taiwan. The publication of detailed but lagged bid data in the U.S. reflects a particular regulatory environment and is not necessarily applicable to the success of restructuring efforts in Taiwan.

7.         Summary and Conclusion

             Taiwan is restructuring its electricity industry and currently evaluating alternative pricing protocols for transmission and distribution. A review of transmission and distribution pricing protocols in 11 regions in the U.S., Europe, and the Asia Pacific provides valuable insights for Taiwan. The review covers the typical components of transmission and distribution services, as well as the logistics of implementing the tariff: access and usage charges; connection, congestion, and loss charges; ancillary services; distribution services; and communication and software systems. The efficiency and transparency of tariffs generally depend on the extent of functional unbundling and intensity of competition. Given the particular features of Taiwan, the emulation of the most sophisticated practices elsewhere is not always, and indeed is rarely, a sensible approach.

 There is no obvious need to break embedded costs into separate geographic zones or functional accounts, or to unbundle transmission from distribution. A simple access fee that allocates embedded costs to wheeling customers on the basis of their share to total MWh of transactions, peak MW of demand, or both may foster open nondiscriminatory access. Locational access charges should be considered only if loads or generation in different locations are found to put very different burdens on the system, such as congestion or expansion requirements. If the required information systems are available, then any congestion may be addressed most efficiently by marginal cost methods, such as zonal pricing or uplift costs.  

Congestion and supply competition are insufficient to warrant congestion pricing based on nodal electricity prices or a detailed allocation of redispatch costs. At a minimum, loss charges should be unbundled from overall access fees, and based on power-flow cases reflecting important variations in conditions and, in the event of open distribution access, distinguishing between transmission and distribution losses. Ancillary services in Taiwan are unlikely to reach the most advanced deregulated stage for some time, until technical and organizational arrangements increase in sophistication, and supply competition intensifies. At a minimum, the pricing of capacity-based and other ancillary services should be unbundled and made transparent as soon as possible.

 Since a single company now provides both transmission and distribution services, Taiwan Power should develop a bundled wires service that includes both transmission and distribution, similar to those in Australia, using a methodology that transparently reflects locational costs of distribution expansion. Communications systems in Taiwan should include the automated publication of timely information on expected system conditions, including forecasts of loads and the availability of transmission capacity.

  

References

 

California

California Independent System Operator, FERC Electric Tariff, First Replacement Volume No. I (Tariff and Appendices, Folsom, CA, October 31, 2000).  http://www.caiso.com/docs/2001/01/22/2001012212462510124.html

California Independent System Operator, FERC Electric Tariff, First Replacement Volume No. II (Protocols, Folsom, CA, October 31, 2000).  http://www.caiso.com/docs/2001/01/22/2001012212462510124.html

California Independent System Operator, Department of Market Analysis, The California ISO Firm Transmission Rights Market. Review of the First Nine Months of Operation: February 1 - October 31  (Folsom, CA, November 30, 2000). http://www.caiso.com/docs/2001/03/07/2001030712513720202.pdf

California Independent System Operator, Market Surveillance Unit, Annual Report on Market Issues and Performance  (Folsom, CA, June 1999). http://www.caiso.com/docs/1999/06/04/1999060416162424876.pdf

Pacific Gas and Electric Company,  Tariff Book: Electric Rate Schedules (San Francisco: April 23, 2001). http://www.pge.com/customer_services/business/tariffs/#ERS

San Diego Gas and Electric Company, Wholesale Open-Access Distribution Tariff (FERC Electric Tariff Volume 5)  (San Diego: April 25, 2001). http://www2.sdge.com/tariff/vol5.pdf

San Diego Gas and Electric Company, Tariff Book:  Electric Schedule of Rates  (San Diego: April 25, 2001 http://www2.sdge.com/tariff/elec/b_e_sr.html

Southern California Edison Company, Tariff Schedules Applicable to Electric Service of Southern California Edison Company (Rosemead, CA: January 1998) http://www.sce.com/005_regul_info/005a3_rates.shtml

Mid-Atlantic Region 

Bastian, Jeff, “PJM Market Summary, 1999 Summary Facts,” in PJM Market Highlights,Vol. 2, number 10 (December 1999), page 4. http://www.pjm.com/documents/reports/download/pge4.pdf

PECO Energy Company, Electric Service Tariff (Supplement No. 25 to Electric PA. P.U.C. No. 3) (Philadelphia , PA: February 28, 2001). http://www.peco.com/corp/corp_rates_fr.html

PJM Interconnection, LLC, Annual Report on Operations, 1999  (Norristown, PA:  2000).  http://www.pjm.com/documents/reports/download/1999annual_report_on_operations.pdf

PJM Interconnection, LLC, PJM Open Access Transmission Tariff . FERC Electric Tariff, Fourth Revised Volume I  (Norristown, PA: February 28, 2001).  http://www.pjm.com/documents/agreements/oatt.pdf

PJM Interconnection, LLC, Amended and Restated Operating Agreement of PJM  Interconnection, LLC.  First Revised Rate Schedule FERC No. 24  (Norristown, PA: November 9, 2000).  http://www.pjm.com/documents/agreements/oa.pdf

PJM Interconnection, LLC, PJM LMP Implementation Training Course, Module 200, Topic 220 (New Business Rules): Energy Market Guiding Principles (Norristown, PA: March 25, 1998).  http://www.pjm.com/lmp/tdocs1/trnsactnmodling.pdf

PJM Interconnection, LLC, PJM Market Highlights,Vol. 2, number 10 (December 1999).  http://www.pjm.com/documents/reports/download/DEC_99ii.pdf

New England 

Connecticut Light & Power, CL&P List and Applicability of Rates and Riders (Hartford, CT: December 1999) http://www.cl-p.com/esupplier/rates.asp

ISO New England, Annual Revenue Requirements of PTF Facilities for Costs in 1999 (ISO New England, Holyoke, MA: June 12, 2000) http://www.iso-ne.com/transmission/Transmission_Tariff_Settlements_And_Rate_Development/rate_development/ rate_development_supporting_documents/RevisedNEP99post96.xls

ISO New England, NEPOOL Open Access Transmission Tariff, Schedule 1 - Scheduling System Control and Dispatch Service Rate, Effective June 1, 2000 - May 31, 2001 (Reflecting 1999 Schedule 1 Costs) (ISO New England, Holyoke, MA: October 6, 2000) http://www.iso-ne.com/transmission/Transmission_Tariff_Settlements_And_Rate_Development/rate_development/ Schedule_1_Rate.xls

ISO New England, NEPOOL Open Access Transmission Tariff, Schedule 9 – Regional Network Service (ISO New England, Holyoke, MA: March 2, 2001) http://www.iso-ne.com/transmission/Transmission_Tariff_Settlements_And_Rate_Development/rate_development/ Schedule_9_Rate.xls

New England Power Pool, FERC Electric Rate Schedule No. 6, Market Rules & Procedures (ISO New England, Holyoke, MA: June 26, 2000) http://www.iso-ne.com/mrp/main.html

New England Power Pool, Restated NEPOOL Open Access Transmission Tariff, FERC Electric Tariff, Fourth Revised Volume No. 1 (As amended through the Sixty-Sixth Agreement Amending New England Power Pool Agreement) (ISO New England, Holyoke, MA: September 26, 2000) http://www.iso-ne.com/FERC_filings/04_NEPOOL_Open_Access_Transmission_Tariff/Currently_Filed_Tariff/

ISO New England, Inc., Filing for Recovery of 2001 Administrative Costs, [FERC} Docket No. ER01-. November 1, 2000. [Includes proposed tariff and revenue requirements, description of mission and services, interim tariff, supporting information, 652 pages]

Texas 

Electric Reliability Council of Texas, Inc., ERCOT Protocols  (Austin, TX: January 5, 2001)http://www.ercot.com/tac/retailisoadhoccommittee/protocols/keydocs/FiledVersions/010501/Complete/Protocols1-05-01.zip

Electric Reliability Council of Texas, Inc., The Market Guide: A guide to how the Electric Reliability Council of Texas (ERCOT) facilitates the competitive power market.  Version 1.2  (Austin, TX: February 22, 2001) http://www.texaschoiceprogram.com/documentation/MarkPartDocs/ERCOT_Market_Guide.zip

Public Utilities Commission of Texas, Scope of Competition in Electric Markets in Texas.  Report to the 77th Texas Legislature (Austin, TX: January 2001). http://www.puc.state.tx.us/electric/reports/scope/2001scope_elec.pdf

Public Utility Commission of Texas, Rulemaking Proceedings to Revise PUC Transmission Rules Consistent with the New ERCOT Market Design, Proposed Rules as Approved for Publication at the February 22, 2001 Open Meeting and Submitted to the Texas Register, Project No. 23157, Issued February 23, 2001.

Norway 

Mølmann , Kjersti,  Provision for system operation in the Norwegian electric power system (Oslo, Norwegian Water Resources and Energy Directorate: March 2000).  http://www.nve.no/programmer/ny_dokument.cgi?nodenr=1959&english=1

England-Wales 

Green, Richard "England and Wales - A Competitive Electricity Market?" University of California Energy Institute, Program on Workable Energy Regulation (POWER), Working Paper  PWP-060 (Berkeley, CA: September 1998). http://www.ucei.berkeley.edu/ucei/PDF/pwp060.pdf

Green, Richard. "England and Wales - A Competitive Electricity Market?" University of California Energy Institute, Program on Workable Energy Regulation (POWER), Working Paper  PWP-060 (Berkeley, CA: September 1998). http://www.ucei.berkeley.edu/ucei/PDF/pwp060.pdf

National Grid, The Connection and Use of System Code, A National Grid Final Proposals Document, December 2000

National Grid, Transmission Charging Principles for April 2001, A National Grid Conclusions Document, November 2000 

National Grid, Schedule 1. Schedule of Charges for Transmission Network Use of System (kW) and Energy Consumption (kWh) for 2001/2002, 31 January 2001

Germany 

DVG Deutsche Verbundgesellschaft E.V., GridCode 2000: Network and System Rules of the German Transmission System Operators (Heidelberg: May 2000) http://www.dvg-heidelberg.de/extern/dvg/res.nsf/files/index_engl.html

France

Commission de Régulation de l’Electricité, Délibération relative aux principes de dissociation comptable (Paris: February 15, 2001). http://www.cre.fr/delib/15fevrier2001_01.htm

Commission de Régulation de l’Electricité, Rapport du Groupe d'Expertise Économique sur la Tarification des Réseaux de Transport et de Distribution de l'Électricité et sur la Tarification de La Fourniture d' Électricité aux Consommateurs Non Éligibles (Paris: January 27, 2000) http://www.cre.fr/champs1.pdf .

Gestionnaire du Réseau d’Électricité, Transitional System Price Scale for Energy Delivery Excluding Supply (Paris: June 2000)  http://www.rte-france.com/htm/an/offre/offre_acces_tarifs.htm

Australia 

National Electricity Market Management Company, Ltd., Operating the NEM (Sydney: September 2000) http://www.nemmco.com.au/operating/operating.htm

Transgrid (New South Wales), National Electricity Market Data. Transmission Shared Network Charges 1 July 2000 to 30 June 2001.

National Electricity Market Management Company Limited [NEMMCO], Treatment of Loss Factors in the National Electricity Market, November 1999.

National Electricity Market Management Company Limited [NEMMCO], National Electricity Market Intra-Regional Constraints, Revision 1.0, 8 September 1998.

National Electricity Market Management Company Limited [NEMMCO], Distribution Loss Factors For The National Electricity Market, March 2001.

National Electricity Market Management Company Limited [NEMMCO], Marginal Loss Factors for The 2001/02 Financial Year, March 2001.

National Electricity Market Management Company Limited [NEMMCO], Final Report and Determination of the Structure of Participant Fees (Section 2.11 of the National Electricity Code), 31 March 2000. [NEMMCO]

National Electricity Market Management Company Limited [NEMMCO], National Electricity Market Ancillary Services. Prepared by Settlements, Version 1.0, May 14, 1999.

National Electricity Market Management Company Limited [NEMMCO], National Electricity Market Information Paper: Ancillary Service Compensation Process, Revised Calculation. Market Operations/NEMMCO Version 2, July 2000.

National Electricity Code Administrator Limited (NECA), The National Electricity Code. Version 1.0, Amendment 5.5, January 25, 2001. http://www.neca.com/au/files/necacode

New Zealand 

Bergara, Mario E. and Pablo T. Spiller, "The Introduction of Direct Access in New Zealand's Electricity Market." University of California Energy Institute, Program on Workable Energy Regulation (POWER), Working Paper  PWP-043 (Berkeley, CA: November 1996). http://www.ucei.berkeley.edu/ucei/PDF/pwp043.zip

Transpower New Zealand Limited, Grid Connection: Pricing for Grid Connection Services (Auckland: December 2000) http://www.transpower.co.nz/misc/download.asp?id=2529&source=PDF+1

Transpower New Zealand Limited, Optimised Deprival Valuation of Transpower (Auckland: November 2000) http://www.transpower.co.nz/misc/download.asp?id=2323&source=PDF+1

Transpower New Zealand Limited, Electricity Industry Bill, Submission to the Commerce Select Committee, 14 February 2001. 

Others 

McGuire, Bart, "Optimal Power Flow, Node Prices, and Transmission Toll in a Number of Instructive Examples." University of California Energy Institute, Program on Workable Energy Regulation (POWER), Working Paper  PWP-050 (Berkeley, CA: June 1997). http://www.ucei.berkeley.edu/ucei/PDF/Pwp050.zip

United States Securities and Exchange Commission Form 10-K for the fiscal year ended December 31, 2000, TXU Electric Company, Commission File # 1-11668.

State of Connecticut Docket NO. 98-01-02 DUPC (Dept. of Public Utility Control) Review of the Connecticut Light and Power Company’s Rates and Charges – Phase II, Feb. 5, 1999.

CPUC (Draft) Proposed Decision of Alj Galvin, April 19, 2001 on Application 00-05-013 (filed May 8, 2000):  Application of PG&E for (i) authority to establish its authorized rates of return on common equity and for electric distribution and gas distribution for year 2001, and (ii) adoption of an annual cost of capital adjustment mechanism.

CPUC (Draft) Proposed Decision of Alj Galvin, December 21, 2000 on Application 00-05-018 (filed May 8, 2000):  Application of Sierra Pacific Power Company for authority to establish authorized rate of return on common equity for electric distribution for year 2001.

Public Utilities Commission of Nevada Interim Order, Sept. 17, 1999 Re Docket No. 99-4001: Compliance filing of Sierra Pacific Power Company for a determination of the total revenue requirement for all services presently performed by its electric operations and approval of the allocation of such total revenue requirement across each unbundled service.

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