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.
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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.
