16 TAC §25.501
The Public Utility Commission of Texas (commission) proposes
new §25.501, relating to Wholesale Market Design for the Electric Reliability
Council of Texas. Project Number 26376 is assigned to this proceeding.
The proposed new rule will set forth basic principles for the ancillary
service markets operated by the Electric Reliability Council of Texas (ERCOT),
including both energy and ancillary capacity service markets. The rule includes
requirements for ERCOT to: allow market participants to self-schedule and
bilaterally contract for energy and ancillary capacity services, to the extent
consistent with system reliability; require the submission of resource-specific
bid curves for energy and ancillary capacity services that ERCOT competitively
procures a day ahead of an operating day or in the operating day; directly
assign all congestion rents to the resources causing the congestion; and use
nodal energy prices for resources and zonal energy prices for loads.
Dr. Eric S. Schubert, Senior Market Economist in the commission's Market
Oversight Division, has analyzed the effects of the proposed rule. Dr. Schubert
is an economist, an expert on competitive electricity markets and the design
of those markets, and is intimately familiar with the details of the rule
and its implications. Dr. Schubert has determined that the public benefits
expected as a result of adoption of the proposed rule will largely begin to
accrue during the third year after the rule takes effect, because ERCOT is
required to fully implement the requirements of the rule approximately three
years after it is scheduled to take effect. The public benefits will be more
effective competition in the sale of electricity at wholesale, resulting in
increased market efficiency; reduction in certain local congestion costs;
increased price transparency; and increased liquidity, as well as improved
siting of generation and transmission resources. In addition, more accurate
wholesale prices will be apparent to retail electric providers and retail
customers, facilitating better-informed price responses by customers. More
accurate pricing will lead to more efficient consumption decisions, and the
rule may lead to the deployment of advanced demand-response technologies,
distributed generation resources, more sophisticated services, and increased
efficiency in the consumption of electricity.
Currently, end-users of electricity in ERCOT are paying between $25 million
to $30 million per year in fees paid to induce power generation companies
to reduce their production at specific generation resources (referred to as
out of merit order down energy or OOME Down costs). These costs easily could
double over time as electricity prices rise, local transmission congestion
increases, or market participants exploit the market rules. Dr. Schubert estimates
that the net cost of these OOME Down payments would decline substantially
as a result of implementation of the rule, based on the experience of the
implementation of direct assignment of congestion fees between ERCOT zones
in February 2002. Direct assignment of local congestion fees, as part of a
nodal congestion management system required by the rule, could reduce these
costs by at least $20 million per year for every year in the future. Using
an estimate of $20 million to $30 million of uplifted OOME Down payments per
year and assuming that OOME Down costs would be eliminated starting in the
fourth year that the rule is in effect, the estimated net present value of
the savings in uplifted OOME Down payments over the first five years of implementing
this rule ranges from $30 million to $50 million. This net present value may
understate the benefit, because the market design proposed in this rule eliminates
the risk of an unexpected sharp increase in OOME Down costs, to which the
current market design does not have countermeasures. In addition, these savings
will continue to accumulate beyond the five-year horizon analyzed here.
As noted in comments filed in this proceeding by a number of interested
persons, direct assignment of congestion fees and zonal pricing have improved
siting of large- scale, gas-fired generation resources, reducing the need
to build 345 kilovolt (Kv) lines to transport power long distances within
ERCOT. The commission sees a comparable benefit of direct assignment of local
congestion fees as part of a nodal congestion management system for 69 Kv
and 138 Kv lines, by encouraging better siting of new generation resources
and more location-specific demand-side resources and distributed generation.
In addition, Dr. Ross Baldick of the University of Texas at Austin presented
in this proceeding the results of his study that shows that the current zonal
system distorts price signals relative to major transmission constraints,
therefore distorting business decisions on where to locate new generation.
Based on STP-Dow shadow prices for the whole of 2002, Dr. Baldick estimates
the error in incentive is approximately 10% of the capital carrying cost of
new generation. In addition to operational inefficiencies, such a large distortion
in price signals will cause unnecessary construction of transmission lines
because of poor siting decisions based on inaccurate price signals. Presently,
ERCOT is planning roughly $650 million of upgrades and construction of transmission
lines (excluding the construction to relieve the McCamey constraint discussed
separately below). This figure is a snapshot, as over time ongoing transmission
projects are completed and new ones are added. For purposes of this analysis,
Dr. Schubert assumes that this $650 million figure is a typical snapshot of
transmission construction in ERCOT. If direct assignment of local congestion
fees improves the siting of new generation resources relative to major transmission
constraints, prevents wind farms from making poor siting decisions that create
another new and expensive local transmission constraint in West Texas, increases
the use of site-specific demand-side resources and distributed generation
resources, then Dr. Schubert anticipates that the rate of transmission construction
costs in ERCOT will be permanently reduced by 20% to 30%. Assuming that these
reduced costs start appearing in the fourth and fifth years after the rule's
effective date, the savings from reduced transmission construction to end-use
customers has a net present value of roughly $45 million to $65 million over
five years and will continue to accumulate beyond the five-year horizon, especially
in response to load growth in urban areas.
As Staff discussed in its filing on September 9, 2002 in this proceeding,
the McCamey area saw a large-scale overbuilding of wind farms behind a local
transmission constraint as a result of inadequate locational price signals.
ERCOT estimates the cost of upgrading the transmission system to accommodate
the wind farms to be $150 million, and as much as $300 million to double that
export capacity so that ERCOT could accommodate the target in the renewable
resources mandate in the Public Utility Regulatory Act (PURA) almost solely
from the McCamey area. Because of the lack of sufficiently granular pricing
within a congestion management zone, the commission and ERCOT are faced with
over $100 million of transmission upgrades, which are eventually paid by end-use
customers, resulting from the actions of a handful of market participants.
With a nodal congestion management system combined with long-term transmission
planning at ERCOT and the commission, wind farms will site in areas of sufficient
transmission export capacity or pay substantial congestion fees if they decide
to locate in an area that is congested, greatly reducing the chances of a
wind farm getting financing to build in a congested area. Dr. Schubert estimates
the savings to end-use customers of electricity in ERCOT will amount to a
net present value of $80 million in the first five years after the effective
date of the rule, because nodal pricing for resources will encourage wind
farms to locate to places on the ERCOT grid other than McCamey.
For the first five years after the effective date of the rule, Dr. Schubert
estimates the net present value of the quantified benefits of converting to
a Texas Nodal market design ranges from $155 million to $195 million in reduced
uplift of local congestion costs and reduced transmission construction. For
the first ten years after the effective date of the rule, Dr. Schubert estimates
that the net present value of the quantified benefits of converting to a Texas
Nodal market design ranges from $320 million to $445 million. Other benefits
not quantified here include a greater range of new supply resources more efficiently
interconnected with the ERCOT grid such as distributed generation and demand-side
resources as well as increased efficiency in real-time operational dispatch
of resources in ERCOT.
Dr. Schubert has determined that for each year of the first five years
that the rule will be in effect, there will be economic costs to entities
that are required to comply with the rule. These costs are associated with
modification of software used in the ERCOT wholesale market and changes in
certain business practices, which are likely to vary from business to business.
As part of this proceeding, Staff asked two qualified scheduling entities
(QSEs) to estimate the economic impact on their businesses of having ERCOT
implement a nodal congestion management system. The estimated costs, which
involved upgrades in their software and communications infrastructure as well
as changed businesses practices, were filed in August 2002 as part of this
proceeding. The overall costs of implementing a nodal system was disputed
by stakeholders, but based on experience in other jurisdictions and these
estimated QSE costs, Dr. Schubert concludes that the net present value of
the costs to be between $130 million and $140 million for all entities required
to comply with the rule in the first five years of the implementation of this
rule. Dr. Schubert also estimates that the net present value of the costs
to be between $255 million to $265 million in the first ten years of implementation
of this rule. Dr. Schubert developed these estimates by taking ERCOT's estimate
of $50 million to revise its software stated in its filing of April 18, 2003
and the estimates of QSE conversion costs (both initial implementation and
increases in operation and maintenance expenses) listed in filings by the
Lower Colorado River Authority and Reliant Resources filed in August 2002.
Dr. Schubert anticipated that the one-time conversion expenses by the QSEs
and ERCOT would take place in the second and third years and that the ongoing
operation and maintenance costs would take place in the fourth and fifth years.
Dr. Schubert also notes that the Competitive Power Advocates (CPA) in its
filing on January 31, 2003 assumed that only half of the QSEs in ERCOT would
need to make a full conversion of their software and business practices, as
many of the QSEs based outside of Texas already had software that would be
compatible with the implementation of the market design in the proposed rule.
Dr. Schubert in his estimate assumed all QSEs would have the full conversion
costs, so his estimate likely overstates the true cost of conversion to the
market design proposed in this rule. Nevertheless, these costs are less than
the benefits in the first five years that the rule will be in effect.
The overall benefits of implementing a nodal congestion management system
go well beyond the first five years, and as Dr. Schubert has estimated, the
benefits increasingly outweigh the costs when looking at a ten-year horizon.
The benefits of implementing this rule are not "one-off" benefits; they will
continue to provide end-users of electricity with savings well into the future.
The new market design will sharply reduce OOME Down payments and transmission
construction costs in every year after implementation, not just in the first
five years. In contrast, the bulk of the costs of the new market design will
take place in the first five years of the market, as a result of QSEs implementing
new software and instituting new business practices. The operating and maintenance
costs for QSEs in years six and further will be much smaller than the benefits
gained from implementing this rule. Thus the ten-year analysis shows an even
higher net benefit to end-use customers than the five-year analysis does.
Dr. Schubert has determined that the economic effects on small businesses
or micro- businesses as a result of the rule will not be proportionately larger
than impacts to the largest businesses. Dr. Schubert has determined that converting
ERCOT to a nodal congestion management system would directly impact QSEs.
Implementing a day-ahead market may have an impact on QSEs, but the commission
is not requiring a mandatory day-ahead market and may decide to endorse a
voluntary power exchange, so those entities that do not want to use the day-ahead
market need not incur user expenses. Dr. Schubert has reviewed the list of
QSEs in ERCOT and found that none of them qualify as small businesses or micro-businesses
as defined in Texas Government Code §2006.001 (Vernon 2000, Supplement
2003). Certain retail electric providers (REPs) or power generation companies
(PGCs) in ERCOT may be micro-businesses or small businesses. The costs of
converting ERCOT market software and the software of some QSEs to handle a
nodal congestion management system likely will be passed along to REPs and
QSEs in the form of fees or charges, using cost for each $100 of sales of
electricity as the standard. The great majority of these charges will be passed
along to end-use customers.
In the public benefits section above, Dr. Schubert has analyzed the potential
costs and savings resulting from the rule. Market participants have provided
the commission with a range of costs of changing software and business practices
of implementing a nodal system, as would be required by the rule. Dr. Schubert
has reviewed data from ERCOT and stakeholder comments that suggest that small
businesses and micro-businesses that are consumers of electricity will save
money by paying less as a result of the rule, by virtue of reduced transmission
costs, improved real-time economic dispatch, reduced local congestion costs,
and the benefit from having a greater range of viable electric services such
as demand-side response programs and distributed generation available to end-use
customers. As indicated above in the public benefits section, the commission
believes that the savings and benefits of implementing a nodal congestion
management system will more than offset the costs to small businesses and
micro-businesses, so implementing the rule should save money for small businesses
and micro-businesses.
Dr. Schubert states that, generally, for the state and for local governments
for each of the first five years that the rule will be in effect: there is
no additional estimated direct cost expected as a result of enforcing or administering
the rule; there are no estimated direct reductions in costs as a result of
enforcing or administering the rule; there is no estimated direct loss or
increase in revenue as a result of enforcing or administering the rule; and
enforcing or administering the rule does not have foreseeable direct implications
relating to cost or revenues. The exception to this statement is that local
governments that participate in the ERCOT wholesale market may incur costs
to comply with the rule; the costs to market participants are described above.
The effect of the rule on the state will be that the commission will administer
and enforce the rule using existing resources. There will be no direct effects
of the rule on local governments, other than as market participants. Local
governments are expected to be indirectly affected due to the public benefits
described above; in particular increased market efficiency will increase disposable
income throughout the ERCOT power region and promote expansion of businesses,
which will in turn increase the tax revenues of local governments. However,
the increased tax revenues resulting from the rule would be very difficult
to accurately quantify. As stated above, the rule will also improve siting
of new generation resources and will reduce the need for new transmission
facilities. The changed sites for new generation resources will mean that
some local governments will receive more tax revenues while others will receive
less, with respect to new generation resources. Local governments at or near
areas of large electric consumption will be more likely to see new generation
resources sited in their jurisdictions, because the rule will provide generation
resources a stronger incentive than currently exists to avoid congestion costs
by locating near areas of large electric consumption. With respect to new
transmission facilities, the rule will reduce the need for new transmission
facilities, because more, new generation resources will locate at or near
areas of large electric consumption. New transmission facilities will be needed
to interconnect new generation facilities to the transmission system, but
fewer transmission lines will be needed to transfer power within areas of
large electric consumption. Therefore the new rule will also mean that local
governments at or near areas of large electric consumption likely will see
a different mix of new transmission facilities sited in their jurisdictions
than under the current market design. The indirect revenues and costs to local
governments resulting from the rule's effects on new generation resources
and new transmission facilities would be very difficult to accurately quantify.
Dr. Schubert states that the rule will not have a direct effect on a local
economy, including for each of the first five years that the rule will be
in effect. However, the rule may have indirect effects. As explained above
with respect to the effects of the rule on local governments, the rule will
improve siting of new generation resources and will reduce the need for new
transmission facilities. The changed sites for new generation resources will
mean that some local economies will have increased employment while other
local economies will have less employment, with respect to new generation
resources. Local economies at or near areas of large electric consumption
will be more likely to see new generation resources sited in their areas,
because the rule will provide generation resources a stronger incentive than
currently exists to avoid congestion costs by locating near areas of large
electric consumption. With respect to new transmission facilities, the rule
will reduce the need for new transmission facilities, because more, new generation
resources will locate at or near areas of large electric consumption. New
transmission facilities will be needed to interconnect new generation facilities
to the transmission system, but fewer transmission lines will be needed to
transfer power within areas of large electric consumption. Therefore, the
new rule will also mean that local economies at or near areas of large electric
consumption likely will see a different mix of new transmission facilities
sited in their jurisdictions than under the current market design. The indirect
employment effects on local economies resulting from the rule's effects on
new generation resources and new transmission facilities would be very difficult
to accurately quantify.
The commission staff will conduct a public hearing on this rulemaking under
the Administrative Procedure Act, Texas Government Code §2001.029 at
the commission's offices, located in the William B. Travis Building, 1701
North Congress Avenue, Austin, Texas 78701, on Tuesday, June 24, 2003, at
9:30 a.m.
Comments on the proposed new section (16 copies) may be submitted to the
Filing Clerk, Public Utility Commission of Texas, 1701 North Congress Avenue,
PO Box 13326, Austin, Texas 78711-3326, on or before June 23, 2003. Reply
comments may be submitted on or before June 26, 2003. Comments should be organized
in a manner consistent with the organization of the proposed rule. All comments
should refer to Project Number 26376.
The commission invites specific comments regarding the costs associated
with, and benefits that will be gained by, implementation of the proposed
section. The commission will consider the costs and benefits in deciding whether
to adopt the section. In addition, the commission invites comments on the
following questions:
Question 1
: In subsection (e) of the proposed
rule, the implementation date for this new market design is March 1, 2006.
The commission seeks comment on the appropriateness and feasibility of this
date.
(a) Is this deadline feasible? If not, why not, and what is your alternative
implementation date?
(b) Is having the new market design implemented before the end of the price-to-beat
period important?
(c) If you believe that the new market design should be implemented in
2007 or later, what "no regrets" interim measures should be taken to address
the existing problems in the current wholesale market design, such as operational
inefficiency, stability of zonal boundaries, the DEC game, the uplift of local
congestion costs, and inadequate price signals for siting resources?
Question 2
: The commission has stated its
intention to have most of the implementation of this rule take place through
the ERCOT stakeholder process. Nevertheless, are there additional issues not
addressed by the rule that the commission should address?
Question 3
: On what timeline should the
following issues be addressed?
(a) Congestion rights
(b) Zonal boundaries for settling load imbalance charges
(c) Day-ahead market / power exchange
(d) Market mitigation
Question 4
: The proposed rule requires
ERCOT to implement a day-ahead energy market. One option for such a market
is an ERCOT-operated voluntary (but financially binding) day-ahead market
based on security-constrained, least-cost dispatch. Such a market would require
that all bilateral transactions become financially binding at the resource
level in the day-ahead period. Alternatively, a day-ahead market can take
the form of a third-party-operated voluntary power exchange, as is used in
the United Kingdom and NordPool markets. Power exchanges would permit trading
at a limited number of trading hubs, with possible hedging of real-time congestion
rents, but could also provide a wider variety of contracts (e.g., forwards,
futures, options) and products (e.g., electricity, natural gas) than an ERCOT-operated
day-ahead market of the type seen in the northeastern United States. A power
exchange could increase liquidity and price discovery in the bilateral market
without requiring submission of financially binding schedules in a day-ahead
energy market run by ERCOT. Bilateral transactions not traded through the
exchange could become financially binding at the time of congestion settlement,
which could take place close to real time.
(a) Would a third-party operated power exchange meet the needs for liquidity
and price discovery in the ERCOT wholesale market?
(b) Would incorporating such an energy market into the market design be
preferable to relying on a voluntary but financially binding day-ahead energy
market based on security-constrained, least cost dispatch?
Question 5
: When ERCOT files the Protocols
to implement the rule, should it also file a cost-benefit analysis that supports
the manner in which ERCOT chose to implement the rule, including evaluation
of major options?
This new section is proposed under the Public Utility Regulatory
Act, Texas Utilities Code Annotated §14.002 (Vernon 1998, Supplement
2003) (PURA), which provides the Public Utility Commission with the authority
to adopt and enforce rules reasonably required in the exercise of its powers
and jurisdiction; §35.004(e), which requires that the commission ensure
that ancillary services necessary to facilitate the transmission of electric
energy are available at reasonable prices with terms and conditions that are
not unreasonably preferential, prejudicial, discriminatory, predatory, or
anticompetitive; §39.001(d), which requires the commission to order competitive
rather than regulatory methods to achieve the goals of PURA Chapter 39 to
the greatest extent feasible; §39.151(a)(1), which requires that ERCOT
ensure access to the transmission and distribution systems for all buyers
and sellers of electricity on nondiscriminatory terms; §39.151(a)(2),
which requires that ERCOT ensure the reliability and adequacy of the regional
electrical network; §39.151(a)(4), which requires that ERCOT ensure that
electricity production and delivery are accurately accounted for among generators
and wholesale buyers in the ERCOT power region; §39.151(c), under which
the commission certified ERCOT to perform the functions prescribed by §39.151
for the ERCOT power region; §39.151(d), which requires ERCOT to establish
and enforce procedures, consistent with PURA and the commission's rules, relating
to the reliability of the regional electrical network and accounting for the
production and delivery of electricity among generators and all other market
participants, and which makes these ERCOT procedures subject to commission
oversight and review; §39.151(i), which permits the commission to delegate
authority to ERCOT to enforce operating standards within the ERCOT regional
electrical network and to establish and oversee transaction settlement procedures,
and which permits the commission to establish the terms and conditions for
ERCOT's authority to oversee utility dispatch functions after the introduction
of customer choice; and §39.151(j), which requires a retail electric
provider, municipally owned utility, electric cooperative, power marketer,
transmission and distribution utility, or power generation company to observe
all scheduling, operating, planning, reliability, and settlement policies,
rules, guidelines, and procedures established by ERCOT.
Cross Reference to Statutes: PURA §§14.002, 35.004(e), 39.001(d),
and 39.151.
§25.501.Wholesale Market Design for the Electric Reliability Council of Texas.
(a)
General. The protocols and other rules and requirements
of the Electric Reliability Council of Texas (ERCOT) shall be consistent with
established economic principles, including marginal cost pricing and minimizing
social costs; support wholesale and retail competition; support the reliability
of electric service; and reflect the physical realities of the ERCOT electric
system.
(b)
Bilateral markets and default provision of energy and ancillary
capacity services. ERCOT shall permit market participants to self-schedule
and bilaterally contract for energy and ancillary capacity services except
to the extent that doing so would adversely impact ERCOT's ability to maintain
reliability. To the extent that a market participant does not self-schedule
or bilaterally contract for the energy and ancillary capacity services necessary
to meet its obligations, ERCOT shall procure energy and ancillary capacity
services to cover the shortfall and charge the market participant ERCOT's
procurement costs.
(c)
Day-ahead energy market. ERCOT shall operate a voluntary
day-ahead energy market, either directly or through contract.
(d)
Develop a Texas Nodal Model. By January 1, 2004, ERCOT
shall use a stakeholder process to develop a wholesale market model that includes
the following characteristics:
(1)
Adequacy of operational information. ERCOT shall require
resource- specific bid curves for energy and ancillary capacity services that
it competitively procures in the day-ahead or operating day, and ERCOT shall
use these bid curves in its operational decisions and financial settlements.
(2)
Congestion pricing. ERCOT shall directly assign all congestion
rents to those resources that caused the congestion. A resource shall be considered
to have caused congestion if it was in the position to relieve congestion
but did not do so. Congestion rents shall be consistent with the nodal prices
used to financially settle resource imbalance charges and the zonal prices
used to financially settle load imbalance charges.
(3)
Nodal energy prices for resources. ERCOT shall use nodal
energy prices for resources. Nodal energy prices for resources shall be based
on security- constrained, economic dispatch.
(4)
Energy trading hubs. ERCOT shall provide information for
energy trading hubs by aggregating nodes and calculating an average price
for each aggregation, for each financial settlement interval.
(5)
Zonal energy prices for loads. ERCOT shall use zonal energy
prices for loads that consist of an aggregation of the individual load node
prices within each zone. ERCOT shall maintain stable zones and shall notify
market participants in advance of zonal boundary changes in order that the
market participants will have an appropriate amount of time to adjust to the
changes.
(6)
Congestion rights. ERCOT shall provide congestion revenue
rights (CRRs), but shall not provide physical transmission rights. ERCOT shall
auction all CRRs, using a simultaneous combinatorial auction, except as otherwise
ordered by the commission for any preassigned CRRs approved by the commission.
CRRs shall not be subject to "use-it-or-lose-it" or "schedule- it-or-lose-it"
restrictions and shall be tradable.
(7)
Market power mitigation. ERCOT shall apply ex ante market
power mitigation methods to energy and ancillary capacity services that it
procures.
(8)
Simultaneous optimization of ancillary capacity services.
For ancillary capacity services that it competitively procures in the day-ahead
or operating day, ERCOT shall use simultaneous optimization and shall set
prices for each service to the corresponding shadow price.
(9)
Multi-settlement system for procuring energy and ancillary
capacity services. For any energy and ancillary capacity services that it
competitively procures in the day-ahead or operating day, ERCOT shall set
a separate market clearing price for each procurement of a particular service.
(e)
Implementation. ERCOT shall file with the commission a
petition to approve the protocols to implement the requirements set forth
in this section by July 1, 2004. Concurrent with that filing, ERCOT shall
present to the commission a cost-benefit analysis of the proposed Texas Nodal
wholesale market design. ERCOT shall fully implement the requirements of the
wholesale market design approved by the commission by March 1, 2006.
This agency hereby certifies that the proposal has been reviewed
by legal counsel and found to be within the agency's legal authority to adopt.
Filed with the Office of
the Secretary of State on may 12, 2003.
TRD-200302949
Rhonda G. Dempsey
Rules Coordinator
Public Utility Commission of Texas
Earliest possible date of adoption: June 22, 2003
For further information, please call: (512) 936-7308