Part 2.
PUBLIC UTILITY COMMISSION OF TEXAS
Chapter 25.
SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS
The Public Utility Commission of Texas (commission) adopts new §25.90
relating to Market Power Mitigation Plans, new §25.91 relating to Generating
Capacity Reports, and new §25.401 relating to Share of Installed Generation
Capacity with changes to the proposed text that was published in the April
28, 2000
Texas Register
(25 TexReg 3665).
Project Number 21081 was assigned to this proceeding. The new rules are necessary
to implement provisions of the Public Utility Regulatory Act (PURA) §§39.154,
39.155, 39.156, and 39.157. Section 25.90 establishes requirements and procedures
for utilities and power generation companies that own and control more than
20% of the installed generation capacity located in, or capable of delivering
electricity to, a power region to file market power mitigation plans. Section
25.91 establishes reporting requirements and procedures for each person, power
generation company, municipally owned utility, electric cooperative, and river
authority that owns generation facilities and offers electricity for sale
in the state to file annual generating capacity reports. Section 25.401 establishes
initial filing requirements and components of the calculation method to be
used in determining whether a power generation company owns and controls more
than 20% of the installed generation capacity located in, or capable of delivering
electricity to, a power region.
A public hearing on the proposed sections was held at the commission's
offices at 9:30 a.m. on June 1, 2000. Representatives from Central and South
West (CSW), Entergy Gulf States (EGSI or Entergy), FPL Energy (FPLE), Certain
Power Generation Companies (PGCs), and Reliant Energy (Reliant), made comments
at the hearing. To the extent that any party's comments at the hearing differed
from their written comments, such comments are summarized herein.
The commission received written comments on proposed §25.90 from CSW,
Reliant, EGSI, El Paso Electric (EPE), and TXU Electric Company (TXU). The
commission also received reply comments on §25.90 from PG&E Corporation
(PG&E) and Texas Industrial Energy Consumers (TIEC).
The commission received written comments on proposed §25.91 from Alcoa,
Inc. (Alcoa), Austin Energy (AE), City Public Service of San Antonio (CPS),
CSW, EGSI, EPE, FPLE, PGCs, PG&E, Occidental Chemical Corporation (OxyChem),
Reliant, Southwestern Public Service (SPS), TIEC, and TXU. The commission
also received reply comments on §25.91 from CSW, PGCs, PG&E, Reliant,
and TIEC.
The commission received written comments on proposed §25.401 from
PG&E, Reliant, SPS, EGSI, CSW, TIEC, TXU, and Office of Public Utility
Counsel (OPC). The commission also received reply comments on §25.401
from CSW, EGSI, PG&E, Reliant, TIEC, and TXU.
The commission requested comments on the following preamble question concerning
proposed §25.401:
PURA §39.154(d) defines the term "installed
generation capacity" in terms of generation capacity that is "potentially
marketable." Subsection (e)(2) identifies several categories of generation
that are not considered to be potentially marketable. The commission invites
comments on whether these categories should be excluded from the denominator.
CSW, Entergy, Reliant, SPS, and TXU commented that all of the categories
listed in §25.401(e)(2)(A)-(G) are potentially marketable and should
not be excluded from the denominator in calculating market share. They argued
that the proposed exclusions in (e)(2) are not consistent with PURA or the
Legislature's intent. Reliant averred that generation will be sold into the
market if the price is right, even if the generation was built or will be
built to primarily serve on-site generation. It added that the fact that a
generator did not previously sell at wholesale is not an indication that the
unit will not participate in the wholesale market in the future. TXU commented
that the exclusionary nature of subsection (e)(2) is at odds with the broad,
all-inclusive statutory definition of "installed generation capacity." It
argued that the types of generating facilities listed in proposed subsection
(e)(2) constitute installed generation capacity as defined by PURA §§39.154(d)(1),
(2) and (3) and are potentially marketable. It added that these types of generation
facilities are potentially marketable because power from such facilities can
be sold in the competitive market; thus, they can be used to defeat an attempt
to exercise market power. Their existence, therefore, thwarts the exercise
of market power.
CSW recommended that if any of the categories are not considered to be
potentially marketable, then a legally binding prohibition on sales of such
capacity should be adopted, with no exceptions, even during the peak summer
months. TIEC disagreed with CSW's recommendation. It argued that such a prohibition
is beyond the commission's power to enforce in a deregulated market, and that
a prohibition on sales from must-run units would seriously impair the reliability
of the power grid.
Reliant interpreted the proposed rule as excluding certain generation capacity
from the denominator of the installed generation calculation, but counting
the same capacity in the numerator of individual market share calculations.
It argued that this would not be conceptually correct and it would only serve
to over-estimate market shares of power generation companies.
OPC commented that proper calculation of installed capacity in the state
is critical to the development of workable competitive markets. It said that
excessive concentration of capacity ownership will lead to the potential for
market power which can drive prices up, exploit customers with inelastic demands,
and pose barriers to entry of new competitors. OPC said that the protection
offered by the 20% capacity market share criteria is diminished somewhat by
legally required reductions to installed generation capacity, such as reductions
for "grandfathered" facilities and capacity auction sales. It concluded that
the concept of potentially marketable capacity should be defined in a conservative
fashion.
TIEC and PG&E agreed with all of the exclusions in subsection (e)(2).
TIEC stated that including generation that is not available for wholesale
sales in the denominator of the market concentration analysis would impair
the integrity of the analysis by artificially reducing the market shares of
the owners. PG&E suggested that the words "potentially marketable" in
this context are used by way of limitation. These words modify examples of
categories of generation to be included in the determination of installed
generation to be used to measure market power. In other words, only generation
capacity that may be sold in the market may be considered in the assessment
of market share, which, under the statute, is used as a proxy for measuring
market power. PG&E said that the categories identified should be excluded
consistent with the intent of the Legislature that only "potentially marketable"
generation be considered in the determination of installed capacity.
PG&E proposed that two additional categories of capacity be excluded
from installed generation capacity because the capacity is not available for
sale at wholesale. PG&E would exclude the capacity necessary to meet the
native summer peak demand of municipally owned utilities and cooperatives
that have not opted for customer choice; and it would exclude any capacity
that is under contract for delivery to another power region.
In reply comments, CSW, EGSI, Reliant, and TXU strongly disagreed with
OPC, PG&E and TIEC that the phrase "all potentially marketable" was intended
to be a limitation on the definition of "installed generation capacity." CSW
said the phrase was used for emphasis and was intended to be inclusive rather
than exclusive. EGSI and TXU argued that the words used in PURA §39.154(d)
require that the statute be interpreted broadly. TXU said the Legislature
intended the term "installed generation capacity" to include all capacity
that could be marketed, not just capacity that is being marketed. TXU also
said there was no basis in PURA §39.154 for PG&E's recommendations
to exclude capacity that is exported to another power region or capacity that
is reserved to serve native load of opt out municipal and cooperative utilities.
It averred that the fact that this capacity is being sold indicates that it
is marketable. Reliant suggested that initially all potentially marketable
capacity should be included, and then excluded only if experience proves it
not to be marketable.
Also in reply comments, PG&E and TIEC strongly disagreed with CSW,
EGSI, Reliant, and TXU. PG&E said that in essence, the incumbent utilities
would have the commission render the phrase "potentially marketable" meaningless.
PG&E said the commission should identify the capacity that reasonably
could be expected to be marketed, and thus, affect market power.
TXU in its comments presented the legislative history of §39.154(d)
of Senate Bill 7 (SB7), 76th Legislative Session, and argued that the Legislature
intended the term "installed capacity" to include all generation that
The commission finds it unnecessary to adopt a prohibition on sales from
capacity that has been excluded from installed generation capacity. The commission
agrees with Reliant that when capacity is excluded from the denominator, it
should also be excluded from the numerator for the power generator that owns
and controls such excluded capacity. However, the commission disagrees with
Reliant's suggestion that initially all generation facilities should be included
in installed generation capacity and then excluded only if experience proves
it not to be marketable. The commission makes no changes in response to these
particular comments. The specific exclusions in §25.401(e)(2) are addressed
below.
§25.401(e)(2)(A):
Installed generation
capacity will not include generating facilities that have a nameplate rating
equal to or less than 1 megawatt (MW).
TXU and SPS pointed out that distributed generation facilities will likely
play a significant role in the development of the market in Texas. Therefore,
facilities rated at less than 1 MW should not be excluded from the potentially
marketable capacity. On the other hand, TIEC commented that generation facilities
rated at less than 1 MW are too small to have any meaningful impact on the
market, so it is appropriate to exclude them from the denominator. PG&E
agreed with the exclusion of these generators, mainly because it would be
difficult to monitor every small generator around the state.
In reply comments, PG&E asserted that
de minimis
capacity, such as distributed generation, does not have a great effect
on the current market. Reliant replied that Texas is likely to have many generation
facilities with one megawatt or less capacity and, in the aggregate, those
facilities will have a meaningful impact on market concentration. EGSI added
that the phrase "potentially marketable" requires only that generation is
capable of being sold, not that it must have a meaningful impact on the market.
In reply comments, TXU disagreed with PG&E that PURA §39.154 would
impose a reporting burden on small generators or require the commission to
monitor them. TXU expressed confidence that the commission could develop reasonable
estimates of the total amount of generating facilities under 1 MW.
Although the commission encourages the development of distributed generation,
generating facilities with a capacity of less than 1 MW do not constitute
a significant percentage of the installed generation in the state at this
time. Therefore, the commission believes it is appropriate to exclude these
generating facilities from installed generation capacity in order to simplify
the calculation. If it appears in the future that facilities with less than
1 MW capacity contribute significantly to the installed capacity in a power
region, the commission may revise the rule appropriately.
§25.401(e)(2)(B):
Installed generation
capacity will not include generating facilities that are used for backup purposes
and do not generate electricity that is sold at wholesale.
SPS disagreed with the exclusion of backup generation. It noted that in
May 2000, the Federal Energy Regulatory Commission (FERC) issued interim orders
valid until September 30, 2000, to make it easier for large manufacturers
to sell their backup power to utilities when electricity supplies run short.
PG&E responded that backup power sold to utilities, including power sold
pursuant to FERC interim measures, would not be excluded from installed capacity
under the proposed rule.
PG&E said it is reasonable to exclude backup generation because in
the absence of an interconnection agreement and appropriate interconnection
equipment such generation is not deliverable over the grid. It also said that
backup generation should be excluded because its availability is limited by
TNRCC regulations to 10% of the normal operating hours of the primary equipment
being replaced, absent formal air quality permits being obtained. TXU responded
that PURA §39.154 does not require capacity to be available 100% of the
time. Reliant replied that backup power is potentially marketable since many
such units are connected to the grid.
The commission concludes that the category of backup generation is not
necessary, and it amends the rule to delete this category. Backup generation
that is less than 1 MW will be treated in accordance with subsection (e)(2)(A).
Backup generation that is greater than 1 MW is self- generation that may be
able to participate in the wholesale market; therefore its treatment will
be determined by subsection (e)(2)(C).
§25.401(e)(2)(C):
Installed generation
capacity will not include generating facilities that are used to generate
electricity for consumption by the person owning or controlling the facility
and do not generate electricity sold at wholesale.
§25.401(e)(2)(D):
Installed generation
capacity will not include cogeneration facilities that do not generate electricity
that is sold at wholesale.
TXU, Entergy, and SPS opposed the exclusion of self-generation and cogeneration
facilities that do not generate electricity that is sold at wholesale. TXU
argued that whether or not the generating facilities currently generate electricity
that is sold at wholesale does not provide the basis for a determination that
the capacity of these facilities is not potentially marketable. PURA §39.154(d)
requires only that the capacity be potentially marketable, not that it is
currently being marketed at wholesale. It added that excluding the capacity
of such generating facilities is contrary to PURA §39.154(d)(2) which
expressly includes "generating facilities used to generate electricity for
consumption by the person owning or controlling the facility." SPS added that
cogenerator status may change through the loss of a steam host; and PURA does
not distinguish how potentially marketable capacity is used by the final consumer.
Entergy cited a trade publication article about an aluminum company that
had recently decided to sell the output of its cogeneration facility to the
grid rather than produce aluminum because the company perceived electricity
prices to be more attractive than aluminum prices.
OPC agreed with the rule's recognition that some self-generation and cogeneration
capacity is not potentially marketable, but it said one problem with the rule
is that a very small sale into the wholesale market could qualify the full
capacity of a self-generation or cogeneration facility as installed capacity,
even though a large fraction of the facility's capacity is not potentially
marketable. OPC proposed an alternative means for determining which self-generation
and cogeneration is potentially marketable. It recommended that the portion
of self-generation and cogeneration which serves on-site load and is defined
as "eligible on-site generation" pursuant to §39.262(k) and Substantive
Rule §25.345(i) of this title should be excluded from installed capacity.
By this recommendation, capacity would be excluded because it is not economically
feasible for a customer to change its self-supply arrangement if the on-site
generation facility had qualified for a stranded cost exemption pursuant to §39.262(k).
PG&E commented that by definition self-generation and cogeneration
that are not sold at wholesale are by definition not available for purchase
in the market. Further, such capacity is not deliverable to the market absent
an interconnection agreement and appropriate interconnection equipment. TXU
replied that PG&E offered no proof that self-generation and cogeneration
facilities do not have or could not get interconnection agreements.
TIEC agreed with OPC that only the portion of self-generation or cogeneration
that serves the wholesale market should be included in the total installed
capacity in the power region. However, TIEC and other parties disagreed with
OPC's recommendation for an alternative definition of which self-generation
and cogeneration is potentially marketable. PG&E found OPC's alternative
to be too narrow in that it fails to recognize that other self-generation
and cogeneration are not potentially marketable even if they do not qualify
as eligible generation. TIEC opposed OPC's suggestion, saying that the treatment
of on-site generation is more appropriately linked to actual participation
in the market rather than a §39.262(k) determination. Reliant disagreed
with OPC's argument that competition transition charge (CTC) would preclude
self-generators from marketing power. Reliant said that self-generators in
service areas without CTC would be able to market power without incurring
this charge. TXU noted that OPC offered no proof that the loss of stranded
cost exemption would be of sufficient magnitude to prevent the marketing of
eligible on-site generation.
The commission amends the rule to delete the exclusions for self-generation
and cogeneration. The commission agrees with TXU that whether the generating
facilities currently generate electricity that is sold at wholesale does not
provide a basis for a determination that the capacity of these facilities
is not potentially marketable. The phrase "is available for sale to others"
in the initially introduced version of SB7 was replaced by the concept of
"potentially marketable" capacity. This is a more liberal standard, and the
commission concludes that cogeneration and self-generation facilities meet
this standard. Section 39.154, as finally enacted, casts a wide net on the
generation facilities that are included in determining the size of the market.
§25.401(e)(2)(E):
Installed generation
capacity will not include generating facilities that will be retired within
12 months.
Reliant and SPS opposed the exclusion of generating facilities that are
scheduled to be retired within 12 months. Reliant commented that there is
no mandatory or regulatory requirement in a competitive market that any unit
actually be retired. Further, changes in market conditions or unanticipated
unit outages might require operation of a facility that had been previously
scheduled for retirement. Moreover, information on planned retirements in
a competitive environment is considered strategically sensitive information
and forecasts of retirements could be subject to "gaming". TXU agreed that
plans to retire a generating facility can be changed in response to market
conditions.
PG&E supported the exclusion of capacity that will soon be retired
because such capacity will no longer mitigate market power and because the
exclusion provides consistency and symmetry in the determination of market
shares. TXU responded that if the Legislature had wanted to provide symmetry
it could have done so.
OPC also supported the exclusion of capacity that will soon be retired,
but suggested that the word "permanently" be added before the word "retired"
to alleviate the potential for manipulation of retirement plans by plant owners.
PG&E agreed with OPC's recommendation but TIEC opposed it. TIEC proffered
that if a unit is returned to service after being retired, it should be included
in any market concentration analysis after its return to service.
The commission agrees with Reliant and TXU that in a competitive market,
plans to retire a generating facility may be fluid and responsive to market
conditions or changes in the status of other generating equipment. In addition,
the commission is concerned about the potential for gaming retirement plans
in order to manipulate market shares or mask competitively sensitive resource
plans. Finally, in the last year, the commission has witnessed a regulated
utility return several generating units to service in order to provide adequate
resources for its system. These units were returned to service in a relatively
short time, and it is fully plausible that they could provide marketable capacity
in a future competitive market. Therefore, the commission amends the proposed
rule to remove the exclusion for generating facilities that will be retired
within 12 months.
§25.401(e)(2)(F):
Installed generation
capacity will not include generating facilities that have been designated
as "grandfathered" pursuant to subsection (d)(3) of this section.
OPC, PG&E, and TIEC concurred that "grandfathered" facilities must
be excluded from the denominator as well as the numerator. They said that
while PURA §39.154(e) is silent with respect to the denominator, this
does not preclude the commission from excluding such facilities from the denominator.
They added that if numerator and denominator are defined inconsistently, the
summation of Electric Reliability Council of Texas (ERCOT) market shares will
not equal 100%. Thus, market shares and market power would be understated.
They argued that the Legislature did not intend an illogical mathematical
operation, and that it did not intend to undermine its own stated policy to
limit market share and to eliminate market power abuses.
Reliant and TXU disagreed that the total of all market shares must add
to 100%. They said that the Legislature knew the shares would not add to 100%,
but wanted to provide an incentive in §39.154(e) for a PGC to comply
with §39.264. Rather than understating market shares, Reliant and EGSI
said that excluding grandfathered facilities from the denominator would overstate
the market shares of those generators who do not have grandfathered facilities.
TXU, EGSI, and Reliant said that excluding grandfathered facilities from
the denominator is contrary to the statutorily-prescribed method of determining
the percentage shares of installed generating capacity. They argued that by
expressly stating that the commission shall reduce the numerator by the amount
of such capacity, the Legislature clearly implied that the denominator is
not to be reduced by the amount of such capacity. They observed that SB7 contemplated
that the sum of all the percentage shares for a power region would not equal
100% because PURA §39.154(c) requires that the installed generation capacity
subject to auction pursuant to §39.153 be subtracted from the numerator.
PG&E said that the exclusion of grandfathered facilities from the determination
of installed capacity reasonably harmonizes the competing legislative policies
related to market power and environmental issues. PG&E acknowledged that
capacity auction requirements would result in market shares failing to sum
to 100%, but it argued that excluding grandfathered capacity is more likely
to achieve the Legislature's market power policy objectives than the alternative
which would understate market shares and market power without providing any
benefit to the competing environmental objective.
The commission deletes the provision that excludes grandfathered facilities
from the denominator. The commission believes that these plants legitimately
contribute to total market generation and should be counted in the denominator.
However, the record is this rulemaking includes an August 9, 2000 letter from
TXU Electric Company in which TXU proposes a compromise concerning the exclusion
of grandfathered facilities. TXU proposed that if the commission deletes the
proposed section related to the exclusion of grandfathered facilities, then
TXU would refrain from acquiring ownership and control of additional generating
facilities to the extent that such acquisition would cause TXU to exceed SB7
20% limitation of ownership and control, calculated with the capacity of all
grandfathered facilities excluded from both the numerator and denominator
of the equation. The commission accepts TXU's proposal.
§25.401(e)(2)(G):
Installed generation
capacity will not include generating capacity that has been designated "must-run"
by the independent organization in the power region.
SPS opposed the exclusion of must-run capacity, arguing that even must-run
units are potentially marketable since the output is sold to and for the benefit
of the power region.
Noting that the treatment of must-run generation is still under discussion
in ERCOT, TIEC commented that such generators will likely be required to sell
their power at regulated prices. Thus, the ability of must-run generation
to influence market behavior or competitive market prices will be restricted.
Therefore, it is appropriate to exclude must-run generation from the denominator
of the market concentration calculations.
PG&E also supported the exclusion of must-run capacity. It said that
must-run capacity provides system support to ensure the reliability of the
system, but it is not available to provide energy for sale at wholesale. However,
since must-run generation will vary over time as generation and transmission
facilities are added to the system, PG&E suggested that must-run units
should be designated annually to coincide with the determination of market
shares.
In reply comments, Reliant argued that if the rule excludes must-run capacity
from the denominator, it should also allow PGCs to exclude their "must run"
capacity from the numerator as well.
The commission agrees with SPS that the output of a "must-run" unit is
sold to and for the benefit of the power region. The fact that the independent
system operator (ISO) can control the output of a must-run unit in market-crucial
periods means that the availability of a must-run unit clearly and directly
moderates other players' ability to limit generation to influence the market
clearing price. Under current plans in ERCOT, the ISO will purchase must-run
capacity under contract. Therefore the commission concludes it is appropriate
to delete the exclusion of must- run capacity from the market share denominator,
as it is to include a company's must-run capacity in calculating its market
share numerator.
§25.90 Market Power Mitigation Plans
§25.90(a), Application
CSW proposed the addition of a sentence to the end of §25.90(a) permitting
the commission, for good cause, to waive or modify the requirement to file
a market power mitigation plan, in accordance with PURA §39.154(b).
The commission has made the change recommended by CSW.
EPE commented that by virtue of PURA §39.102(c), it is not subject
to PURA Chapter 39 until the expiration of its freeze period in 2005. It requested
that proposed §25.90 be amended to reflect this fact.
The commission has made the change recommended by EPE.
Entergy, Reliant, and TXU argued that the actual date of relevance for
the 20% test should be on or after January 1, 2002, not the December 1, 2000,
date in the proposed rules. Reliant and TXU stated that PURA §39.154
clearly states that the date on which the 20% limitation on installed capacity
begins is the "date of introduction of customer choice." TXU stated that the
Legislature clearly intended the ownership and control determinations to be
forward-looking since new generating facilities that will be operating within
12 months are to be included as part of installed generation capacity. TXU
noted that the commission has projected that more than 14,000 megawatts of
new generation capacity is expected to come on-line in ERCOT by the first
year of customer choice, and that the new generating capacity will substantially
alter percentage shares of installed generation capacity. TXU and Reliant
said the percentage shares of installed generation capacity should be determined
based on projections or estimates of the total amount of installed generation
capacity expected to exist in each power region on the date of introduction
of customer choice.
PG&E and TIEC disagreed with the incumbent utilities, urging the commission
to keep the December 1, 2000 date. PG&E argued that changing the operative
date for measuring market share would be contrary to PURA §39.156(b).
TIEC stated that using projected generation data would introduce a great deal
of uncertainty and controversy in the market concentration analysis, because
it is likely that parties will produce widely divergent forecasts of the amount
of generation that will be added by various generation owners in the future.
The commission agrees with Entergy, TXU and Reliant that it is not appropriate
to specify in the rule that a utility that has a capacity market share greater
than 20% prior to December 1, 2000, will be required to file a market power
mitigation plan by December 1, 2000. The focus of the rule should be on market
shares when retail competition begins. Therefore, the commission deletes the
phrase "prior to December 1, 2000" from §25.90(a). However, the commission
does not believe it is appropriate to include language that specifies the
use of projected data; therefore, it declines to make the other wording changes
recommended by TXU.
The commission included the initial information filing in §25.90(b)
of the proposed rule to provide enough information so that it can calculate
market share percentages to determine which utilities, if any, will be required
to file a market power mitigation plan by December 1, 2000. In calculating
market share percentages, the commission will consider generating facilities
that will be connected to a transmission and distribution system and operating
within 12 months as required by PURA §39.154(d)(3). The commission recognizes
that there may be differing expectations of the capacity that will be connected
and operating within 12 months, but it will work with the appropriate ISOs
to determine appropriate estimates for the amount of incremental generation
capacity to be included.
§25.90(b), Initial informational filing
CSW commented that the rule does not set forth the basis for determining
the capacity rating of a generating unit. It suggested that nameplate rating
is the appropriate method.
The commission adds a reference in §§25.90(b) to §25.91(f)
of this title (relating to Generating Capacity Reports) where the basis for
determining the capacity rating of a generating unit is set forth.
Entergy and TXU commented that the proposed initial information filing
in §25.90(b) is not expressly required by PURA and that it serves no
useful purpose. TXU added that if the informational filing requirement is
retained, it should be broadened to include all persons subject to PURA §39.155
since there is no basis in PURA for discrimination based on the amount of
installed generation capacity owned and controlled. It pointed out that PURA §39.001(c)
provides that the commission may not discriminate against any participant
or type of participant during the transition to and in the competitive market.
PG&E and TIEC strongly dissented, stating that the reporting requirement
is vital for enforcing the statutory limit on generation ownership. In addition,
they believe that to require all generation owners to file market share calculations
would impose an administrative burden on smaller generation owners with no
useful purpose.
The commission believes that the initial filing requirement is necessary
so that it can calculate market share percentages and determine which utilities
or power generation companies, if any, should file market power mitigation
plans on December 1, 2000. However, it would not serve any purpose to broaden
the filing requirement to include all persons subject to PURA §39.155
since most of them would not come close to having a 20% capacity market share.
The commission does not agree that it is discriminatory to require an informational
filing from the small number of utilities that have the greatest amounts of
installed generation so that it can determine who should file market power
mitigation plans. The informational filing is necessary for the commission
to meet its responsibilities to ensure that no one has a market share greater
than 20%.
TXU recommended that the phrase "in the power region" in §25.90(b)
should be modified to read "in the power region, or capable of delivering
electricity to the power region" to be consistent with the language in PURA §39.154(a).
It also commented that the phrase "owned in whole or in part" is inconsistent
with PURA §39.154 and should be modified to read "owned and controlled."
The commission agrees with TXU and has made the recommended changes.
TXU recommended that transmission import capacity be excluded from both
the numerator and denominator of the market concentration analysis because
including it would be inconsistent with PURA §39.154(a). It pointed out
that "installed generation capacity" is defined as all potentially marketable
electric generation capacity, and therefore it is inappropriate to include
transmission import capacity in the calculation. Reliant and Entergy suggested
that the commission should retain transmission import capacity in the denominator
of the analysis, while excluding such capacity from the numerator because
open access transmission allows nondiscriminatory access to transmission capacity
on a first-come, first-served basis.
TIEC opposed these suggestions, stating that it is entirely appropriate
to include transmission import capacity in the numerator or denominator of
the market concentration analysis, because the ability to import generation
into a region has a direct impact on competitive market prices within the
region. It said the existence of open-access transmission does not negate
the fact that generation owners can control transmission import capacity by
reserving such capacity under the tariffs. TIEC added that including transmission
import capacity in the denominator but not in the numerator of the market
concentration analysis would artificially reduce the market shares of the
generation owners.
CSW recommended that transmission import capacity amounts that are to be
included in the numerator and the denominator of the calculations should be
reported by the ISOs rather than the utility or power generation company.
The commission believes that the inclusion of transmission import capacity
in the market share calculation is entirely consistent with the language in
PURA §39.154 which refers to capability of delivering electricity to
a power region. It believes that inclusion of transmission import capacity
in the denominator is necessary in order to accurately determine the value
of the total installed generation capacity that is available in a region.
Similarly, the commission believes that the transmission capacity that a utility
or power generation company reserves in order to import generation capacity
owned and controlled in another power region should be included in the numerator
of the market share calculation. The commission adds wording to the section
to clarify the information that should be included in the initial informational
filing, and to allow any interested party to respond to the initial informational
filings.
Entergy stated that if the commission chooses to include import capacity,
at a minimum, only the amount directly reserved by the power generation company
should be included. Entergy said that continuing regulatory obligations may
require that its regulated affiliates reserve transmission import capacity
to support ongoing regulated retail load. It noted that utilities in regions
that have not fully deregulated may need to reserve transmission capacity
in order to meet retained regulated load obligations. Entergy continued by
stating that certain types of transmission reservations may be properly assigned
to a supplier, such as reservations associated with long-term power contracts.
In this case, it said the supplier has "control" over the reserved amount
of import capacity that can serve the power region. However, it added, other
types of transmission reservations should not automatically be assigned to
the current holder of the reservations.
As discussed in its comments concerning §25.401(d), the commission
believes that a utility's numerator capacity share should include the transmission
import capability that is reserved for the purpose of importing generation
capacity during the summer peak season that is owned and controlled by the
power generation company or its affiliate in another power region.
§25.90(c), Market power mitigation plan
SPS recommended that the ability to increase transmission capability into
a power region be added as a recognized mitigation measure that may be included
in a market power mitigation plan. PG&E disagreed, stating that the addition
of transmission capacity does not represent a reasonable market power mitigation
measure because it would impose costs on other market participants that otherwise
could be avoided. It argued that the addition of transmission capacity can
add costs to the nonbypassable charges. It added that in power regions other
than ERCOT, transmission rates are subject to FERC jurisdiction and may not
be determined based on the postage stamp approach. Thus, generation which
is closer in proximity to load,
i.e.,
incumbent
utility generation, would have a market advantage in that its transportation
costs would be lower than the transportation costs to its competitors.
The commission declines to make the changes recommended by SPS. PURA §39.156(c)(5)
states that a proposed market power mitigation plan may include any reasonable
method of mitigation. SPS or other entity will be free to include a proposal
to mitigate market power by increasing transmission capability in the plan
it proposes. The merits of such a proposal can be taken up at that time.
§25.90(f), Commission determinations
Subsection (f)(5)
Reliant and TXU contended that whether a plan provides adequate mitigation
of market power is not a relevant consideration in evaluating a proposed market
power mitigation plan. They pointed out that PURA §39.156(a) defines
a market power mitigation plan as a proposal for reducing ownership and control
of installed generation capacity. Reliant averred that while other sections
of PURA do give the commission the authority to monitor market power and address
market power abuses, those issues cannot be the subject of a plan filed under
PURA §39.156 and proposed §25.90, nor can the commission assume
broader discretion in considering market power mitigation plans than is provided
for in PURA §39.156(g).
In reply comments, PG&E and TIEC countered that the TXU and Reliant
position should be rejected because §39.156(g)(5) of PURA provides that
the commission may consider whether a plan is consistent with the public interest
in evaluating a market power mitigation plan. TIEC stated that these responsibilities
extend beyond the determination of whether generation capacity is excessively
concentrated to include the detection and mitigation of a variety of market
power abuses, including predatory pricing, collusion, withholding of capacity,
and erecting barriers to market entry. It added that whether a proposed plan
adequately mitigates market power is directly relevant to evaluating a market
power mitigation plan and should be retained in the rule.
The commission does not agree that PURA §39.156 limits it in the manner
suggested by Reliant and TXU. PURA §39.156(g) expands the commission's
determinations beyond the sole issue of the proposed reduction in ownership
and control of installed generation capacity to include such issues as minimization
of stranded costs, the effect on federal income taxes, and consistency with
the public interest. The commission agrees with PG&E and TIEC that in
considering whether a plan is consistent with the public interest, it can
make a determination of whether the plan provides adequate mitigation of market
power. In determining whether there is adequate mitigation, the commission
will look to whether the utility or power generation company has presented
a feasible and timely plan to reduce generation to below the 20% threshold.
The commission declines to make the changes recommended by TXU and Reliant.
Proposed Subsection (f)(7)
SPS suggested that language should be added to §25.90 as (f)(7) to
indicate "whether the sale of capacity or disposition of assets is subject
to federal Securities and Exchange Commission pooling of interests requirements."
The commission declines to add the language recommended by SPS. SEC pooling
of interest requirements are not related to market power or the public interest
determination in evaluating market power mitigation plans.
§25.91 Generating Capacity Reports
§25.91(a), Application
EGSI, Reliant, and SPS commented that the application in §25.91(a)
should pertain to all generators connected to the transmission or distribution
system, including self-generation and cogeneration. TIEC strongly opposed
a requirement for self-generators and cogenerators to file generating capacity
reports if they do not offer power for sale in the market. It argued that
generation that is not for sale will not affect market prices; therefore,
reports from such generators are not needed to assess market power.
The commission declines to make the change recommended by EGSI, Reliant,
and SPS. The proposed rule is consistent with PURA §39.155(a), which
requires entities that own generation facilities and offer electricity for
sale in the state to file generating capacity reports.
EPE recommended that language be added to §25.91 stating that the
section would not apply to an electric utility that is not subject to PURA
Chapter 39, pursuant to PURA §39.102(c), until the expiration of its
freeze period.
The commission agrees that the rule does not apply to a company that is
subject to PURA §39.102(c) until its freeze period ends. The commission
modifies §25.91(a) to include this clarification; however, it notes that
EPE will continue to be subject to other applicable commission reporting requirements
during the freeze period that are not based on PURA Chapter 39.
§25.91(b), Definitions
CSW commented that the defined term "net dependable capability" (NDC) in §25.91(b)
and the reference to "summer net dependable capability" §25.91(f) will
be subject to a variety of interpretations which will lead to inconsistencies
in the calculations made by various reporting entities. CSW recommended the
use of nameplate ratings that it said would be more easily determined and
verified. PG&E replied that NDC provides a more accurate measure of the
capacity available during peak periods when the potential for market power
abuses is at its highest. However, PG&E would not object to modifying
the definition of "summer net dependable capability" to provide more uniformity
in its determination.
The commission believes it is appropriate to measure capacity that is available
during peak periods when the potential for market power abuse is at its highest.
NDC rating is a well- established requirement in ERCOT, and the commission
believes that other reliability councils have comparable requirements although
they may use slightly different terms. Therefore, the commission modifies
the definition of "summer net dependable capability" to mean the net capability
of a generating unit for daily planning and operational purposes during the
summer peak season, as determined in accordance with the requirement of the
reliability council or independent organization in which the unit operates.
Reliant recommended the use of nameplate capacity ratings in §25.91(b)(1)
for renewable generators instead of some historical operating measure. It
noted that the output of renewable resources varies from year to year, which
would yield an inconsistent measure of installed capacity.
Although the actual peak capacity provided by a renewable generator may
vary from year to year, the year-to-year difference may be much less than
the difference between the nameplate rating and the actual performance. Some
renewable generation relies on intermittent resources, such as wind, and have
significantly less real capability than their nameplate capacity. Therefore,
the commission believes the historical measure is a more appropriate measure
of the capacity of a renewable resource, and declines to make the change recommended
by Reliant.
§25.91(c), Filing requirements
EGSI commented that filing such a broad list of operational measures on
an annual basis is burdensome and inconsistent with the spirit of competition.
SPS recommended that the reporting date be moved from the end of February
to May 15th or later to allow companies to incorporate information from their
FERC Form 1 reports.
The commission does not agree that annual filing of the information required
by this rule is burdensome. Information filed on a less frequent basis would
not be timely enough to be of value. In addition, to the extent that market
power abuse issues arise, they are likely to occur during the summer peak
period. An annual filing made on May 15th or later would be received too late
for the commission to evaluate the information and take any needed actions
prior to the summer peak season. Therefore, the commission declines to make
the changes recommended by EGSI and SPS.
§25.91(e), Confidentiality
TXU commented that the use of a standard protective order as provided in §25.91(e)
is not appropriate because the generating capacity reports will not be filed
as part of a contested proceeding. It recommended that §25.91(e) should
permit reporting parties to designate information as "competitively sensitive"
since PURA §39.155(a) requires the commission to administer the reporting
requirements in a manner that "ensures" the confidentiality of "competitively
sensitive information." TXU also recommended the rule should expressly state
that information designated as "competitively sensitive" shall be considered
exempt from the disclosure requirements of Chapter 552, Government Code. TXU
noted that Government Code §552.110 exempts from disclosure "commercial
or financial information obtained from a person and privileged or confidential
by statute…"
PURA §39.155(a) requires the commission to administer the reporting
requirements "in a manner that ensures the confidentiality of competitively
sensitive information." This requirement is not equivalent to saying that
information filed automatically qualifies for an exemption from the Open Records
act. Government Code §552.110 states that "a trade secret or commercial
or financial information obtained from a person and privileged or confidential
by statute or judicial decision is excepted from the requirements of §552.021."
The commission does not agree that the information to be submitted in the
generating capacity reports becomes "privileged or confidential by statute
or judicial decision" by virtue of being submitted pursuant to PURA §39.155(a).
Therefore, the commission declines to make the changes recommended by TXU.
§25.91(g), Reporting requirements
EGSI commented that much of the information requested in §25.91(g)
is unnecessary and unduly burdensome. It recommended the information only
be required when there is evidence of market power abuse or a complaint is
filed alleging market power abuse. In reply comments, PG&E said that the
reporting requirements should be retained, except for the highly sensitive
competitive information in §25.91(g)(2)(H)-(L), to help the commission
perform market monitoring and ensure compliance with the requirements of PURA,
including the 20% limitation on the ownership of capacity.
Based on amendments made pursuant to comments, the commission does not
believe that the revised information required in §25.91(g) is unnecessary
and unduly burdensome. It notes that PURA §39.155(a) requires generating
entities to report "any other information necessary for the commission to
assess market power or the development of a competitive retail market in the
state." The commission has reviewed the comments and reply comments on specific
subparts of the proposed rule and will address them in the following paragraphs.
Alcoa and OxyChem commented that the proposed rule imposes a much greater
burden on cogenerators than the prior requirements in P.U.C. Substantive Rule §25.105
of this title. They were very concerned about the amount of information, especially
the highly confidential information, that would have to be reported on an
annual basis. They argued that cogenerators should continue to report according
to the §25.105 requirements, and that additional data should only be
required when there is a complaint by a market participant that an abuse of
market power has or is likely to occur. FPLE and PGCs expressed the same concerns
on behalf of EWGs as well as cogenerators and recommended that EWGs and cogenerators
also should continue to report according to the §25.105 requirements.
When it revised Substantive Rule §25.105, the commission intended
to simplify the registration requirements for power generation companies and
to consolidate the reporting requirements in a separate rule. The commission
believes that annual reporting is necessary because the commission is charged
with monitoring capacity market shares and market power. It is likely that
some of the information to be reported annually may not change significantly
from year to year. Therefore, the reporting requirements may be less burdensome
than they appear.
FPLE also argued that even if the requirements in the proposed rule are
appropriate for incumbent utilities in Texas or their generation affiliates,
they are not appropriate for independent power generation companies which
are just entering the market in Texas and cannot wield market power. CSW and
Reliant replied that a distinction in reporting requirements for small or
non-affiliated owners of generation capacity would not be consistent with
statutory provisions, and it would unfairly disadvantage those entities that
are required to file extensive reports. CSW added that such a distinction
would limit the commission's ability to monitor and evaluate market power.
Reliant added that PURA §39.001(c) prohibits the commission from discriminating
against any market participant or type of market participant during the transition
to a competitive market or in the competitive market.
The commission does not agree that it would be appropriate to have separate
reporting requirements for generating entities that are not affiliated with
incumbent utilities in the state. Independent PGCs and new entrants can accumulate
generation market share quickly, whether through construction or acquisition.
All power generation companies should file the same generating capacity reports.
Market power abuse may occur in a localized area and may not be a function
of the total amount of generation in a power region. Therefore, the commission
declines to make any changes in response to FPLE's comments.
Subsection (g)(1)
PG&E recommended two additional categories of information be required
in §25.91(g)(1). First, it recommended that parties report total capacity
under contract to affiliates from unaffiliated entities so the commission
can better monitor the total capacity controlled by a single affiliate group.
Second, it recommended that parties report affiliate capacity that will be
connected to a transmission or distribution system within 12 months so the
commission would have better information on the capacity owned by a single
group. In reply comments, Reliant argued that both categories are unnecessary
since the commission will already have the information. It pointed out that
PGCs must identify wholesale and retail electric affiliates in Texas when
they register with the commission pursuant to Substantive Rule §25.109
of this title, and that all entities that generate electricity for sale in
the state will file the capacity reports to be approved in §25.91.
The commission agrees with Reliant that the information requested by PG&E
could be determined from the information filed under Substantive Rule §25.109
of this title and proposed §25.91. The commission declines to make the
changes recommended by PG&E
TXU Electric proposed adding a new subpart under §25.91(g)(1) that
would require reporting parties to provide the capacity of generating facilities
used to generate electricity for consumption by the person owning or controlling
the facility. It argued that this is necessary to be consistent with the definition
of "installed generation capacity" in PURA §39.154(d).
The commission agrees and makes the change proposed by TXU.
CSW requested clarification of whether the phrase "capacity dedicated to
its own use" in §25.91(g)(1)(F) referred to data on power plant consumption.
Subsection (f) of this section provides that generating unit capacity will
be reported at the summer net dependable capability. This value would be net
of power plant consumption. The commission intends that self generators report
the amount of capacity that they have reserved for their own use in response
to subsection (g)(1)(F).
SPS and Reliant argued that subsection (g)(1)(H) should be deleted because
there is no reason to risk inadvertent exposure of confidential, unit-specific
information that is not needed for market monitoring purposes. They also argued
that subsection (g)(1)(I) and (L) should be deleted because annual energy
and capacity sales to affiliated REPs are not relevant to the determination
of total market share. In reply comments, PG&E argued that the information
in (g)(1) can be required pursuant to PURA §39.155(a); it said the reporting
requirement should be retained since it is designed to facilitate the commission's
market monitoring function.
Consistent with the commission's conclusion that anticipated plant retirements
will not be excluded from the market share denominator, the rule is amended
to delete this reporting requirement from the generating capacity reports.
However, the commission believes that information on capacity and energy sales
to affiliated REPs is necessary for market oversight purposes. Therefore,
the commission declines to make the change recommended by Reliant.
SPS commented that the word "energy" in §25.91(g)(1)(J) and (K) should
be changed to "power" to conform to PURA §39.155(a).
Although PURA uses the term "power," the commission believes that the term
"energy" is more commonly used in this context. Therefore, the commission
declines to make the change recommended by SPS.
Subsection (g)(2)
Alcoa, CSW, FPLE, OxyChem, PGCs, Reliant, SPS, TIEC, and TXU strenuously
objected to subparagraphs (H) through (L) because they would require routine
reporting of information that the parties view as highly confidential and
competitively sensitive. In addition, the parties argued that the information
in subparagraphs (H) through (L) is not needed by the commission to assess
market power or the development of a competitive retail market in the state.
Reliant and SPS also objected to subparagraph (M) for the same reasons. AE
objected to all of paragraph (g)(2) for the same reasons.
OxyChem, PGCs, and TIEC argued that the information specified in subparagraphs
(H) through (L) is particularly sensitive for industrial cogenerators and
self-generators. TIEC said that information such as heat rate provides critical
cost information that would allow a competitor to ascertain not only the cost
of electricity for an industrial customer with self- generation, but also
the production cost for the products made by that company. It said that for
some industries that use self-generation or cogeneration, electricity comprises
up to 70% of their production costs. FPLE and PGCs stressed that there would
be no assurance that competing generators or prospective buyers could not
obtain the information through the Open Records Act. Reliant and TXU commented
that even though the reports could be filed under a protective order, there
was a risk that the information could be disclosed inadvertently.
CSW, EGSI, OxyChem, PGCs, and PG&E argued that the information in subparagraphs
(H)-(L) should only be required if the commission had a specific need for
it, such as investigating a complaint of market power abuse. PGCs and PG&E
said the commission has sufficient authority under PURA to require this kind
of data from any generator against whom a complaint has been lodged of potential
market power abuse.
SPS recommended that if the commission deems the information in subparagraphs
(H) through (M) to be necessary, then it should adopt a standard reporting
format such as that provided to the North American Electric Reliability Council.
CPS, CSW, OxyChem, PGCs, PG&E, and TIEC acknowledged the commission's
responsibility to monitor market power and its authority under PURA §39.155(a)
to require reporting of "any other information necessary for the commission
to assess market power or the development of a competitive retail market in
the state." CPS suggested that such assessments might be better achieved through
the establishment of an effective market monitoring program in conjunction
with the ERCOT ISO (or the independent organizations in non-ERCOT regions).
FPLE recommended that the commission obtain generating data through the Package
3 data collection processes being developed by the ERCOT ISO. PGCs supported
FPLE's recommendation, provided that any information obtained from the ISO
could be submitted pursuant to a protective order.
PG&E said the commission should not defer to the ERCOT data collection
process for determining whether market power abuses have occurred. It said
the commission's reporting requirements are designed to facilitate monitoring
the market and mitigating any market power abuses and, therefore, the requirements
should be retained.
The commission does not agree that all of the information in subsection
(g)(2) is highly confidential, competitively sensitive information, but it
acknowledges the concern expressed by all the parties about the sensitivity
of the information specified in subparagraphs (H) through (M). The commission
agrees that it would be more appropriate to require this information only
if it is needed for an investigation of possible market power abuse. Therefore,
the commission deletes proposed subparagraphs (H) through (M) and adds a new
subsection (h) that would require reporting parties upon request to provide
additional information to the commission within 15 days.
At this time, the commission declines to adopt the recommendations by CPS
and FPLE to rely upon the market monitoring process or the ERCOT Package 3
database for all information beyond the minimum generation capacity share
data. The ERCOT database is still in development, and the scope of the commission's
market surveillance function has not yet been fully determined. Once those
processes are in place, the commission will revisit this provision.
Subsection (g)(3)
SPS commented that it was not clear if subsection (g)(3) was meant to apply
to generation that is used on-site or sold at retail only.
Based on the commission's decision concerning §25.401(e)(2) to include,
rather than exclude grid-connected self-generation and cogeneration greater
than 1 MW in the market share denominator, it is not necessary for parties
to file this information as part of their generating capacity reports. The
commission amends the proposed rule to delete the requirement.
Subsection (g)(5)
Section 25.91(g)(5) requires a reporting party to provide an explanation
of generation that it owns but does not control. PGCs expressed concern that
a detailed description of contractual rights and responsibilities would constitute
highly confidential and competitively-sensitive information that should not
be required.
For purposes of this reporting requirement, a brief explanation of the
other party's control of the generating unit will be adequate. The commission
is not seeking a detailed description of contractual rights and responsibilities.
The commission amends the provision to clarify this point.
Subsection (g)(8)
SPS and Reliant recommended that subsection (g)(8) be deleted because must-run
unit status is not relevant to the determination of market shares.
The commission deletes this information requirement because it has determined
that must- run capacity will be included in installed generation capacity
for the power region. Therefore, it is not necessary to have must-run capacity
reported.
Subsection (g)(9)
CSW commented that information on the amount of transmission import capacity
in §25.91(g)(9) is "more appropriately" obtained from the entity that
supervises the applicable power region.
The commission declines to make the change recommended by CSW. Although
the independent organization for the power region would likely be a good source
of information on transmission import capacity, the commission's authority
to require this information from independent organizations for power regions
that include other states is not clear.
SPS and Reliant recommended that subsection (g)(9) be deleted because transmission
import capacity is not relevant to the determination of capacity market shares,
unless a PGC purchases electricity from itself or an affiliate outside the
power region.
The commission declines to make the change recommended by SPS and Reliant.
Subsection (g)(9) will provide information that the commission will need in
order to calculate generation market shares in accordance with proposed §25.401.
§25.401 Share of Installed Capacity
All comments concerning §25.401(e)(2)(A) - (G) are summarized in the
prior section of this document that discusses the published preamble question.
§25.401(a), Application
TXU commented that §25.401 must apply to persons, municipally owned
utilities, electric cooperatives, and river authorities that own generating
facilities and offer electricity for sale in the state because §25.401
provides the definition of "installed generation capacity" that is used in
proposed §25.90 and §25.91.
The commission does not believe it is necessary to include the other generators
in the application section in order for this rule to incorporate by reference
the definition of "installed generation capacity" in another rule. The commission
declines to make the change recommended by TXU.
§25.401(c), Capacity ratings
Reliant suggested changing the last line of proposed §25.401(c) to
say, "The commission may revise reported capacity estimates if they are found
to be substantially incorrect and contrary to known published estimates."
It said that estimates of net dependable capability for cogenerators, for
example, are proprietary in nature, and therefore existing utilities and their
affiliate PGCs should not be held accountable for small differences or even
transitory changes in capacity estimates.
The commission declines to make the change recommended by Reliant because
it is not necessary. The purpose of the last sentence in §25.401(c) is
to clarify that the commission will not be obligated to use the submitted
capacity ratings if it determines that they are incorrect. The sentence does
not automatically attach blame or consequences to the party who submits capacity
ratings that are subsequently changed by the commission.
§25.401(d), Installed generation capacity
of a power generation company
TXU recommended that the proposed language should be clarified by adding
the phrase "that is produced by installed generation capacity owned and controlled
by such power generation company" to the end of proposed §25.401(d)(2).
It said this is necessary for consistency with PURA §39.154(a).
Reliant and SPS argued that transmission import capacity reserved by a
power generation company should not be considered a part of its generating
capacity as currently stated in §25.401(d)(2). They noted that transmission
is reserved through open access rules, and that transmission may be reserved
for many reasons including ancillary services. SPS averred that transmission
reservation during the summer peak period will have little to do with market
power. SPS argued that transmission reservation is only important if the power
generation company has to purchase electricity from itself or an affiliate
outside the power region; in which case, such purchase would be considered
in the power generation company's market share calculation, and the transmission
reservation would be considered in the total power region calculation under
the category "capable of delivering electricity to, the power region."
The commission generally agrees with SPS. The numerator of the capacity
share calculation should include the transmission capacity that is reserved
for the purpose of importing generation capacity that is owned by the power
generation company or an affiliate in another power region. The commission
amends §25.401(d)(2) accordingly.
TXU proposed that an electric utility or power generation company be allowed
to provide evidence other than a Texas Natural Resource Conservation Commission
(TNRCC) permit application to demonstrate that it has committed to complying
with PURA §39.264. TIEC commented that the mere filing of an application
with the TNRCC should not be considered a binding commitment to comply with
PURA §39.264 since an applicant can withdraw its application prior to
approval. TIEC recommended therefore that grandfathered facilities only be
excluded from the determination of market share if the PGC's TNRCC application
has been approved. In addition, TIEC recommended that the derated capacity
of grandfathered units after pollution control equipment has been added should
be used for the market concentration analysis.
In reply comments, TIEC urged the commission to reject TXU's proposal to
allow the submission of evidence other than the TNRCC permit application.
TIEC noted that it was not clear what evidence TXU had in mind, but it reiterated
its initial comments that only an approved TNRCC application would constitute
a binding commitment and justify the exclusion of the grandfathered capacity
from the market share calculation. PG&E agreed with TIEC. As an alternative,
it said the rule could provide that the filing of a TNRCC application would
only be considered a binding commitment if the PGC agreed not to withdraw
the application without the express consent of the commission.
The commission understands that a grandfathered facility must receive a
permit for the emission of air contaminants from TNRCC or it will not be allowed
to operate after May 1, 2003. Therefore, submission of a permit application
will be considered adequate evidence of a binding commitment to comply with
PURA §39.264. However, the commission will review the progress on achieving
an approved TNRCC application when it determines market share percentages.
If adequate progress has not been made, the commission may chose not to exclude
the grandfathered facility from the numerator of the market share calculation.
The commission amends proposed §25.401(d)(3) to require that adequate
progress must be shown. It also amends proposed §25.91 to require that
a utility report on its progress as part of its annual Generating Capacity
Report. The commission declines the recommendations made by TXU, PG&E,
and TIEC.
§25.401(e), Total installed generation
EGSI and TXU commented that the capacity of generating facilities located
on the boundary between two power regions should not be allocated between
the regions as currently stated in subsection (e)(1)(D). EGSI said that capacity
would be sold into either power region based on prices. TXU said the entire
capacity of a boundary facility should be included in the installed generation
capacity for each power region because it is potentially marketable in either
region. Reliant argued that allocating the capacity of a dual-sited generation
facility based on historical sales is flawed logic because the previous year
has no bearing on future sales.
TIEC argued that the allocation of capacity from generation facilities
on the boundary between two power regions should reflect any firm commitments
of power from such facilities. To the extent the facility has a firm contract
to supply specific amounts of power to customers within a given power region
during the study period, the amount of power committed under the contract
should be assigned to that power region for the market concentration analysis.
In reply comments, PG&E agreed with TIEC. It disagreed with EGSI, Reliant,
and TXU, pointing out that if both power regions are constrained, which is
not unlikely during the peak period, the total capacity is not available to
both regions to mitigate market power. CSW agreed with EGSI, arguing that
allocation based upon historical data would be of little value because such
data would be of little value with respect to capacity under different market
conditions. It said such capacity should be included in the denominator for
both power regions. Also in reply comments, TIEC said that including the entire
capacity in both regions results in obvious double- counting of the same capacity.
The commission believes it is appropriate to allocate the capacity as stated
in the proposed rule. Historical information is an imperfect predictor of
the future, but it is preferable to double- counting the capacity.
TIEC recommended that the commission establish an appropriate method of
determining total transmission import capacity. For example, total import
capacity could be defined either be a transmission connection's thermal rating
or by the connection's total transmission capability as reported on the regional
Open Access Same Time Information System. TIEC said this issue merits further
study to determine the appropriate approach.
The commission agrees that this issue needs further study, and it makes
no change to the proposed rule.
All comments, including any not specifically referenced herein, were fully
considered by the commission. In adopting these sections, the commission makes
other minor modifications for the purpose of clarifying its intent.
Subchapter D. RECORDS, REPORTS, AND OTHER REQUIRED INFORMATION
16 TAC §25.90, §25.91
These new sections are adopted under the Public Utility Regulatory
Act, Texas Utilities Code Annotated §14.002 (Vernon 1998, Supplement
2000) (PURA), which provides the Public Utility Commission with the authority
to make and enforce rules reasonably required in the exercise of its powers
and jurisdiction; and specifically, PURA §39.154, which requires the
commission to determine the percentage shares of installed generation capacity
that are owned and controlled by a utility or a power generation company; §39.155,
which grants the commission the authority to assess market power and to require
the filing of generation capacity reports; §39.156, which grants the
commission the authority to require the filing of market power mitigation
plans; and §39.157, which grants the commission the authority to address
market power and to monitor the market shares of installed generation capacity
to ensure that the limitations in PURA §39.154 (relating to Limitation
of Ownership of Installed Capacity) are not exceeded.
Cross Reference to Statutes: Public Utility Regulatory Act §§14.002,
14.003, 31.002, 39.154, 39.155, 39.156, 39.157, and 39.264.
§25.90.Market Power Mitigation Plans.
(a)
Application. An electric utility or power generation company
that the commission determines owns and controls more than 20% of the installed
generation capacity located in, or capable of delivering electricity to, a
power region shall file a market power mitigation plan with the commission
not later than December 1, 2000. An electric utility or power generation company
that the commission determines owns and controls more than 20% of the installed
generation capacity located in, or capable of delivering electricity to, a
power region after January 1, 2002, shall file a market power mitigation plan
as directed by the commission. The commission may, for good cause, waive or
modify the requirement to file a market power mitigation plan, in accordance
with Public Utility Regulatory Act (PURA) §39.154(b). This section does
not apply to an electric utility subject to PURA §39.102(c) until the
end of the utility's rate freeze.
(b)
Initial information filing. Each utility or power generation
company that owns and controls, either separately or in combination with its
affiliates, more than 10,000 megawatts (MW) of electric generation capacity
located in a power region that is partly or entirely within the state shall
file a calculation by September 5, 2000, detailing the installed generation
for its power region expected as of January 1, 2002, and showing its percentage
share of the installed generation capacity located in, or capable of delivering
electricity to, the power region, plus the capacity expected to be interconnected
to the transmission system by January 1, 2002, less the capacity to be auctioned
off pursuant to PURA §39.153, and any grandfathered facilities capacity
pursuant to PURA §39.154(e). The calculation shall be made pursuant to
the requirements of §25.401 of this title (relating to Share of Installed
Generation Capacity). The filing shall include detailed information that will
allow the commission to replicate the calculation. At a minimum, the filing
must include an itemized list of all generating units that are located in,
or capable of delivering electricity to, the power region and are owned and
controlled by the utility or power generation company and its affiliates in
the power region or capable of delivering electricity to the power region.
Generating units should be identified by name, capacity rating, ownership,
location, and reliability council. Capacity shall be rated according to the
method established in §25.91(f) of this title (relating to Generating
Capacity Reports). The filing shall also include the transmission import capacity
amounts that are to be included in the numerator and the denominator of the
calculation prescribed by §25.401 of this title and an explanation of
how the transmission capacity amounts were determined. Any interested parties
may respond to the utility filings by filing comments with the commission
by September 29, 2000. By October 20, 2000, the commission will indicate which
utilities, if any, exceed the 20% threshold and are required to file a market
power mitigation plan on or before December 1, 2000.
(c)
Market power mitigation plan. A market power mitigation
plan is a written proposal by an electric utility or a power generation company
for reducing its ownership and control of installed generation capacity as
required by PURA §39.154. A market power mitigation plan may provide
for:
(1)
the sale of generation assets to a nonaffiliated person;
(2)
the exchange of generation assets with a nonaffiliated
person located in a different power region;
(3)
the auctioning of generation capacity entitlements as part
of a capacity auction required by PURA §39.153;
(4)
the sale of the right to capacity to a nonaffiliated person
for at least four years; or
(5)
any reasonable method of mitigation.
(d)
Filing requirements. The plan shall include all supporting
information necessary for the commission to fully understand and evaluate
the plan. On a case-by-case basis, the commission may require the electric
utility or power generation company to provide any additional information
the commission finds necessary to evaluate the plan. The plan submitted should
incorporate information addressing the determinations listed in subsection
(f) of this section.
(e)
Procedure. The commission shall approve, modify, or reject
a plan within 180 days after the date of filing. The commission may not modify
the plan to require divestiture by the electric utility or power generation
company.
(f)
Commission determinations. In reaching its determination
under subsection (e) of this section, the commission shall consider:
(1)
the degree to which the electric utility's or power generation
company's stranded costs, if any, are minimized;
(2)
whether on disposition of the generation assets the reasonable
value is likely to be received;
(3)
the effect of the plan on the electric utility's or power
generation company's federal income taxes;
(4)
the effect of the plan on current and potential competitors
in the generation market;
(5)
whether the plan provides adequate mitigation of market
power; and
(6)
whether the plan is consistent with the public interest.
(g)
Request to amend or repeal mitigation plan. An electric
utility or power generation company with an approved mitigation plan may request
to amend or repeal its plan. On a showing of good cause, the commission may
modify or repeal the mitigation plan.
(h)
Approval date. If an electric utility's or power generation
company's market power mitigation plan is not approved before January 1 of
the year it is to take effect, the commission may order the electric utility
or power generation company to auction generation capacity entitlements according
to PURA §39.153, subject to commission approval, of any capacity exceeding
the maximum allowable capacity prescribed by PURA §39.154 until the mitigation
plan is approved. An auction held under this subsection shall be held not
later than 60 days after the date the order is entered.
§25.91.Generating Capacity Reports.
(a)
Application. This section applies to each person, power
generation company, municipally owned utility, electric cooperative, and river
authority that owns generation facilities and offers electricity for sale
in this state. This section does not apply to an electric utility subject
to Public Utility Regulatory Act (PURA) §39.102(c) until the end of the
utility's rate freeze.
(b)
Definitions. The following words and terms, when used in
this section, shall have the following meanings unless the context clearly
indicates otherwise.
(1)
Nameplate rating - The full-load continuous rating of a
generator under specified conditions as designated by the manufacturer.
(2)
Summer net dependable capability - The net capability of
a generating unit in megawatts (MW) for daily planning and operational purposes
during the summer peak season, as determined in accordance with requirements
of the reliability council or independent organization in which the unit operates.
(c)
Filing requirements. Reporting parties shall file reports
of generation capacity with the commission by the last working day of February
each year, based on the immediately preceding calendar year. Filings shall
be made using a form prescribed by the commission.
(d)
Report attestation. A report submitted pursuant to this
section shall be attested to by an owner, partner, or officer of the reporting
party under whose direction the report was prepared.
(e)
Confidentiality. The reporting party may designate information
that it considers to be confidential. Information designated as confidential
will be treated in accordance with the standard protective order issued by
the commission applicable to generating capacity reports.
(f)
Capacity ratings. Generating unit capacity will be reported
at the summer net dependable capability rating, except as follows:
(1)
Renewable resource generating units that are not dispatchable
will be reported at the actual capacity value during the most recent peak
season, and the report will include data supporting the determination of the
actual capacity value;
(2)
Generating units that will be connected to a transmission
or distribution system and operating within 12 months will be rated at the
nameplate rating.
(g)
Reporting requirements.
(1)
Each reporting party shall provide the following information
concerning its generation capacity (in MW) and sales (in megawatt-hours (MWh))
on a power region-wide basis and for that portion of a power region in the
state:
(A)
total capacity of generating facilities that are connected
with a transmission or distribution system;
(B)
total capacity of generating facilities used to generate
electricity for consumption by the person owning or controlling the facility;
(C)
total capacity of generating facilities that will be connected
with a transmission or distribution system and operating within 12 months;
(D)
total affiliate installed generation capacity;
(E)
total amount of capacity available for sale to others;
(F)
total amount of capacity under contract to others;
(G)
total amount of capacity dedicated to its own use;
(H)
total amount of capacity that has been subject to auction
as approved by the commission;
(I)
total amount of capacity that will be retired within 12
months;
(J)
annual capacity sales to affiliated retail electric providers
(REPs);
(K)
annual wholesale energy sales;
(L)
annual retail energy sales; and
(M)
annual energy sales to affiliate REPs;
(2)
Each reporting party shall provide the following information
for each generating unit it owns in whole or in part:
(A)
Name;
(B)
Location by county, utility service area, power region,
reliability council, and, if applicable, transmission zone;
(C)
Capacity rating (MW) as specified in subsection (f) of
this section;
(D)
Annual generation (MWh);
(E)
Type of fuel or nonfuel energy resource;
(F)
Technology of natural gas generator; and
(G)
Date of commercial operation.
(3)
Each reporting party shall identify the name and capacity
rating of each generating unit that it owns that is partly owned by other
parties. For each such unit, it shall identify the other owners and their
respective ownership percentages.
(4)
Each reporting party shall identify the name and capacity
rating of each generating unit that it owns but does not control. For each
such unit, it shall identify the controlling party and briefly explain the
nature of the other party's control of the unit.
(5)
Each reporting party shall identify the name and capacity
rating of each generating unit that it owns that is located on the boundary
between two power regions and able to deliver electricity directly into either
power region, and shall report the total sales from each such unit for the
preceding year by power region.
(6)
Each reporting party that is subject to the PURA §39.154(e)
shall identify the name and capacity rating of each "grandfathered" generating
unit that it owns in an ozone non-attainment area. Each reporting party shall
also provide copies of any applications to the Texas Natural Resources Conservation
Commission (TNRCC) for a permit for the emission of air contaminants related
to the grandfathered units, and it shall also provide a description of the
progress it has made since its last Generating Capacity Report on achieving
approval of each such TNRCC permit.
(7)
Each reporting party shall identify the amount of transmission
import capability that it has reserved and is available to import electricity
during the summer peak into the power region from generating facilities that
are owned by the reporting party or its affiliate in another power region.
(h)
Upon written request by the person responsible for the
commission's market oversight program, a reporting party shall provide within
15 days any information deemed necessary by that person to investigate a potential
market power abuse as defined in PURA §39.157(a). In addition, the commission
may request reporting parties to provide any information deemed necessary
by the commission to assess market power or the development of a competitive
retail market in the state, pursuant to §39.155(a). A reporting party
may designate information provided to the commission as confidential in accordance
with subsection (e) of this section.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on August 11, 2000.
TRD-200005649
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: August 31, 2000
Proposal publication date: April 28, 2000
For further information, please call: (512) 936-7308
4.
OTHER MARKET POWER ISSUES
16 TAC §25.401
These new sections are adopted under the Public Utility Regulatory
Act, Texas Utilities Code Annotated §14.002 (Vernon 1998, Supplement
2000) (PURA), which provides the Public Utility Commission with the authority
to make and enforce rules reasonably required in the exercise of its powers
and jurisdiction; and specifically, PURA §39.154, which requires the
commission to determine the percentage shares of installed generation capacity
that are owned and controlled by a utility or a power generation company; §39.155,
which grants the commission the authority to assess market power and to require
the filing of generation capacity reports; §39.156, which grants the
commission the authority to require the filing of market power mitigation
plans; and §39.157, which grants the commission the authority to address
market power and to monitor the market shares of installed generation capacity
to ensure that the limitations in PURA §39.154 (relating to Limitation
of Ownership of Installed Capacity) are not exceeded.
Cross Reference to Statutes: Public Utility Regulatory Act §§14.002,
14.003, 31.002, 39.154, 39.155, 39.156, 39.157, and 39.264.
§25.401.Share of Installed Generation Capacity.
(a)
Application. The provisions of this section apply to power
generation companies.
(b)
Share of installed generation capacity. The percentage
share of installed generation capacity for a power generation company will
be determined by dividing the installed generation capacity owned and controlled
by the power generation company in, or capable of delivering electricity to,
a power region by the total installed generation capacity located in, or capable
of delivering electricity to, the power region.
(c)
Capacity ratings. For purposes of this section, generating
unit capacity ratings shall be consistent with §25.91(f) of this title
(relating to Generating Capacity Reports). The commission may revise reported
capacity ratings if they are found to be incorrect.
(d)
Installed generation capacity of a power generation company.
(1)
In determining the percentage shares of installed generation
capacity under the PURA §39.154, the commission shall combine capacity
owned and controlled by a power generation company and any entity that is
affiliated with that power generation company within the power region, reduced
by the installed generation capacity of those facilities that are made subject
to capacity auctions under PURA §39.153(a) and (d).
(2)
In determining the percentage shares of installed generation
capacity, the commission shall increase the installed generation capacity
owned and controlled by a power generation company by the transmission import
capability that is available for importing electricity during the summer peak
season into the power region from generating facilities that are owned by
the power generation company or an affiliate in another power region.
(3)
In determining the percentage shares of installed generation
capacity owned and controlled by a power generation company under PURA §39.154
and §39.156, the commission shall, for purposes of calculating the numerator,
reduce the installed generation capacity owned and controlled by that power
generation company by the installed generation capacity of any "grandfathered
facility" within an ozone nonattainment area as of September 1, 1999, for
which that power generation company has commenced complying or made a binding
commitment to comply with PURA §39.264. This paragraph applies only to
a power generation company that is affiliated with an electric utility that
owned and controlled more than 27% of the installed generation capacity in
the power region on January 1, 1999. The commission will consider a permit
application to the Texas Natural Resource Conservation Commission (TNRCC)
to be adequate evidence that the power generation company has commenced complying
or made a binding commitment to comply with PURA §39.264. However, the
commission will review the progress that has been made on achieving an approved
an TNRCC permit, when it reviews and updates market share percentages, and
if adequate progress has not been made, the commission may choose to include
the grandfathered capacity in the numerator.
(e)
Total installed generation. The total installed generation
will consist of the installed generation capacity that is located in, or capable
of delivering electricity to, a power region.
(1)
Installed generation capacity will include all potentially
marketable electric generation capacity. Except as provided in paragraph (2)
of this subsection, installed generation capacity will include:
(A)
generating facilities that are connected with a transmission
or distribution system;
(B)
generating facilities used to generate electricity for
consumption by the person owning or controlling the facility;
(C)
generating facilities that will be connected with a transmission
or distribution system and operating within 12 months; and
(D)
generating facilities that are located on the boundary
between two power regions and are able to deliver electricity directly into
either power region, except that the capacity of such facility shall be allocated
between the power regions based on the share of its total electric energy
that the facility sold in each power region during the preceding year.
(2)
Installed generation capacity will not include generating
facilities that have a nameplate rating equal to or less than 1 megawatt (MW).
(3)
The amount of installed generation capacity that is capable
of delivering electricity to a power region will be determined by:
(A)
the import transmission capacity during the summer peak
period of the alternating current transmission interconnections between the
power region at issue and other power regions; and
(B)
the import capacity during the summer peak period of the
reliable direct current interconnections between the power region at issue
and other power regions.
This agency hereby certifies that the adoption
has been reviewed by legal counsel and found to be a valid exercise of the
agency's legal authority.
Filed
with the Office of the Secretary of State on August 11, 2000.
TRD-200005648
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: August 31, 2000
Proposal publication date: April 28, 2000
For further information, please call: (512) 936-7308
16 TAC §25.431
The Public Utility Commission of Texas (commission) adopts
new §25.431, relating to Retail Competition Pilot Projects, with changes
to the proposed text as published in the June 16, 2000,
Texas Register
(25 TexReg 5772). This new section is adopted under
Project Number 21407. The new rule is necessary to implement Public Utility
Regulatory Act (PURA), Texas Utilities Code Annotated §39.104 and §39.405.
PURA §39.104,
Customer Choice Pilot Projects
, directs the commission to require utilities to conduct pilot projects
beginning June 1, 2001, and PURA §39.405,
Pilot
Project
, sets forth additional requirements for pilot projects conducted
by utilities that are subject to the provisions of PURA Chapter 39, Subchapter
I. Section 25.431 establishes the requirements and procedures for these pilot
programs.
The commission used the negotiated rulemaking procedures set forth in Texas
Government Code, Chapter 2008, for this project. The commission formally appointed
a committee of interested stakeholders to serve on the negotiating committee
and develop a proposed rule. Meetings of the negotiating committee were held
in Austin, Texas, every Monday from March 6 through May 1, 2000, with additional
meetings held on Tuesday, April 4 and Thursday May 11. Additional caucus meetings
were held as necessary, and the committee members relied heavily on electronic
communication to work through issues between meetings.
As a result of its negotiations, the committee was able to reach consensus
on most aspects of the proposed rule. There were two issues, however, on which
the committee was unable to reach consensus: 1) whether to use a lottery to
select participants in the residential customer class, and 2) how to set delivery
rates for the pilot if the commission has not set interim rates in the utilities'
unbundled cost of service (UCOS) cases by May 2001. The committee agreed that
these two issues should be identified in the preamble of the published rule
for the purpose of soliciting public comment, and that all members of the
committee were free to offer comments on these two issues.
The commission received comments on the proposed new section from the following
interested parties: American Association of Retired Persons, Consumers Union
Southwest Regional Office, Texas Legal Services Center, and Texas Ratepayers'
Organization to Save Energy (collectively Residential Consumers); Central
Power and Light Company, Southwestern Electric Power Company, and West Texas
Utilities Company (collectively AEP); Cities served by TXU Electric Company
and Central Power and Light (collectively Cities); Enron and the New Power
Company (collectively Enron); Greenmountain.com and NewEnergy (collectively
non- affiliated retail electric providers, or REPs); Entergy Gulf States,
Inc. (EGS); Reliant Energy, Incorporated (Reliant); Southwestern Public Service
Company (SPS); Texas Industrial Energy Consumers (TIEC); Texas-New Mexico
Power Company-Retail Electric Provider (TNMP-REP); Texas-New Mexico Power
Company-Distribution Utility (TNMP-DU); TXU Electric Company- Retail (TXU-REP);
TXU Electric Company-Distribution Utility (TXU-DU); and the United States
Department of the Army (Army).
No public hearing on the proposed new section was held under Government
Code §2001.029 because it was not requested by at least 25 persons, a
governmental subdivision or agency, or an association having at least 25 members.
Preamble Issue 1: Should a lottery be used to select participants in the
residential customer class? Paragraph (g)(1) sets forth a procedure for residential
customer participation that is first come, first served; as customers authorize
switches to retail electric providers, they are counted toward the 5.0% load
limit until such limit is reached. One option that was suggested during the
negotiating committee meetings was to allow customers to first indicate interest
in participating in the pilot project, and if that interest exceeded the 5.0%
limit, then a lottery would be held to determine which residential customers
could have the opportunity to switch providers.
Residential Consumers, non-affiliated REPs, Enron, TNMP-DU, TXU-REP, SPS,
and Cities supported the first come, first served methodology for selecting
participants in the residential customer class. Parties generally supported
this methodology because it would minimize confusion, simplify the process,
keep administrative costs low, and test whether the market will broadly include
demographic groups and all geographic areas. Reliant and EGS supported utility
choice of whether to use a first come, first served methodology or a lottery.
Reliant commented that a lottery would maximize the chance for any customer
to participate. EGS opposed requiring a lottery because utilities may not
be able to recover the costs of conducting a lottery.
The commission concludes that no changes to the proposed paragraph (g)(1)
are necessary. The commission agrees with the parties that the first come,
first served methodology for selecting participants in the residential customer
class will minimize confusion, simplify the process, keep administrative costs
low, and test whether the market will broadly include demographic groups and
all geographic areas.
Preamble Issue 2: How should the commission set rates for the pilot if
the commission has not set interim rates in the utilities' unbundled cost
of service (UCOS) cases by May 2001? Proposed subsection (h) is silent regarding
how the commission will set rates in the event that interim rates are not
set in the UCOS cases in time for use in the pilot programs. Although it is
the commission's intent to have interim rates set by May of 2001, and the
committee members agreed that the UCOS interim rates are the most appropriate
rates to be used during the pilot, the committee believed that the commission
needs a contingency plan in the event that procedural delays in those cases
result in interim rates not being set in time. The committee discussed several
options. First, the rule could be silent on the issue. Second, the commission
could rely on the proposed rates filed by the utilities in their UCOS cases,
or, similarly, on testimony filed by rate design witnesses for the commission's
Office of Regulatory Affairs in those cases. Third, the commission could rely
on the methodology employed in §25.227 of this title (relating to Electric
Utility Service for Public Retail Customers) (GLO Rule). Section 25.227 uses
the functional cost percentages for each rate class developed for each utility
in the final staff report in Project Number 20749,
Functional Cost Separation of Electric Utilities in Texas
, (May 1999)
to determine transmission and distribution (T&D) rate components. Section
25.227 also includes a methodology for determining competition transition
charges (CTC). Regardless of which contingency method should be used to set
pilot rates, though, the committee members agreed that such rates should not
be subject to true-up once final T&D rates are set.
All parties agreed that the most appropriate rate to use for the pilot
project is a commission approved interim rate based on the UCOS filings. In
the event the UCOS interim rates are not set, Residential Consumers and TIEC
supported the rule remaining silent on the issue. In the alternative, Residential
Consumers argued that if the interim rates are not set, the commission should
reconsider the start date of the pilot project because it is critical that
pilot project rates, like other aspects of the pilot project, mirror competition.
Other parties objected to the rule remaining silent, arguing that market participants
need more certainty in order to adequately plan for the pilot project and
subsequent retail market.
AEP, SPS, and Entergy commented that the commission should rely on the
proposed rates filed by the utilities in their UCOS cases, not subject to
true-up. TIEC, Cities, non-affiliated REPs, and Enron generally opposed the
utilities' proposed UCOS rates, arguing that the UCOS rates filed by the utilities
are too high, and some adjustments have already been ordered by the commission
in Docket Number 22344,
Generic Issues Associated
With Applications for Approval of Unbundled Cost of Service Rate Pursuant
to PURA §39.201 and Public Utility Commission Substantive Rule §25.344
. In addition, parties opposing the utilities' proposed UCOS rates
argued that if the filed rates are used without true-up, the utilities will
likely receive a financial gain.
Reliant, TXU-REP, Cities, and TXU-DU offered alternatives other than the
utilities' proposed UCOS filings. Reliant supported a temporary rate based
on either the companies' or the commission staff's proposed rates in the UCOS
filing, subject to true-up. Reliant argued that PURA §36.155 establishes
procedures for interim rates and requires refunds or surcharges if the temporary
rates are different from the rates approved. TXU-REP supported a fair method
stressing that rates should be utilized that reflect, as closely as possible,
the rates that will be in effect at market opening for a seamless transition
to retail competition. Cities recommended that the commission should convene
a limited proceeding to consider evidence regarding the appropriate proxy
and set the rates. TXU-DU commented that the utility should have the option
to bond rates at levels that it determines reasonable in accordance with PURA §36.110,
and such rates should be subject to true-up. TXU-DU argued that the bonding
procedures in PURA §36.110 have been utilized by utilities and this commission
in past proceedings and that procedures for accommodating this method are
in place and tested. Reliant supported this alternative in its reply comments.
Non-affiliated REPs and Enron commented that, in the event interim rates
are not approved in the UCOS cases, the commission should use the methodology
established in Project Number 20749, which is employed in §25.227 (GLO
rule). The parties argued that the rates developed in the GLO rule were presented
to the 76th Legislature, and are a more reasonably proxy for final rates.
Non-affiliated REPs and Enron opposed true-ups, arguing that such a process
is a barrier to participation because it would unreasonably expose a REP to
the entire risk of inaccurate collection or strip a REP of its ability to
offer its customers price certainty. CSW, TXU-REP, TXU-DU, SPS, EGS, and Reliant
opposed the methodology contained in the GLO rule. In reply comments, parties
argued that the GLO rule methodology does not reflect the commission's unbundling
and UCOS requirements because it was developed prior to the commission's unbundling
rules. As a result, the methodology does not accurately reflect the cost items
associated with unbundling, the cost levels, or rate design that utilities
are proposing in the UCOS cases. Opposing parties argued that because the
rate design and rate classes proposed for the unbundled T&D rates are
very different from the existing rate structure and rate classes, the purpose
of the pilot project to test systems and acquaint customers and market participants
with the restructured retail market would be frustrated if the GLO rates were
used.
The commission strongly agrees with all the parties that the most appropriate
rates to use for the pilot projects are commission approved interim rates
based on the UCOS filings. Such rates will provide the most seamless transition
to full retail competition. The commission agrees with Residential Consumers
that several aspects of the pilot project rule will be impacted by other rulemaking
projects and contested cases before the commission, and that the proposed
rule is silent where a decision is pending elsewhere. In addition, designating
a "backup" alternative methodology for setting the pilot rates offers no certainty
to market participants because such methodology would remain open until May
31, 2001, the date by which the commission must approve the pilot tariffs
pursuant to paragraph (h)(3). Accordingly, the commission concludes that the
rule should remain silent on the rates to be used in the event interim rates
are not approved in each individual UCOS case. The commission further adopts
the original consensus position of the committee that rates for the pilot
project are not subject to true-up.
Other Issues:
Several parties raised additional
issues in their comments.
TIEC commented that the term "registration agent" is not defined in the
rule, although TIEC assumed that it refers to the Electric Reliability Council
of Texas Independent System Operator (ERCOT ISO).
The commission finds that it is clear from the wording of the rule that
the term "registration agent" refers to the ERCOT ISO, and therefore declines
to adopt TIEC's proposed clarification.
Non-affiliated REPs noted concern with several informal discussions that
have taken place at ERCOT that would require non-affiliated REPs to participate
in a "mock market" before being eligible to participate in the pilot project.
The commission has noted the concerns of the non-affiliated REPs. However,
the commission finds that the appropriate forum in which to address such concerns
is in the mock market planning taking place at ERCOT. The commission affirms
that REPs are not required by this rule to participate in the mock market
as a prerequisite to participation in the pilot project, but declines to modify
the proposed rule language.
TNMP-REP commented that the rule does not address the eligibility of customers
who are delinquent in payment of their account with the integrated utility.
TNMP-REP also commented that the rule does not address disconnects for non-payment
during the pilot programs.
The commission declines to modify the proposed consensus rule to address
the treatment of customers with delinquent accounts because these issues are
most appropriately addressed in Project Number 22255,
Rulemaking Proceeding for Customer Protection Rules for Electric Restructuring
Implementing SB7 and SB 86
(Customer Protection Rulemaking). Consistent
with the intent of the pilot projects expressed in subsection (c) of the proposed
rule, the pilot programs should parallel full customer choice, therefore pilot
customers with delinquent accounts should be treated just as any such customer
will be treated once full retail competition begins, as determined in the
Customer Protection Rulemaking.
TIEC commented that the rule should require that any commission-approved
fuel surcharge be included in the interim rate charged in the pilot project.
In reply, Cities supported TIEC's comments and Reliant suggested that alternatively,
an exit fee could be charged at the end of the pilot to collect any additional
fuel surcharges.
The commission finds that this issue has been addressed in Docket Number
22650,
Petition of Reliant Energy HL&P to Revise
Fuel Factors and Implement Surcharge for Pilot Undercollected Fuel Costs.
Should this issue arise with respect to a fuel surcharge for any other
utility, the commission will give appropriate consideration at that time to
the precedential value of its ruling in Docket Number 22650. Accordingly,
the commission declines to modify the proposed rule language.
TNMP-DU commented on §25.431(b)(1), the application section, which
states that a pilot project commencing before the adoption of this section
may fulfill portions of the requirements of this section, as determined by
the commission. TNMP-DU commented that it currently has municipal aggregation
pilot programs underway in two municipalities and that these pilot projects
represent approximately 3.0% of its total Texas load. TNMP-DU requested that
the commission consider counting at least some of this load in fulfilling
the 5.0% mandate.
The commission finds that the application section does exactly what TNMP
requests, and that no changes to the proposed rule language are necessary.
TNMP shall make such request in its compliance filing pursuant to §25.431(l),
and the commission will then consider whether some of the load in its existing
municipal pilot projects will count toward the 5.0% load participation for
this pilot project.
AEP commented on §25.431(c)(4)(B) regarding the effect of pre-existing
contracts. AEP interpreted this provision as prohibiting a utility from challenging
a customer's right to participate in the pilot because the customer did not
provide notice of cancellation in compliance with the contract, but that the
utility may challenge a customer's right to participate in the pilot project
based on other factors associated with the existing contract. AEP argued that
in most instances, costs would be related to the construction of customer-specific
facilities and that "the utility should be able to insist on economic performance
of the customer's commitment, and participation in the pilot should not be
an opportunity for customers to game the system and fail to fulfill such commitments".
AEP noted that it understood that the affected utility can challenge a customer's
participation in the pilot project if the utility has not fully recovered
its costs as contemplated by an existing contract, unless alternative arrangements
are made (e.g., the customer agrees to discharge the outstanding obligation
for remaining costs).
The commission finds that AEP has a correct understanding regarding the
language in §25.431(c)(4)(B), and that such proposed language includes
the procedure for a utility to challenge a customer's participation in the
pilot. The commission concludes that the proposed rule language adequately
addresses AEP's concerns and that no clarification is necessary.
The Army commented that the definitions of customer classes in §25.431(d)(2)
should be expanded to include a specific class for government, due to the
distinct characteristics of governmental entities and their unique procurement
requirements.
The commission finds that although the federal government was not represented
on the negotiating committee, state agencies and public aggregators have similar
interests and were represented on the negotiating committee that agreed to
the definitions of customer classes. The Army has not shown that the federal
and state governments have different characteristics and interests with respect
to the activities contemplated by this rule, and therefore declines to modify
the proposed rule language.
TNMP-DU commented that §25.431(f) related to customer education should
be modified to suggest that for REPs who intend to serve only certain areas
of the state, that this information be placed next to the name of the REP
on the commission mailing.
The commission finds that this issue is most appropriately addressed in
Project Number 21251,
Implementation of Senate Bill
7 Provisions Regarding Customer Education About Electric Choice.
Accordingly,
the commission declines to modify the proposed rule.
TIEC commented on §25.431(g)(3)(A)(ii) that sets individual load caps
of 20% of the 5.0% allocated to the demand-metered non-residential customer
classes. TIEC argued that large industrial customers should be able to designate
only a portion of their load served by one meter to participate in the pilot,
because otherwise this cap would effectively eliminate participation by larger
industrial customers. TIEC argued that this is similar to a customer designating
a portion of its load to be served by one REP and a portion to be served by
another REP.
The commission finds that this issue was discussed and agreed to by the
negotiating committee, and that considerations were given to limitations at
ERCOT for splitting meter load during the pilot. Although TIEC did not participate
in the negotiations, large industrial customers were represented during the
negotiations. The cap is to assure that one large customer does not constitute
all or nearly all of the load eligible to participate from that customer class.
Accordingly, the commission declines to modify the proposed rule language.
In reply comments, AEP commented on §25.431(k) regarding the recovery
of costs associated with administering the pilot projects by the utilities.
AEP noted that this section provides three options by which utilities may
seek cost recovery, and reserves the rights of parties to challenge the utilities'
ability to seek cost recovery. AEP argued that because the commission ruled
in its open meeting on June 29, 2000, in Docket Number 22344,
Generic Issues Associated with Applications for Approval of Unbundled Cost
of Service Rates Pursuant to PURA Section 39.201 and Public Utility Commission
Subst. R. 25.344
, that utilities could not seek recovery of pilot program
administrative costs as part of their transmission and distribution rates,
AEP should no longer be bound by the results of the negotiated rulemaking
process. AEP argued that the commission's decision in Docket Number 22344
undercuts the consensual nature of the consensus rule language.
The commission finds AEP's argument without merit. The consensus language
states that the utilities "may request recovery from the commission…."
This language does not guarantee cost recovery through any of the three options,
nor does it specify when a decision should be rendered by the commission regarding
a utility's request for cost recovery. The commission found in Docket Number
22344 that costs associated with administration of the pilot project were
not appropriate for inclusion in transmission and distribution rates in the
UCOS cases pending before the commission because such costs are not ongoing
and will not be incurred in the test year. The commission finds that §25.431(k)(2)(C)
should be deleted from the rule as proposed because it is no longer an option
for cost recovery.
All comments, including any not specifically referenced herein, were fully
considered by the commission. In adopting this section, the commission makes
other minor modifications for the purpose of clarifying its intent.
This new section is adopted under the Public Utility Regulatory
Act, Texas Utilities Code Annotated §14.002 (Vernon 1998, Supplement
2000) (PURA), which provides the Public Utility Commission with the authority
to make and enforce rules reasonably required in the exercise of its powers
and jurisdiction, and specifically PURA §39.104, which states that the
commission shall require utilities to conduct pilot projects beginning June
1, 2001, and PURA §39.405, which sets forth additional requirements for
pilot projects conducted by utilities that are subject to the provisions of
PURA Chapter 39, Subchapter I.
Cross Reference to Statutes: Public Utility Regulatory Act §§14.002,
39.104, and 39.405.
§25.431.Retail Competition Pilot Projects.
(a)
Purpose. This section establishes the parameters under
which an electric utility shall offer customer choice for 5.0% of the load
in its Texas service area beginning on June 1, 2001, through the implementation
of retail competition pilot projects. The commission may use these pilot projects
to evaluate the ability of each power region to implement full customer choice
on January 1, 2002, including the operational readiness of support systems.
The pilot projects conducted under this section also will serve to encourage
participation in a competitive retail market and to inform customers about
customer choice.
(b)
Application.
(1)
This section applies to an electric utility as defined
in the Public Utility Regulatory Act (PURA) §31.002(6). An electric utility
exempt from PURA Chapter 39 in accordance with PURA §39.102(c) may conduct
a customer choice pilot project consistent with the requirements of this section
upon expiration of its exemption. A pilot project commencing before the adoption
of this section may fulfill portions of the requirements of this section,
as determined by the commission.
(2)
Other entities, including retail electric providers (REPs)
certified by the commission, and aggregators, power generation companies,
and power marketers registered with the commission may participate in the
pilot projects under the terms and conditions established by this section.
(c)
Intent of pilot projects. Pilot projects conducted under
this section are intended to implement customer choice for all applicable
customers in the same manner in which full customer choice will be offered
starting January 1, 2002, to the extent practicable. Unless determined otherwise
through a subsequent commission proceeding, or unless stated otherwise in
this section, all pilot project participants who are not retail customers
shall abide by all applicable commission rules, including but not limited
to, rules relating to customer protection and transmission and distribution
terms and conditions, and all rules of an independent organization as defined
in PURA §39.151.
(1)
Utility's obligation to serve. A utility shall continue
to provide electric service in accordance with PURA and the commission's substantive
rules to requesting customers in its certificated service area who do not
wish to take service from a REP.
(2)
Indemnification. Market participants, including utilities,
shall be held harmless for any damages resulting from any non-willful system
or process failures during the pilot project.
(3)
Performance standards.
(A)
Call center performance may be compromised by potential
large increases of customer inquiries generated because of the customer education
program and pilot project activities. For the period February 1, 2001 through
December 31, 2001, as applicable to each utility,
(i)
a reduction of five percentage points will be applied to
the percentage of calls to be answered in the allowable time; or
(ii)
5.0% of the calls with the longest wait time will be subtracted
from the calculation of average answer time.
(B)
An affected utility shall track and report such performance
during the pilot project in accordance with applicable commission rules and
orders. An affected utility does not waive any rights to request an adjustment
or waiver of performance standards directly affected by the customer education
program or pilot project.
(4)
Effect of pre-existing service agreements or contracts.
(A)
To the extent a customer is otherwise eligible to participate
in a pilot project in accordance with this section, a utility shall not challenge
a customer's right to participate:
(i)
based upon a claimed failure to provide notice of cancellation
in accordance with the requirements of an existing service agreement, contract,
or tariff; or
(ii)
in the event that the customer's service agreement or
contract is beyond its primary term.
(B)
To the extent a customer is otherwise eligible to participate
in a pilot project in accordance with this section, customers in the primary
term of a service agreement or contract shall have the right to participate
in the pilot project subject to a challenge by the utility based upon a service
agreement or contractual issue other than failure to provide notice of cancellation
in compliance with an existing service agreement, contract, or tariff. The
procedure for any such challenge shall be as follows:
(i)
A utility contending that a customer that has been otherwise
selected to participate in the pilot project is not eligible to participate,
because of an existing service agreement or contract in its primary term,
shall inform the customer not later than seven days after the date scheduled
for the lottery for the applicable class in the event the class is oversubscribed
or the date the customer requests participation in the event the class is
undersubscribed.
(ii)
If the customer wishes to dispute the utility's contention,
the customer must, within seven days of receipt of the utility's notification,
so inform the utility. Pending resolution of the dispute, the utility shall
reserve a place for that customer on the participant list.
(iii)
The customer shall be entitled to participate in the
pilot project unless the utility informs the commission of the pilot project
eligibility dispute within seven days of receipt of the customer's notification
to the utility disputing the claim of ineligibility. Upon receipt by the commission
of timely notice of the dispute, the commission will resolve the dispute within
30 days after filing, and may do so administratively.
(iv)
If the commission determines that the customer is eligible
to participate, the customer will be included within the pilot project as
soon as practicable after the decision.
(5)
Right to withdraw from pilot project. For any reason, and
at a customer's request, the REP and the incumbent utility shall restore a
residential customer's account to pre-pilot project services and rates. In
the event a customer's REP ceases to do business in Texas during the pilot
project, the incumbent utility shall restore any customer's account to pre-pilot
project services and rates at the customer's request.
(6)
Application of renewable energy rule. To encourage access
to energy generated from renewable resources by customers participating in
the pilot projects, the renewable energy mandate provisions of §25.173
of this title (relating to Goal for Renewable Energy) will be extended on
a voluntary basis during the pilot projects to the competitive portion of
the market, with the following changes:
(A)
Each REP may acquire and retire renewable energy credits
(RECs) consistent with its share of retail kilowatt-hour sales during the
pilot period (June 1, 2001 through December 31, 2001), at a rate consistent
with REC obligations for the year 2002, and in the manner specified in §25.173(h)
of this title;
(B)
Each REC retired for the pilot period will reduce the REC
obligations of the REP for the year 2002 compliance period;
(C)
The voluntary settlement period for the pilot project renewable
energy program will commence January 1, 2002 and end March 31, 2002; and
(D)
Penalty provisions of §25.173(o) of this title are
not applicable.
(7)
End of pilot projects. The pilot projects will end on December
31, 2001, unless determined otherwise by the commission in accordance with
subsection (j) of this section. For an electric utility exempt from PURA Chapter
39 in accordance with PURA §39.102(c), the pilot project, if undertaken,
will begin and end on dates deemed reasonable by the commission. A customer
will remain with the REP by which he or she was served on the last day of
the pilot project until the customer or the REP elects otherwise. By participating
in the pilot project, a customer does not waive any right to take service
under the price to beat in accordance with PURA §39.202.
(d)
Definitions. The following terms when used in this section
shall have the following meanings unless the context clearly indicates otherwise:
(1)
Aggregation - includes the purchase of electricity from
a retail electric provider, a municipally owned utility, or an electric cooperative
by an electricity customer for its own use in multiple locations or as part
of a voluntary association of electricity customers. An electricity customer
may not avoid any nonbypassable charges or fees as a result of aggregating
its load.
(2)
Customer class - a grouping of customers, specific to the
pilot projects, for the purpose of allocating loads available for customer
choice during the pilot projects. The five customer classes used in the pilot
projects are:
(A)
Residential - all customers identified by an electric service
identifier (ESI) who purchase electricity under a utility's residential rate
schedule.
(B)
Non-residential, non-demand metered - all customers identified
by an ESI who:
(i)
do not purchase electricity under a utility's residential
rate schedule; and
(ii)
do not purchase electricity under a utility's municipal
or school rate schedule; and
(iii)
do not purchase electricity under a utility's rate schedule
that is based on metered or estimated demand during the twelve month period
ending December 31, 2000.
(C)
Industrial demand-metered - all customers identified by
an ESI who:
(i)
do not purchase electricity under a utility's residential
rate schedule; and
(ii)
purchase electricity under a utility's rate schedule that
is based on a metered demand; and
(iii)
purchase electricity under a utility's industrial rate
schedules (or are identified as industrial by the utility's rate code if the
utility does not have industrial rate schedules) or have filed a manufacturing
or processing tax exemption certificate with the utility.
(D)
Commercial and all other demand-metered - all customers
identified by an ESI who:
(i)
do not purchase electricity under a utility's residential
rate schedule; and
(ii)
do not come within the definition of the industrial demand
metered customer class; and
(iii)
purchase electricity under a utility's rate schedule
that is based on a metered demand.
(E)
Other - The other customer class is composed of all customers
identified by an ESI who:
(i)
purchase electricity under a utility's rate schedule that
is based on known usage patterns, not actual metered data (i.e., unmetered
loads); or
(ii)
purchase electricity under a utility's municipal or school
rate schedules; or
(iii)
purchase electricity under utility rate schedules applicable
to seasonal agricultural use, such as cotton gins, irrigation, or grain elevators.
(3)
Electric service identifier (ESI) - premise-based identifier
assigned to each electric service delivery point between a transmission and
distribution utility and an end- use load, which is used in the Texas customer
registration system and the Electric Reliability Council of Texas (ERCOT)
settlement system.
(4)
Lottery - fair process in which ESIs or aggregator packets
of ESIs are selected for participation in a pilot project by using standard
statistical methods for simple random sampling; each ESI or aggregator packet
of ESIs should have an equal chance of actually being selected.
(5)
Participation - occurs when the customer takes service
from a retail electric provider that is not the incumbent, integrated utility.
(e)
Requirements for participants that are not retail customers.
(1)
A REP must be certified by the commission pursuant to §25.107
of this title (relating to Certification of Retail Electric Providers) prior
to participating in pilot projects established pursuant to this section. An
affiliated REP shall not participate in the certificated service area of the
electric utility with which it is affiliated.
(2)
An aggregator, other than a self-aggregator, must be registered
with the commission pursuant to §25.111 of this title (relating to Registration
of Aggregators) prior to participating in pilot projects established pursuant
to this section.
(3)
A power generation company must be registered with the
commission pursuant to §25.109 of this title (relating to Registration
of Power Generation Companies) prior to participating in pilot projects established
pursuant to this section. A utility need not be registered as a power generation
company in order to generate power for sale during the pilot projects.
(4)
A power marketer must be registered with the commission
pursuant to §25.105 of this title (relating to Registration and Reporting
by Power Marketers) prior to participating in pilot projects established pursuant
to this section.
(5)
An independent transmission organization outside of ERCOT
may require a market participant to register with that organization in order
to become a wholesale buyer and seller of energy across the transmission system.
(f)
Customer education. Customer education for the pilot projects
shall be conducted as part of the statewide customer education campaign for
introducing customer choice. Included in this campaign will be announcements
regarding the opportunity to participate in the pilot project and instructions
on obtaining further information about the pilot project. The commission shall
mail information written in English and in Spanish explaining the pilot project
to eligible non-residential customers no later than March 1, 2001, and to
eligible residential customers no later than April 15, 2001. The utility shall
provide the commission or its designee with customer information necessary
to implement this subsection. For purposes of this subsection, §25.272(g)(1)
of this title (relating to Code of Conduct for Electric Utilities and Their
Affiliates) does not apply with regard to proprietary customer information
released to the commission or its designee. The mailing may contain information
including, but not limited to:
(1)
a description of the pilot project;
(2)
the commission's central call center phone number and Internet
website operating to respond to customer questions and requests for information;
(3)
a list of REPs certified as of a date certain, including
the telephone number and, if available, Internet website address for each
REP, and a statement disclosing that the REP list is continually updated and
how the customer can obtain an updated list; and
(4)
a clear, plain language description of customer choice
and the price to beat.
(g)
Customer choice during pilot projects. The following procedures
shall be used for customers to participate in the pilot projects within the
designated time periods for each applicable customer class.
(1)
Administration. For all customer classes, a REP shall submit
requests to switch customers participating in the pilot projects to the registration
agent beginning on May 31, 2001, and power delivery in conjunction with the
pilot projects may begin on June 1, 2001. For purposes of this section, any
electronic submission to the utility shall be executed using a standard electronic
data interface (EDI) protocol (814) to be included in the utility's compliance
filing.
(A)
Except where explicitly stated otherwise in this section,
a REP shall electronically submit switch requests to the utility for counting
and validation purposes prior to submitting such requests to the registration
agent. The utility shall maintain a weekly updated list of non-matching, rejected
ESIs on its pilot project Internet website.
(B)
Except for the industrial demand-metered class, there shall
be no out-of-cycle meter reading requests submitted for purposes of the pilot
project before July 1, 2001.
(C)
Members of the non-residential customer classes may elect
to waive the verification and recision process of the registration agent.
(D)
A participating customer shall have the right to change
from one REP to another REP in accordance with the switching procedures adopted
by the commission.
(E)
Beginning April 16, 2001, a REP shall electronically report
to the utility any switch request for a customer or an aggregation packet
with a listing of the ESIs to be switched to the REP as set forth in this
paragraph. After the utility confirms that a non-residential ESI or aggregation
packet is on the associated participant list, the utility shall submit the
ESI to the registration agent. The registration agent shall keep a record
of all the ESIs identified by the utility for participation in the pilot.
The REP shall be responsible for submitting to the registration agent the
ESIs associated with the switch request to serve. If the ESI identified by
the REP matches an ESI identified by the utility, then the registration agent
shall allow the registration process to continue.
(F)
Because the utility is assigned the responsibility to administer
the pilot project, except for complaints arising under §25.272 of this
title, which may be made in accordance with procedures established under that
section, a claim by any party of unreasonableness associated with the administration
of the pilot project will first be addressed by the pilot implementation working
group established by subsection (j)(4) of this section. If the complaint is
not resolved within ten working days of initial notification to the pilot
implementation working group, the complaint may be filed with the commission.
(2)
Residential customer class.
(A)
Determination of the 5.0% load available for customer choice.
For residential customers, the load available for customer choice shall be
determined by calculating 5.0% of the number of ESIs in this customer class
as of December 31, 2000. No later than January 31, 2001, the utility shall
determine the amount of load available for this customer class and shall make
that information publicly available through its pilot project Internet website.
For this customer class, 20% of the 5.0% load available for customer choice
shall be initially set aside for each customer class (hereafter referred to
as the 1.0% set-aside) for aggregated loads.
(B)
Initiating switching. Beginning February 15, 2001, a REP
may accept authorizations to switch providers from residential customers.
A REP shall notify the utility of such authorizations for residential customers.
(C)
Reaching the 5.0% load limit. For purposes of this subparagraph
the total number of ESIs eligible to switch determined in subparagraph (A)
of this paragraph, less the number of ESIs that have already authorized a
switch, shall be referred to as the amount of available load.
(i)
As each customer in this class authorizes a switch to another
provider, the amount of available load shall be decremented by one.
(ii)
When the amount of available load reaches zero, no more
switch authorizations shall be accepted.
(3)
Non-residential customer classes.
(A)
Determination of the 5.0% load available for customer choice.
No later than January 31, 2001, the utility shall make the results of the
following calculations for each non-residential customer class publicly available
through its pilot project Internet website. For each non-residential customer
class, 20% of the 5.0% load available for customer choice shall be initially
set aside for each customer class (hereafter referred to as the 1.0% set-aside)
for aggregated loads.
(i)
Non-residential, non-demand metered customers. For non-
residential, non-demand metered customers, the load available for customer
choice shall be determined by calculating 5.0% of the number of ESIs in that
customer class as of December 31, 2000.
(ii)
Industrial demand-metered customers; commercial and all
other demand-metered customers. For each of the demand metered customer classes,
the load available for customer choice shall be determined by calculating
5.0% of the sum of the kilowatts invoiced by the utility to all ESIs in each
customer class for meter reading dates during the utility's peak demand month
in the year 2000. In addition, the utility shall determine the individual
ESI load caps for each demand metered customer class by calculating 20% of
the load available for the pilot project in each demand- metered customer
class.
(iii)
Other customers as defined in subsection (d)(2)(E) of
this section. For all other customers, the load available for customer choice
shall be determined by calculating 5.0% of the sum of the kilowatt- hours
for which all ESIs in this customer class were invoiced by the utility during
the twelve month period ending December 31, 2000. In addition, the utility
shall determine the individual ESI load caps for this customer class by calculating
20% of the kilowatt-hours available for the pilot project in this customer
class.
(B)
Amount of available load. For purposes of this paragraph,
the total load available for customer choice determined in subparagraph (A)
of this paragraph, less the amount of the customer's ESI load used for calculation
in subparagraph (A) of this paragraph, shall be referred to as the amount
of available load for each non-residential customer class. For an ESI that
was not included in the calculation in subparagraph (A) of this paragraph,
hereinafter called a new ESI, the customer's ESI load shall be determined
as follows:
(i)
For the non-residential, non-demand metered class, a new
ESI shall count as one ESI against the total number of ESIs.
(ii)
For the demand-metered classes, the demand allocated to
a new ESI shall be 95% of the utility-estimated demand for the new ESI.
(iii)
For the other class as defined in subsection (d)(2)(E)
of this section, the energy allocated to a new ESI shall be 95% of the utility-
estimated annual kilowatt-hours for the new ESI.
(C)
Open interest period. Beginning February 15, 2001, and
continuing through March 15, 2001, interested customers may request the opportunity
to participate in a utility's pilot project by submitting to the utility through
its pilot project Internet website the account number and zip code information
necessary to determine the customer's ESI. An eligible ESI is one that does
not exceed the individual ESI load cap established in subparagraph (A) of
this paragraph. By March 21, 2001, the utility shall determine if the non-residential
customer classes are either oversubscribed or undersubscribed, including the
amount of load oversubscribed or undersubscribed, and shall make such information
publicly available through its pilot project Internet website.
(i)
Participant list. The utility shall create a list of customers
eligible to participate in the pilot project, referred to as the participant
list. The participant list shall include each ESI and related service address,
the name in which the customer is billed, and customer class as defined in
this section. No later than March 21, 2001, the utility shall make available
its integrated voice response (IVR) system or its pilot project Internet website
to allow a customer having an ESI in the lottery to determine whether its
ESI has been selected for the participant list. The participant list for each
customer class shall be provided to the commission no later than March 21,
2001.
(ii)
Oversubscription. On March 21, 2001, if a non-residential
customer class is oversubscribed, the utility shall use a lottery to develop
the participant list. As each ESI is selected through the lottery, the ESI's
load used for the calculation in subparagraph (A) of this paragraph shall
be subtracted from the total amount of load available for customer choice
as determined in subparagraph (A) of this paragraph. The ESI that causes the
4.0% load limit (i.e., the 5.0% load limit less the 1.0% set-aside) to be
reached shall be the final ESI selected through the lottery; the 4.0% limit
may be exceeded only for the purpose of accommodating the entire load associated
with the final ESI selected, except that such excess shall not cause the amount
of load available for customer choice to be greater than 4.1%. Once the 4.0%
load limit is reached, the selected ESIs shall be included on the participant
list.
(iii)
Undersubscription. If a non-residential customer class
is undersubscribed, all eligible ESIs submitted shall be included on the participant
list. Beginning March 21, 2001, any unsubscribed load will be available for
subscription by customers in that customer class on a first come, first served
basis.
(D)
Negotiation period. Between March 21, 2001 and May 10,
2001, customers on the participant list may negotiate and contract with REPs.
A REP shall notify the utility of execution of a contract. If a customer has
not entered into a confirmed REP contract for a specific ESI by May 10, 2001,
that ESI shall be removed from the participant list, and the load associated
with that ESI shall be added to the amount of available load. On May 11, 2001,
the utility shall post, on its pilot project Internet website, a list of submitted
ESIs that do not match a customer on the participant list. REPs shall have
until May 14, 2001 to correct any ESI listed by the utility on May 11, 2001.
On May 17, 2001, the utility shall determine the amount of available load
for each non-residential customer class and shall make such determination
publicly available through its pilot project Internet website.
(E)
Monitoring and adjusting the amount of available load.
Following the negotiation period, participation shall be allowed on a first
come, first served basis.
(i)
As each non-residential customer in a class executes a
contract, the amount of available load for that class shall be decremented
by the amount of the customer's ESI load used for the calculation in subparagraph
(A) of this paragraph.
(ii)
The ESI that causes the amount of available load to reach
zero shall be the final ESI selected; the amount of available load may drop
below zero only for the purpose of accommodating the entire load associated
with the final ESI selected, subject to the limitations described in subparagraph
(C)(ii) of this paragraph.
(4)
Aggregated load set-aside. Customers participating in customer
choice may use aggregation to the extent they choose, and may participate
by self aggregation or multiple customer aggregation. For purposes of pilot
project administration, aggregators must submit to the utility their groupings
of utility account numbers and associated zip codes, or ESIs if available,
for participation in the pilot project subject to the 1.0% set-aside. Such
groupings (hereafter referred to as aggregation packets) shall be submitted
by customer class as defined in subsection (d) of this section with a listing
of utility account numbers and associated zip codes.
(A)
Set-aside cap. No single aggregation packet may contain
an ESI or ESIs that represent more than 20% of the 1.0% set-aside for that
customer class, with the exception of the residential class.
(B)
Registration dates. Aggregators may register non-residential
customer class aggregation packets, subject to the limitation in subparagraph
(A) of this paragraph, with the utility beginning February 15, 2001. Aggregators
may register residential aggregation packets beginning March 1, 2001.
(C)
Undersubscription for all non-residential customer classes.
If an aggregation packet contains non-residential ESIs from a class that is
undersubscribed as of April 2, 2001, then that aggregation packet shall have
a reserved allotment of the 1.0% set-aside until May 21, 2001. If by May 31,
2001, the 1.0% set-aside for aggregation in any non-residential class is undersubscribed,
then the utility shall determine the unused class capacity and add it to the
amount of available load for that class. No later than June 10, 2001, the
utility shall make the updated amount of available load publicly available
through the utility's pilot project Internet website.
(D)
Aggregation selection process for customer classes. The
eligibility for the 1.0% set-aside for each customer class shall be determined
as follows:
(i)
Residential customer class. Beginning on March 1, 2001,
an aggregator may accept authorizations from residential customers to switch
providers as a part of an aggregation packet. Aggregators shall submit aggregated
utility account numbers and associated service address zip codes to the utility
for tracking the 1.0% set- aside on a first come, first served basis. Aggregation
packets shall be accepted until either the 1.0% set-aside is reached or June
15, 2001, whichever comes first. If the 1.0% set-aside is not fully subscribed
by June 15, 2001, the utility shall determine the unused class capacity and
add that unused capacity to the total amount of available load for the residential
class.
(ii)
Non-residential customer classes. The initial set-aside
for each of the non-residential customer classes shall be 1.0% of the eligible
load by customer class. To be eligible for the aggregation participant list,
an aggregator must provide utility account number and service address zip
code information, or ESIs if available, to the utility by April 2, 2001.
(I)
Oversubscription for the non-residential, non-demand metered
customer class. If the total number of ESIs in aggregation packets submitted
for the pilot for a non- residential, non-demand class as of April 2, 2001
exceeds the 1.0% set-aside, then the utility shall use a lottery to determine
the aggregation participant list for this class. Aggregation packets eligible
for the aggregation participant list shall be selected by the utility by April
5, 2001. As each aggregation packet is selected through the lottery, the ESI
count shall be subtracted from the total number of ESI available for the 1.0%
set-aside. Aggregation packets shall be selected until none of the 1.0% set-aside
is left. If the last aggregation packet selected causes the 1.0% set-aside
to be exceeded, the selection of the final aggregation packet for this class
shall be done in accordance with subparagraph (E)of this paragraph. By April
6, 2001, the utility shall determine whether an aggregation packet has been
selected, and shall make such information publicly available through its pilot
project Internet website.
(II)
Oversubscription for the industrial demand-metered and
commercial and all other demand-metered classes. If the total combined load
of all aggregation packets submitted for each of the industrial demand-metered
and commercial and all other demand-metered classes exceeds the 1.0% set-aside
as of April 2, 2001, then the utility shall use a lottery to determine the
aggregation participant list for each customer class. Aggregation packets
eligible for the aggregation participant list shall be selected by the utility
by April 5, 2001. As an aggregation packet is selected through the lottery,
the demand for that ESI used to determine the available capacity for that
customer class shall be subtracted from the total demand amount available
for the 1.0% set-aside. Aggregation packets shall be selected until none of
the 1.0% set-aside is left. If the last aggregation packet selected causes
the 1.0% set-aside to be exceeded, the selection of the final aggregation
packet for the class shall be done in accordance with subparagraph (E) of
this paragraph. No later than April 6, 2001, the utility shall make the list
of ESIs eligible for the pilot project publicly available through its pilot
project Internet website.
(III)
Oversubscription for the other customer class as defined
in subsection (d)(2)(e) of this section. If the total combined load of all
aggregation packets submitted for the other class exceeds the 1.0% set-aside
as of April 2, 2001, then the utility shall use a lottery to determine the
aggregation participant list for this class. Aggregation packets eligible
for the aggregation participant list shall be selected by the utility by April
5, 2001. As each aggregation packet is selected through the lottery, the energy
in kilowatt-hours for that ESI used to determine the size of the customer
class shall be subtracted from the total amount of energy available for the
1.0% set-aside. Aggregation packets shall be selected until none of the 1.0%
set-aside is left. If the last aggregation packet selected causes the 1.0%
set-aside to be exceeded, the selection of the final aggregation packet for
the class shall be done in accordance with subparagraph (E) of this paragraph.
No later than April 6, 2001, the utility shall make the list of ESIs eligible
for the pilot project for the class publicly available through its pilot project
Internet website.
(E)
Non-residential customer classes oversubscription lottery
selection of last aggregation packet. If the final aggregation packet chosen
in a customer class lottery causes the 1.0% set-aside for that customer class
to be exceeded by more than 10%, that is, if that aggregation packet increases
the size of the customer class to greater than 1.1%, that aggregation packet
shall be rejected and another aggregation packet shall be chosen if available.
If no other aggregation packet is available to fill each non- residential
customer class without exceeding the 10% overage limit, that remaining increment
of capacity set-aside will not be subscribed, but will be added to the amount
of available capacity for aggregation for that non- residential customer class
and will be available on a first come, first served basis. An aggregation
packet that does not exceed the 10% overage limit will be allowed. When the
results of the oversubscription lottery are posted by the utility, the utility
shall also make publicly available the information concerning this available
capacity through its pilot project Internet website.
(F)
Contract notification due date for non-residential customer
classes. By May 21, 2001, a REP must submit verification of executed supply
contracts with ESIs and associated zip code to the utility. Any ESI that has
not been validated by a REP by this date will relinquish its reserved allotment
on the aggregation participant list. The relinquished allotment will then
be available for aggregation in that customer class on a first come, first
served basis.
(G)
Notification of executed contract for non-residential customer
classes. The REP shall document the existence of an executed contract for
service by electronically submitting a list of ESIs representing executed
contracts to the utility. The utility may rely on receipt of this list as
proof of the existence of an executed contract. The REP shall file a signed
affidavit with the commission attesting to the accuracy of the ESIs on the
list.
(H)
Electronic submissions by aggregators. All submittals required
by this section by aggregators to a utility shall be made in electronic format
using a Microsoft Excel spreadsheet using a spreadsheet template posted on
the utility's pilot project Internet website. A utility will post its templates
by January 31, 2001.
(I)
New ESIs. For an ESI that was not included in the calculation
in paragraph (3)(A) of this subsection, hereinafter called a new ESI, the
customer's ESI load shall be determined as follows:
(i)
For the non-residential non-demand metered classes, a new
ESI shall count as one ESI against the total number of ESIs.
(ii)
For the demand-metered classes, the demand allocated to
a new ESI shall be 95% of the utility-estimated demand for the new ESI.
(iii)
For the other class as defined in subsection (d)(2)(E)
of this section, the energy allocated to a new ESI shall be 95% of the utility-
estimated annual kilowatt-hours for the new ESI.
(h)
Transmission and distribution rates and tariffs.
(1)
Utilities within ERCOT. In connection with a utility's
pilot project, the utility shall provide transmission service and distribution
service in accordance with the rates for non-bypassable delivery charges approved
by the commission, on an interim basis for application during the utility's
pilot project, in the utility's unbundled cost of service case filed pursuant
to PURA §39.201. Notwithstanding the provisions of §22.125 of this
title (relating to Interim Relief), such interim rates shall not be subject
to surcharge or refund if the rates ultimately established differ from the
interim rates.
(2)
Utilities outside of ERCOT.
(A)
Jurisdiction of other regulatory bodies. Processes utilized
by non-ERCOT participants shall support the settlement of traditional wholesale
markets and shall conform to all Federal Energy Regulatory Commission (FERC)
rules and regulations.
(B)
Transmission service. In connection with a utility's pilot
project, the utility shall provide transmission service in accordance with
the rates and delivery charges approved by the FERC. A utility in transition
to an independent transmission company (ITC) model shall maintain on file
with the commission a copy of its current FERC-approved open access transmission
tariff (OATT), as well as any proposed amendments to the OATT submitted to
FERC.
(C)
Distribution service. In connection with a utility's pilot
project, the utility shall provide distribution service in accordance with
the rates for non- bypassable delivery charges approved by the commission,
on an interim basis for application during the utility's pilot project, in
the utility's unbundled cost of service case filed pursuant to PURA §39.201.
Notwithstanding the provisions of §22.125 of this title, such interim
rates shall not be subject to surcharge or refund if the rates ultimately
established differ from the interim rates.
(3)
Approval of tariffs. Tariffs implementing pilot project
rates must be filed within ten days following the commission's determination
of those rates. The commission shall approve such tariffs by May 31, 2001,
and may do so administratively.
(i)
Billing requirements.
(1)
A utility shall bill a customer's REP for non-bypassable
delivery charges in accordance with the tariffs established pursuant to subsection
(h) of this section. The REP must pay these charges.
(2)
A REP shall be responsible for ensuring that its retail
customers are billed for electric service provided. A utility may bill retail
customers at the request of a REP, provided that any such billing service
shall be offered by the utility on comparable terms and conditions for any
requesting REP.
(j)
Evaluation of the pilot projects by the commission; reporting.
The commission shall evaluate the pilot projects and the operational readiness
of each power region, including its support systems, for customer choice.
(1)
Evaluation criteria.
(A)
Criteria for determining the readiness of a power region
for customer choice may include the following:
(i)
whether a power region's operational support systems were
tested, and any problems that surfaced during the pilot project were adequately
rectified;
(ii)
whether electric system reliability was significantly
affected in an adverse way; and
(iii)
any other criteria the commission determines appropriate.
(B)
Criteria for determining whether commission rules may need
modifications or whether certain aspects of retail competition may require
more detailed monitoring by the commission may include the following:
(i)
whether participants in the pilot projects represented
a broad base of customers of diverse demographic characteristics;
(ii)
whether customers were aware of their rights and responsibilities
with respect to customer choice, and whether such awareness increased for
customers as a whole over the duration of the pilot projects;
(iii)
whether a broad range of electric services and products
were offered;
(iv)
whether the quality of customer service with respect to
retail customers was affected; and
(v)
any other criteria the commission determines appropriate.
(2)
Information used for evaluation of pilot projects. Evaluation
of the pilot projects shall be based on information including, but not limited
to:
(A)
reports filed in accordance with paragraph (3) of this
subsection;
(B)
surveys of retail customers conducted in connection with
the commission's customer education program; and
(C)
the quantity and nature of complaints or inquiries regarding
the pilot project received by the commission's Office of Customer Protection.
(3)
Reporting by market participants and independent organizations.
Each market participant and independent organization shall file two status
reports with the commission under a single project number as designated by
the commission's central records division. The first status report shall be
filed on November 15, 2001, and the second no later than 30 days following
the conclusion of the pilot project. In addition, a utility subject to PURA
Chapter 39, Subchapter I, shall file semi-annual reports with the commission
for the duration of its pilot project to permit the commission to monitor
whether proportional representation is achieved in accordance with subsection
(l)(3)(B) of this section.
(A)
Reporting by utilities. Each status report from a utility
shall include:
(i)
The percent of load switched by month and cumulatively,
for each customer class as defined in this section, including supporting data;
(ii)
The number of customers that have withdrawn from the pilot
project, by customer class;
(iii)
A summary of any technical problems encountered during
the reporting period, including resolutions or proposed resolutions, as appropriate,
and supporting data;
(iv)
A summary of all complaints related to the pilot project
received by the utility during the reporting period, including a description
of the resolution of the complaints;
(v)
For a utility in transition to an ITC model, a progress
report on the transition to the ITC, including any updates to the initial
compliance filing; and
(vi)
Any other information the utility believes will assist
the commission in evaluating the pilot projects and the readiness of a power
region for implementation of full customer choice.
(B)
Reporting by REPs. Each status report from a REP shall
include:
(i)
A summary of any technical problems encountered during
the reporting period, including resolutions or proposed resolutions, as appropriate,
and supporting data;
(ii)
A summary of all complaints related to the pilot project
received by the REP during the reporting period, including a description of
the resolution of the complaints; and
(iii)
Any other information the REP believes will assist the
commission in evaluating the pilot projects and the readiness of a power region
for implementation of full customer choice.
(C)
Reporting by an independent organization. Each status report
from an independent organization shall include:
(i)
Data from the registration agent regarding the average
time elapsed between a switch request and the time the switch became effective;
(ii)
Data from the registration agent, categorized by residential
and non- residential customers, listing the total number of switch requests
for each month, as well as the average number of switch requests per day for
each month, and the total number of switch requests by zip code;
(iii)
Data from the registration agent regarding the number
of rejected switch requests resulting from the anti-slamming verification
process;
(iv)
A summary of all complaints, categorized by REP and by
utility, related to the pilot project captured in the registration agent's
systems during the reporting period, including a description of the resolution
of the complaints;
(v)
A summary from the registration agent and the independent
organization, as applicable, of any technical problems encountered during
the reporting period, including resolutions or proposed resolutions, as appropriate,
and supporting data; and
(vi)
An analysis by the independent transmission organization
of system reliability during the pilot projects.
(D)
Other reporting.
(i)
To the extent low-income rate discounts are offered in
accordance with PURA and commission rules, the number of customers receiving
a low-income rate discount shall be reported to the commission by the administrator
of the system benefit fund.
(ii)
At any time, a pilot project participant who is neither
a utility nor a REP may provide the commission with any information the participant
believes will assist the commission in evaluating the pilot projects and the
readiness of a power region for implementation of full customer choice.
(4)
Pilot implementation working group. The commission will
establish a pilot implementation working group to oversee the pilot projects.
The commission or its designee, based upon a recommendation of the pilot implementation
working group, may revise the operational requirements of the pilot projects
in order to resolve technical problems encountered by market participants.
(5)
Extension of pilot projects. Should the commission determine
that it is necessary to delay competition and extend the pilot projects, it
must make such determination by December 31, 2001, except as otherwise authorized
by PURA §39.405.
(k)
Pilot project administration and recovery of associated
costs.
(1)
Each utility shall be responsible for administering the
pilot project for its service area. Costs incurred by the utility to administer
the pilot project may include expenses for required communications, third-party
outsourcing for any or all administration tasks, enrollment process, or lottery
administration.
(2)
The utility may request recovery from the commission of
pilot project administrative costs through:
(A)
inclusion in the annual report filed pursuant to PURA §39.257;
or
(B)
deferral to future retail transmission or distribution
rates.
(3)
Parties do not waive the right to challenge the utility's
ability to seek cost recovery for costs associated with the pilot projects
at the time that such relief is sought. In addition, nothing in this section
shall be construed as resolving the legal issue of whether utilities may recover
costs associated with the pilot projects.
(l)
Compliance filings.
(1)
Timing and review. Each utility shall file a pilot project
implementation plan with the commission under a project number designated
by the commission's central records division. An implementation plan filed
under this section shall be reviewed administratively to determine whether
it is consistent with the principles, instructions and requirements set forth
in this section.
(A)
Each utility shall file its implementation plan within
45 days of the commission's adoption of this section. Such filings do not
constitute contested case proceedings, but are designed to describe the particular
application of this section to the filing utility for the purpose of providing
information to the public and the commission.
(B)
No later than 15 days after filing, interested parties
may file comments on the implementation plan.
(C)
No later than 25 days after filing, commission staff may
file a recommendation concerning the implementation plan.
(D)
Unless the commission or presiding officer determines otherwise,
an implementation plan filed under this section shall be deemed approved on
the thirtieth day after filing. If the implementation plan is not approved,
the utility shall resubmit its plan following consultation with commission
staff under a deadline established by the presiding officer.
(2)
Content. The compliance filing shall address each provision
of this section with a brief narrative explaining how the utility intends
to implement that provision, including the utility's pilot project Internet
website address and other contact information, as applicable. Numerical and
formulaic data shall also be provided where applicable. Specifically, the
compliance filing shall detail the calculation of the 5.0% load available
for each customer class, including the 1.0% set-aside, and demonstrate the
calculation with sample data. The final calculations containing actual data
shall be filed with the commission by January 31, 2001.
(3)
Additional requirements for non-ERCOT utilities.
(A)
A utility subject to PURA Chapter 39, Subchapter I, shall
include in its transition plan filed pursuant to PURA §39.402, a plan
for extending its pilot project beyond January 1, 2002. The plan for extension
of the pilot project shall contain:
(i)
The utility's proposed increase(s) in pilot project participation
beyond 5.0%, and proposed timing for such increase(s), including supporting
data and workpapers; and
(ii)
A report to the commission on market conditions in the
utility's power region, including an analysis of the level of competition
that the region can support and all relevant data and workpapers.
(B)
A utility subject to PURA Chapter 39, Subchapter I, shall
include in its compliance filing, a plan to ensure proportional representation
in its pilot project between customers receiving service from the utility
in an area that is certificated solely to the utility and those customers
of the utility located in multiply certificated areas.
(C)
A utility in transition to an ITC model shall include in
its compliance filing:
(i)
a narrative of how its plan for transition to an ITC is
expected to affect the pilot project, including relevant supporting data and
workpapers; and
(ii)
an explanation of any requirements of market participants
that are unique to its service area (e.g, registration with ITC, data aggregation
requirements).
This agency hereby certifies that the adoption
has been reviewed by legal counsel and found to be a valid exercise of the
agency's legal authority.
Filed with the Office of
the Secretary of State on August 14, 2000.
TRD-200005693
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: September 3, 2000
Proposal publication date: June 16, 2000
For further information, please call: (512) 936-7308
Chapter 303.
GENERAL PROVISIONS
Subchapter D. TEXAS BRED INCENTIVE PROGRAMS
2.
PROGRAMS FOR HORSES
16 TAC §303.92
The Texas Racing Commission adopts an amendment to §303.92
concerning the rules of the Texas Thoroughbred Association regarding the Texas
Bred Incentive Programs. The amendment is adopted without changes to the proposed
text published in the June 23, 2000, issue of the
Texas Register
(25 TexReg 6020) and the text will not be republished.
The amendment was presented to the Commission as a rulemaking petition under
16 Tex. Admin. Code §307.33 by the Texas Thoroughbred Association, the
official breed registry for Thoroughbred horses in Texas.
The amendment is adopted to ensure the funds dedicated to the Texas Bred
Incentive Programs may be used in a variety of ways to enhance the Texas breeding
programs. According to the petition, the amendment permits the breed registry
to use award money generated from multiple two and multiple three wagers under §6.08(f)
of the Texas Racing Act to supplement purses for special events or days that
are restricted to accredited Texas-bred thoroughbreds. The amendment also
corrects a misspelled word.
No comments were received regarding the proposal.
The amendment is adopted under the Texas Civil Statutes, Article
179e, §3.02, which authorizes the Commission to adopt rules for conducting
racing with wagering and for administering the Texas Racing Act; §6.08(g),
which authorizes the Commission to adopt rules relating to the accounting,
audit, and distribution of all amounts set aside for the Texas-bred program;
and §9.01, which authorizes the state breed registries to adopt reasonable
rules to establish the qualifications of accredited Texas-bred horses to promote,
develop, and improve the breeding of horses in Texas, subject to the approval
of the Commission.
The adopted amendment implements Texas Civil Statutes, Article 179e.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on August 11, 2000.
TRD-200005593
Judith L Kennison
General Counsel
Texas Racing Commission
Effective date: September 1, 2000
Proposal publication date: June 23, 2000
For further information, please call: (512) 833-6699
Subchapter A. LICENSING PROVISIONS
1.
OCCUPATIONAL LICENSE
16 TAC §311.3
The Texas Racing Commission adopts an amendment to §311.3
concerning the fingerprint requirements and procedure for background investigations
of applicants. The amendment is adopted without changes to the proposed text
published in the May 26, 2000 issue of the
Texas
Register
(25 TexReg 4685) and the text will not be republished.
The amendment is adopted to ensure the occupational licensing process will
be more streamlined and efficient. The amendment eliminates the requirement
that a license applicant submit a set of fingerprints on a separate card for
the Federal Bureau of Investigation. Under a new system in place at the Department
of Public Safety, fingerprints submitted by the Commission to the Department
are sent electronically to the FBI. Therefore, a separate set of fingerprints
for the FBI is no longer required.
No comments were received regarding the proposal.
The amendment is adopted under the Texas Civil Statutes, Article
179e, §3.02, which authorizes the Commission to adopt rules for conducting
racing with wagering and for administering the Texas Racing Act; and §7.02,
which authorizes the Commission to establish categories of occupational licenses
and the qualifications and experience required for licensing in each category.
The adopted amendment implements Texas Civil Statutes, Article 179e.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on August 11, 2000.
TRD-200005594
Judith L. Kennison
General Counsel
Texas Racing Commission
Effective date: September 1, 2000
Proposal publication date: May 26, 2000
For further information, please call: (512) 833-6699
16 TAC §311.101
The Texas Racing Commission adopts an amendment to §311.101
concerning the licensing of horse owners. The amendment is adopted without
changes to the proposed text published in the May 26, 2000, issue of the
The amendment is adopted to simplify the licensing process for horse owners.
The amendment eliminates the "entry time" deadline for licensing of horse
owners. A horse owner must still be licensed before a horse may start in a
race in Texas.
No comments were received regarding the proposal.
The amendment is adopted under the Texas Civil Statutes, Article
179e, §3.02, which authorizes the Commission to adopt rules for conducting
racing with wagering and for administering the Texas Racing Act; and §7.02,
which authorizes the Commission to establish categories of occupational licenses
and the qualifications and experience required for licensing in each category.
The adopted amendment implements Texas Civil Statutes, Article 179e.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on August 11, 2000.
TRD-200005595
Judith L. Kennison
General Counsel
Texas Racing Commission
Effective date: September 1, 2000
Proposal publication date: May 26, 2000
For further information, please call: (512) 833-6699
Subchapter C. CLAIMING RACES
Subchapter O. UNBUNDLING AND MARKET POWER
Subchapter P. PILOT PROJECTS
Part 8.
TEXAS RACING COMMISSION
Chapter 311.
OTHER LICENSES
Subchapter B. SPECIFIC LICENSES
Chapter 313.
OFFICIALS AND RULES OF HORSE RACING