Part 2.
PUBLIC UTILITY COMMISSION OF TEXAS
Chapter 25.
SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS
Subchapter B. CUSTOMER SERVICE AND PROTECTION
16 TAC §25.41
The Public Utility Commission of Texas (commission) adopts
new §25.41 relating Price to Beat with changes to the proposed text as
published in the November 10, 2000,
Texas Register
(25 TexReg 11213). This section implements the Public Utility Regulatory
Act (PURA), Texas Utilities Code Annotated §39.202 and §39.406
(Vernon 1998, Supplement 2001) as these sections of PURA relate to the regulation
of the price to be offered by affiliated retail electric providers (REPs)
for the five year period succeeding the implementation of retail choice. This
section was adopted under Project Number 21409.
This section is necessary to establish the calculation methodology and
other requirements under which the price to beat (PTB) will be established
and administered by affiliated REPs. The commission believes that the 6.0%
rate reduction embodied in Senate Bill 7, 76th Legislative Session, is an
integral part of the restructuring process in Texas. However, the commission
is cognizant of the experiences in other states. Where default services have
not been reflective of the market prices of electricity for some or all of
the months in a year, the development of a robust market has been largely
stunted. Many retail customers who switched providers have returned to the
default service during summer months, and in some cases, on a more permanent
basis.
In the rule as adopted, the existing base rate structure will be maintained
for price to beat rates and each rate component will be reduced by 6.0%. Affiliated
REPs will be required to offer a price to beat for each rate and service rider
for which a price to beat customer was taking service on January 1, 1999,
unless otherwise approved by the commission.
The rule also prescribes how the initial fuel factor portion of the price
to beat will be set in accordance with PURA §39.202(b) and permits an
affiliated REP to request a seasonal fuel factor for small commercial customers.
For residential customers, the rule retains the structure for the fuel factor
that currently exists for the integrated utility. The commission finds that
imparting seasonality to the fuel factor as provided in the rule should be
the only remedy available for affiliated REPs to address potential gaming
of the price to beat. The commission has determined that other suggested mechanisms
to address the gaming potential such as minimum contract terms if a customer
returns to the PTB, seasonal rates only upon return to the PTB, or tracking
accounts that effectively pass through market prices to PTB customers (i.e.,
the TXU seasonal adjustment mechanism (SAM)) should not be adopted because
they create significant disincentives for customers to test the competitive
market.
The obligation to offer the price to beat expires at the end of 60 months
after the beginning of competition. The affiliated REP may also not offer
rates other than the price to beat rates for residential or small commercial
customers until the earlier of 36 months after competition begins, or when
40% of the residential or small commercial load served by the affiliated transmission
and distribution utility prior to customer choice is served by non-affiliated
REPs. This section, as adopted, establishes the methodology for calculating
the 40% threshold for each class.
This section also establishes procedures under which the fuel factor portion
of the price to beat may be adjusted for changes in the prices of natural
gas and electricity in the market, in accordance with PURA. The adjustment
mechanism for natural gas prices is based on a percentage change in average
forward gas prices from the gas prices used in setting the seasonal final
fuel factors that will be effective beginning January 1, 2002. As adopted,
this section provides for a minimum 4.0% materiality threshold before the
fuel factors may be adjusted. Under this standard, if the percentage change
in gas prices exceeds 4.0%, then the affiliated REP may petition to adjust
the seasonal fuel factor by percentage equal to the change in gas prices.
The rule also establishes a benchmark for "headroom" under the price to beat
based on the average of the price of a three year contract for full requirements
service for price to beat customers and the most recent average 12 month forward
prices received for baseload capacity auction products required to be auctioned
by Substantive Rule §25.381 of this title (relating to Capacity Auctions).
An affiliated REP will also be allowed to adjust the fuel factor portion of
the price to beat if the amount of headroom under the price to beat decreases.
The combination of these two adjustments is intended to ensure that the price
to beat does not become a below market rate where it is initially above market,
or become further below market in the event that the price to beat is initially
a below market rate in a particular area. The ability of the affiliated REP
to make these adjustments will aid in the development of a robust retail market.
Furthermore, the use of one and three year forward power prices is intended
to strongly encourage REPs to manage wholesale price volatility through the
use of longer term contracts and other hedging tools.
Additionally, the commission finds that it is appropriate, after a sufficiently
liquid electricity commodity index has developed in an affiliated REP's power
region and the power generation company (PGC) affiliated with the affiliated
REP has finalized its stranded cost determination and non-bypassable charges
or credits, as appropriate, to allow affiliated REPs to request a change to
their fuel factor in order to reflect changes in the price of purchased energy
indicated by this index. It is not appropriate to move to such an index until
the stranded costs of the affiliated PGC are finalized as any stranded cost
charges (or credits to return prior stranded cost collection) will not be
finalized until stranded costs are finalized. At that time, if the price to
beat for an affiliated REP is in danger of being below market because of high
market prices for generation, the return of any excess mitigation, or negative
stranded costs if the commission determines that it has the authority to require
the return of negative stranded costs, can be used to address concerns about
headroom and thereby mitigate the effects of high market prices on price to
beat customers. Subsection (g)(1)(F) has been added to allow for this transition
and prescribes these preconditions and the method by which an affiliated REP
must transition to the use of an electricity index.
This section also establishes criteria for determining whether or not a
customer is eligible for price to beat service. Under the rule, all residential
customers and small commercial customers with a peak demand of less than 1,000
kilowatts are eligible for the price to beat. If a customer's peak demand
exceeds 1,000 kilowatts, the customer is no longer eligible for price to beat
service. However, a customer may be eligible again if the customer's peak
demand does not exceed 1,000 kilowatts for a period of 12 consecutive months.
Public hearings on the proposed section were held at commission offices
on January 11, 2001 at 9:30 a.m. and January 22, 2001 at 1:00 p.m. Representatives
from the Alliance for Retail Markets (ARM) (whose members include Green Mountain
Energy, AES New Energy, Inc., Exelon Corporation, Strategic Energy, Enron
Energy Services and the New Power Company), American Association of Retired
Persons (AARP), American Electric Power Company (AEP), the City of Amarillo
(Amarillo), the City of Dallas (Dallas), Cities served by TXU (Cities), Consumers
Union, Texas Legal Services Center (TLSC), and Texas Ratepayers to Save Energy
(collectively referred to as Consumer Commenters), Office of Public Utility
Counsel (OPC), Reliant Energy, Inc. (Reliant), Shell Energy Services Company,
LLC (Shell), Spectrum Energy (Spectrum), the State of Texas (State), True
North, and TXU Energy Services Company (TXU REP) attended the January 11 hearing
and provided comments. To the extent that these comments differ from the submitted
written comments, such comments are summarized herein.
Representatives from ARM, AEP, Consumers Union, Entergy Gulf States, Inc.,
on behalf of its retail business (Entergy REP), OPC, Reliant, Texas-New Mexico
Power Company (TNMP), and TXU REP attended the January 22 hearing and provided
comments. To the extent that these comments differ from the submitted written
comments, such comments are summarized herein.
Initial comments were filed on December 11, 2000, by ARM, AEP, Cities,
City of Houston and Coalition of Cities (Coalition of Cities), Consumer Commenters,
El Paso Electric Company (EPE), the Electric Reliability Council of Texas
(ERCOT), Entergy REP, OPC, Reliant, Shell, Southwestern Public Service Company
(SPS), TNMP, and TXU REP. CLECO ConnexUS also supported the ARM comments.
Reply comments were filed on January 2, 2001, by ARM, AEP, Cities, Coalition
of Cities, Consumer Commenters, Entergy REP, OPC, Reliant, REP Coalition (whose
members include Reliant Energy, TXU Energy Services and ARM), Shell, TNMP,
and TXU REP.
Others commenting on the rule were AARP, Dallas, and Spectrum.
In the preamble to the proposed rule, the commission posed the following
questions:
Question 1: Is the use of the NYMEX natural gas
price index referenced in subsection (f)(3) appropriate for the establishment
of two seasonal fuel factors? If not, what mechanism should be included in
the rule to appropriately reflect the different cost of power in summer and
non-summer months?
Several commenters, including Consumer Commenters, Cities, OPC and TXU
REP were opposed to the establishment of seasonal fuel factors in general.
The Consumer Commenters and TXU REP expressed concern that seasonal fuel factors
will alter the existing rate structure of price to beat customers and that
altering the rate structure of the price to beat violates PURA and is contrary
to the intent of the legislature. TXU REP stated that Senate Bill 7, 76th
Legislative Session (SB7) does not require that price to beat rates precisely
track the affiliated REP's power costs or that affiliated REP's transfer variations
between summer and winter wholesale power prices to retail customers. TXU
REP asserted that the seasonal rates resulting from the proposed rule would
punish customers, creating the kind of rate crisis that San Diego customers
experienced in the summer of 2000.
Entergy REP disputed TXU REP's assertion that Texans will experience monthly
market based prices akin to customers in San Diego. Under the proposed rule,
Entergy REP stated that the initial seasonal fuel factors in Texas will be
cost-based. Once set, the initial factors may be adjusted for changes in fuel
prices. In contrast, according to Entergy REP, in San Diego, monthly electric
power exchange prices were automatically passed through directly to customers.
Consumer Commenters opposed the seasonal fuel factors and the use of any
index to establish the amount of those fuel factors. Additionally, Consumer
Commenters argued that Senate SB 7 requires the commission to update utilities'
current fuel factors, which do not contain a seasonal differential. Consumer
Commenters asserted that PURA §39.202(b) requires the commission to determine
the fuel factor for each utility as of December 1, 2001, and that this directive
leaves no room for redefining the fuel factor. Consumer Commenters concluded
that any change in the fuel factor should be applied as it is today and must
be made in a commission fuel reconciliation proceeding. Consumer Commenters
expressed concerns about deregulation in other states, including California,
that the competitive providers have not been able to offer lower prices to
the consumers as they had promised, and that in Texas the only way to raise
the price to beat is through a fuel adjustment. Additionally, Consumer Commenters
expressed concern over the possibility that while the affiliated REP may be
losing money, its parent company would be making money on the sale of power
or using its corporate structure in some way to disadvantage the affiliated
REP's customers. As such, Consumer Commenters argued that affiliated REPs
should be given strong incentives to hedge their risk, and that if they do
not they should not be rewarded by getting an increase in the price to beat
rate.
TXU REP stated that the commission should not set two or any number of
seasonal fuel factors because this approach is punitive to customers, is not
contemplated by the price to beat provisions in PURA and is unnecessary since
residential and small commercial customers are unlikely to engage in gaming
activities anyway. TXU REP commented that retail price to beat rates to customers
were never intended to track costs by month or by season and that no compelling
arguments in favor of such treatment have been advanced by other commenters.
TXU REP noted that the advocates for seasonal factors are the new non-affiliated
REPs like Shell and members of ARM who recognize that an artificial change
in summer rates will drive customers away from the affiliated REPs which will
benefit non-affiliated REPs.
Consumer Commenters contended that there is currently no summer-winter
differential in the existing fuel factors of investor-owned utilities in Texas.
Therefore, they concluded, that the most appropriate mechanism to reflect
summer-winter differentials would be the opportunity for affiliated REPs to
request appropriate adjustments to their fuel factors based on significant
increases in the cost of fuel. Several commenters observed that the implementation
of seasonal fuel factors where they are not currently in place may have the
effect of increasing the total price per kilowatt hour (kWh) in the summer
season, which would be inconsistent with the provisions of PURA Chapter 39.
AEP stated that this effect is unlikely to result for the AEP companies, since
they already have seasonal fuel factors that reflect the higher average cost
of generation in the summer months. AEP suggested that concerns about the
potential for monthly price increases should be addressed in the proposed
rule by making the requirement for a seasonal differential optional. AEP also
suggested that affiliated REPs be required to demonstrate that use of seasonal
fuel factors would not result in total cost increases in each month.
ARM noted that for many investor-owned utilities, base rates may already
reflect some seasonality. Because utilities' base rate structures vary in
this regard, ARM concluded, it may be necessary to determine the customer
impacts of incorporating different levels of seasonality into the fuel factors
for each utility on a case-by-case basis. ARM stated that as a policy matter
it may be unreasonable to use
any
kind of
broad index reflecting the actual spread between summer and non-summer spot
electricity prices for establishing seasonal differentials in the fuel factors,
given the adverse impact on customers that may result.
OPC commented that the current price to beat rate structure includes a
capacity cost seasonal differential in base rates. Therefore, OPC determined
that in the absence of actual experience in the marketplace, there is no reason
to conclude that the existing differential is inadequate. Spectrum expressed
concern about the price to beat becoming a below market rate. Spectrum also
commented that the 10% materiality threshold in the rule as proposed was too
high given that affiliated REPs can only request changes in the fuel factor
twice per year.
OPC stated that because the proposed fuel factor differentiation may squeeze
headroom in the summer, when household electric bills are highest, they do
not recommend any form of seasonal differentiation of the fuel factor. AARP
also expressed opposition to the staff-proposed seasonality adjustment. Reliant
commented that it does not necessarily advocate a seasonal fuel factor.
Entergy REP, Shell and TNMP disagreed with TXU REP and the Consumer Commenters'
arguments that PURA does not permit seasonality. Entergy REP and Shell noted
that PURA §39.202(b) does not limit the commission to one fuel factor
applicable to all seasons. TNMP opposed the elimination of the seasonal factor
as proposed in initial comments by TXU REP and Consumer Commenters. If the
commission does not allow seasonal factors, TNMP commented, then the affiliated
REP would not be able to raise the price to beat to meet higher costs in the
proposed summer season which would eliminate headroom and therefore damage
the competitive framework.
Shell urged the commission to include seasonal fuel factors in the rule
to help insure that the PTB tracks the true cost of power as closely as possible,
sending accurate price signals to customers and to the market as a whole.
Shell contended that seasonal fuel factors should be mandatory, not optional
as some commenters proposed. Shell reasoned that without accurate price signals
customers would not be able to react rationally to changes in the cost of
power and that competitors may not be able to serve the residential market.
Entergy REP also supported seasonal fuel factors and believes they should
be optional, subject to the constraint that the PTB fuel factors would be
designed such that the aggregate annual weather-normalized PTB billings with
seasonal factors cannot exceed the aggregate annual PTB billings without seasonal
factors for the average PTB customer of each rate class. Entergy REP pointed
out several advantages to this approach. First, a PTB customer will pay no
more, in the aggregate, than a customer without seasonal factors. Secondly,
the affiliated REPs can mirror market prices more closely, enhancing headroom.
Finally, the effects of gaming will be mitigated.
Shell, ARM, EPE, Entergy REP, Cities, SPS, AEP, and OPC were generally
opposed to using the NYMEX natural gas price index for the establishment of
two seasonal factors. ARM, SPS, TNMP, OPC, Shell and Cities expressed concern
that gas prices are often significantly higher in the winter than in the summer,
while the opposite is true for wholesale power costs. The Cities stated that
this runs counter to the commission's apparent attempt to increase the summer
price to beat to deflate incentives to game the price to beat. ARM further
commented that the NYMEX natural gas index does not track either the price
curves or the volatility of electricity prices. Other commenters, including
AEP, noted that the seasonal differences in the price of natural gas and electricity
have historically been inversely correlated. These commenters reasoned that
the NYMEX natural gas price index might not be a reliable indicator of changes
in the price of purchased energy.
The City of Dallas asserted that the risk of linking the price to beat
solely to the cost of gas is that if the cost of other fuels decreases, then
the price to beat would be artificially inflated to reflect the rising cost
of gas. Subsequently, once the price to beat period expires, the affiliated
REPs could then undercut other competitors and drive them away.
Several solutions were proposed in the event that the commission determines
that seasonal fuel factors are necessary and appropriate. ARM stated that
a differential of a cent ($ .01) between summer and non-summer fuel factors
would be a reasonable starting point for addressing the issue of seasonality.
ARM stated that at the opening of the retail market, a one- cent seasonal
differential should minimize any potential adverse impact on customers, while
giving appropriate signals with respect to electricity price.
Consumer Commenters stated that the staff-proposed seasonal one-cent seasonal
differential is not about fuel, but about market prices, gaming, and capacity
costs and would add between $10-14 to summer electric bills, which in turn
would wipe out the 6.0% decrease under the price to beat. Consumer Commenters
also stated that whatever the winter rates would be, a one-cent seasonality
adjustment would always be approximately $10-14 more in the summer and as
such customers would not see any savings in the summer months. Consumer Commenters
did not provide any information to support this assertion.
TNMP also disagreed with the initial comments of OPC and ARM that argued
in favor of a fixed seasonal differential, as this does not reflect the costs
of each of the affiliated REPs. TNMP contended that these seasonal differentials
would arbitrarily produce economic "winners" and "losers" out of the affiliated
REPs and the non-affiliated REPs that seek to compete with them.
If the commission does include a seasonal fuel differential for headroom
purposes, OPC suggested that the initial fuel factor be developed with an
initial summer rate, which is five mills higher in the summer than in the
winter. OPC stated that the five mill fuel factor seasonal differential would
continue in any subsequent adjustment based upon 12-month average fuel prices.
OPC also suggested that if the commission prefers a differential which is
developed more precisely, it is possible that an alternative to the five mill
value could be developed in each initial fuel factor proceeding based upon
the utility's gas generating station weighted average heat rate for summer
and winter seasons. OPC stated that ARM's one-cent differential was too high
and compared it to their own one-half cent. OPC concluded that a half-cent
differential would almost double the existing summer bill differential for
some utilities. Therefore, OPC recommended that given the large electric bills
experienced by air-conditioning users during hot summers, any seasonal differential
should be conservatively selected in order to produce a more modest result.
TXU REP suggested that the commission seriously consider the effect that
these proposed rate differentials would have on residential and small business
customers. TXU REP's analysis indicated that a five mill per kWh increase
in the summer months (OPC's compromise position) would increase a typical
residential summer bill by 7.0%, and a one-cent per kWh increase as proposed
by ARM would increase typical residential summer bills by 13.5%. TXU REP stated
that the increase resulting from Shell's recommended use of the ERCOT-B profile
would be 32%. TXU REP argued that the SB 7 model was designed to provide benefits
for all customers while avoiding mistakes made in other states. Seasonal factors
applied to all customers, TXU REP concluded, are not consistent with these
objectives. TXU REP particularly disagreed with Shell's proposal to establish
seasonal fuel factors based on seasonal differences in wholesale power markets
relying on the ERCOT-B index for example, to set seasonal fuel factors for
markets within ERCOT. TXU REP contended that the proposals of Shell, OPC and
others would produce a rate shock that would lead to a consumer outcry comparable
to that recently experienced in California.
Cities' suggested amendments would require each utility filing for its
seasonal fuel factors to identify all projected firm purchases of power and
purchases of economy (non-firm) energy for which the price paid is determined
by the price of natural gas or the cost of gas fired generation. Cities suggested
this change is necessary to implement a price to beat adjustment mechanism
that tracks the impact of changes in natural gas prices on the cost of purchased
power as an affiliate should not be permitted to claim and recover hypothetical
increases in cost that would not have been recoverable by the integrated utility.
Cities also proposed changes to allow for adjustments to the seasonal fuel
factors as a result of the gas generation component of current fuel factors.
Cities contended that nuclear fuel, coal and lignite prices will not vary
with natural gas prices and that SB 7 only allows for the recovery of increases
that are the result of increases in natural gas and purchased power expense.
EPE, Reliant, Shell, SPS, and other commenters proposed that an electricity
index be used instead of a natural gas index. EPE stated that the use of a
power index will capture the effect of a change in gas prices as well as other
power market drivers. Shell agreed and requested that seasonal fuel factors
be established based on differences in wholesale power market prices. Shell
suggested that the prices from the wholesale market could be obtained from
Entergy REP agreed with the initial comments filed by SPS, Shell, and EPE
that proposed that seasonal fuel factors be based on purchased energy prices
rather than a natural gas index. Entergy REP stated that the fuel-based seasonal
price differential as proposed would not be adequate to reflect the overall
seasonal price differential that will occur in the wholesale electricity markets.
Entergy REP claims that seasonality based solely on fuel costs ignores the
seasonality impacts of non-fuel capacity costs that will be reflected in wholesale
electricity prices. Entergy REP stated that setting seasonal fuel factors
based on the fuel mix and fuel prices in each season will not accurately reflect
the seasonal differences in electricity prices. According to Entergy REP,
setting seasonal fuel factors in this way would result in seasonal fuel factors
that are flat relative to electricity market prices and would likely induce
gaming opportunities that the seasonal fuel factors are intended to prevent.
Entergy REP supported the proposal by SPS, Shell and EPE to use an electricity
index rather than a natural gas index to set the initial seasonal fuel factor.
Entergy REP commented that the seasonal shape would most closely mirror the
seasonality of the costs faced by competitive REPs thereby providing customers
better economic price signals in each season. AEP agreed that a power index
would be more beneficial for establishing seasonal fuel factors. AEP acknowledged
that there is difficulty in selecting a forward-looking power index that is
robust at the start of competition, although it is likely that one will develop
over time. When that happens, AEP asserted, the commission should use this
index because it will more closely track the expected seasonality of power
prices.
Entergy REP proposed a slightly different alternative. Entergy REP stated
that the total annual revenue to be recovered through the fuel factor should
be based on the projected fuel and purchased power costs for 2002. To set
the initial seasonal fuel factors, Entergy REP recommended that projected
2002 annual fuel and purchased power costs be allocated to summer and non-summer
seasons based on a known historical relationship between load weighted electricity
spot prices for the summer and non-summer periods (such as in the "Into Entergy"
market as reported in a publicly available source) and then divided by the
applicable summer and non-summer kilowatt-hours in 2002. This method, Entergy
REP asserted, would ensure that the seasonal fuel factors more closely mirror
the seasonality of the market costs faced by competitive REPs and would provide
customers more accurate price signals in each season. In addition, Entergy
REP commented that relying on a historical relationship between spot electricity
prices that is objective and verifiable is preferable to determining the seasonality
of the initial fuel factor based on a projected, unknown fuel mix. Entergy
REP proposed changes in the rule to permit the calculation of separate seasonal
rolling averages and the adjustment of seasonal factors based on the rate
of change between separate seasonal rolling averages and the separate seasonal
NYMEX baseline moving averages.
Reliant commented that if fuel factors are the only way to prevent seasonal
gaming, then Implied Heat Rates (the price of a purchased energy block for
a period divided by the price of natural gas for the same period) rather than
natural gas prices, should be used to shape the seasonal fuel factors. Reliant
contended that seasonal fuel factors should be used for all price to beat
customers and that seasonal fuel factors must be initially shaped and subsequently
adjusted using Implied Heat Rates. Reliant proposed that seasonal fuel factors
be obtained by calculating one fuel factor, and then shaping the fuel factor
for seasonality. Reliant assumed that this process would repeat for each fuel
factor adjustment. In other words, under Reliant's proposal, a new single
fuel factor would be calculated for each requested adjustment, using the mechanism
detailed in the "PTB ADJUSTMENT" section in the Coalition Reply Comments.
This formula is discussed in more detail in Question 2 below.
If the commission does not accept Reliant's proposal for seasonality, Reliant
recommended that (1) no seasonal adjustment be used, and (2) that price to
beat customers (residential and small commercial with demand less than 50
kW) who leave and then return to the affiliated REP be required to choose
from one of the following requirements: (a) a seasonal price to beat rate
rider equal to the incurred summer subsidy calculated using actual prices
from the balancing energy market; or (b) balanced billing, with the affiliated
REP having the ability to request a deposit to cover the initial balanced
billing subsidy, in addition to the deposit allowed under the customer protection
rule. Reliant also suggested that regardless of seasonality, all returning
small commercial customers with a peak demand greater than 50 kW should be
required to accept a minimum term of one year with a buyout equal to the incurred
summer subsidy calculated using actual prices from the balancing energy market.
Cities urged the commission to refrain from instituting a seasonal fuel
factor until evidence suggests that residential and small commercial customers
are gaming the price to beat.
Upon further consideration, Reliant proposed that seasonality should not
apply to residential customers under any circumstances. Restrictions on individual
PTB customers should be limited to returning small commercial customers with
a peak demand, either in the aggregate or on an individual meter basis, exceeding
50 kW. Reliant proposed that such returning customers be subject to one of
two restrictions: (1) seasonal rates, or (2) a tracking mechanism that calculates
a running account of the actual cost to serve such customers versus the actual
charge to such customers based on allowed summer rates.
TNMP asserted in reply comments that the commission should use three seasons,
rather than two, to more accurately reflect the changing energy prices. Entergy
REP suggested that the seasonal factors be calculated for the periods of May
through September and October through April to reflect the fact that summer
load conditions begin in May. ARM agreed with Entergy REP that the summer
season should include the month of May.
TNMP stated that the commission should clarify the language of the rule
to ensure that the differential in the summer and winter NYMEX natural gas
index does not equal the differential in the summer and winter fuel factors.
If this change is not made, TNMP asserted it would result in an artificially
low price to beat and the concomitant loss of headroom during the summer season,
stifling competition and saddling the affiliated REP with a price to beat
under which it will suffer losses.
Cities stated that the fuel factor adjustment as proposed is a one-way
street in favor of the utilities. Cities suggested that the commission and
other parties have the authority to request an adjustment to the PTB fuel
factors. In the alternative, Cities suggested that any surcharge should be
regarded by the commission as a temporary surcharge. Cities suggested that
if gas prices fall 10% below a threshold the surcharge would expire.
Cities expressed concern that the proposed rule permits only the affiliated
REP to request an adjustment to the fuel factor and that the one-sided request
ensures that the fuel factor will never be lower than its initial level. Cities
also objected that the proposed rule does not require any resulting over-recoveries
to be flowed back to customers.
The commission finds that under the plain language of PURA §39.202(l),
only the affiliated REP can request a change in the fuel factor portion of
the price to beat. Furthermore, the commission finds that the combination
of the ability to choose service from alternate providers, natural competitive
forces, and the operation of the "clawback" under PURA §39.262(e) in
the 2004 true-up provide compensation to ratepayers for the price to beat
being an above market rate. Finally, one of the benefits of the implementation
of retail choice is that there is a more efficient avenue for customers to
receive lower prices than through commission rate proceedings.
The commission disagrees with TXU REP, Consumer Commenters, OPC and others
that seasonal fuel factors are not contemplated under PURA. PURA §39.202
states that the commission shall determine the fuel factor for each electric
utility as of December 31, 2001. PURA Chapter 36 contains the authority for
the commission to establish rates. Fuel factors are specifically discussed
in §36.203. Section 36.003 provides that rates must be just and reasonable,
and rates may not be unreasonably preferential, prejudicial, or discriminatory.
There is no specific grant of authority to set seasonal rates, but the commission
has for some time set rates that include seasonal variation, including fuel
factors, under the broad authority contained in Chapter 36. The commission
notes that all investor-owned utilities currently have seasonal base rates,
and that the AEP utilities (Central Power & Light Company, Southwestern
Electric Power Company and West Texas Utilities Company) currently also have
seasonally differentiated fuel factors. The commission concludes that it has
the authority under PURA to establish seasonal fuel factors under the PTB.
The commission further disagrees with those commenters, including Consumer
Commenters and AARP, who suggested that seasonal fuel factors will increase
customer bills and eliminate the 6.0% PTB decrease and send inappropriate
price signals, comparable to those being experienced in the California electric
market. First, unlike California, the statute expressly permits a portion
of the price to beat (fuel factor) to be adjusted based on significant changes
in the costs of natural gas and purchased energy. By contrast, as noted by
Entergy REP, in San Diego, monthly electric power exchange prices were automatically
passed through directly to customers. Additionally, under a one-cent seasonal
differential, customers with average usage would still receive the 6.0% rate
decrease contemplated under PURA §39.202(a) on an annual basis. A one-cent
seasonal differential would likely eliminate the 6.0% decrease in the summer
months (June-September) for customers with average usage. However, such seasonality
would not increase a customer's bill over what it would otherwise have been
under regulation for the summer months. Moreover, these customers would receive
greater decreases in the non-summer months. On an annual basis, price to beat
customers with average usage would receive the 6.0% rate decrease contemplated
under PURA §39.202(a).
After consideration of the comments received by parties on the issue of
seasonality and given the concerns voiced by some parties about the perceptions
of the impact on high summer- usage customers and a recognition that residential
customers are less likely to exhibit switching behavior that would take advantage
of the fact that the PTB may be below market during the summer months, the
commission finds that it is reasonable to allow the affiliated REP to request
a seasonal fuel factor for small commercial price-to-beat customers (as defined
in subsection (c) of the rule) only at this time. The commission does find
that nothing in PURA prohibits the commission from setting seasonal fuel factors
for all customers, as it currently does for the AEP companies. However, in
order to provide continuity for residential customers during the initial transition
to a competitive market, the commission declines, at this time as a matter
of policy, to introduce seasonality into the residential fuel factor where
it does not exist today. For utilities with existing seasonal fuel factors,
the commission finds that it is appropriate to allow their affiliated REPs
to retain the seasonality that exists in the current fuel factors for all
customers, if they so desire.
The commission finds that imparting seasonality to the fuel factor is the
only remedy that will be available for the affiliated REP to address gaming
concerns. The commission believes that other mechanisms that have been proposed
to address the gaming potential such as minimum contract terms if a customer
returns to the PTB, seasonal rates only upon return to the PTB, or tracking
accounts that effectively pass through market prices to PTB customers (i.e.,
the TXU seasonal adjustment mechanism (SAM)) should not be adopted because
they create significant disincentives for customers to test the competitive
market.
Subsection (f)(3)(C) of the rule has been revised accordingly.
Question 2: Is the use of the NYMEX natural gas
price index referenced in subsection (g)(1) the appropriate mechanism to use
in adjusting the fuel factor for significant changes in the price of natural
gas and purchased energy? If a purchased power index should be used instead
of the gas price index, what index should the commission use? Are there other
adjustment mechanisms that would more accurately reflect significant changes
in the price of natural gas and purchased energy?
This was by far the most controversial aspect of this rule. Virtually all
commenters who filed comments and/or participated in the public hearings on
this rule expressed an opinion on this issue. The commenters were sharply
divided on this question. Some commenters, particularly Consumer Commenters,
OPC and Cities, were generally opposed to the use of a purchased power or
energy index. A number of other commenters, including most of the utilities
and the REPs were strongly in favor of using some type of energy index to
adjust the fuel factor portion of the price to beat. Numerous proposals, including
gas-only, a combination of gas and purchased energy and purchased energy-only
were suggested in comments and at the public hearings. The commission carefully
considered all of these proposals before making its decision on this issue.
ARM and Shell commented that the index used in adjusting the fuel factor
was not as important as insuring that the initial price to beat fuel factors
are set at the proper level. These commenters noted that a competitive market
will not develop if the PTB is set at a level below the price that new market
entrants must pay to purchase power and ancillary services.
No commenter supported a natural gas price index as the sole mechanism
to adjust the price to beat throughout the entire price to beat period. Reliant
commented that natural gas by itself is not an adequate means for adjusting
the fuel factor. Reliant stated that the old regulatory regime of reconcilable
fuel, energy and capacity will be gone on January 1, 2002. After the choice
date REPs will buy power, not natural gas or any other generation fuel. Reliant
stated that market forces of power supply and demand will affect the price
of power and natural gas will be only one component in the market. Reliant
and other commenters asserted that natural gas prices have not historically
been perfectly correlated with power prices. In fact, Reliant asserted that
since power began trading in ERCOT gas price movements explain only 17% of
the variance in electric price movements.
TNMP and Entergy REP did not oppose the use of the NYMEX natural gas index
if it applied only to the natural gas portion of the utility's current fuel
mix. Entergy REP proposed to track changes in the forecasted price of natural
gas and apply the changes to the gas portion of the fuel mix rather than applying
the changes to the entire fuel factor as proposed in the rule. Under this
scenario, Entergy REP proposed to keep the cost components fixed, for example,
coal and nuclear, since the prices for those inputs are not as volatile and
the costs are generally fixed under the fuel factor rules today. Entergy REP
stated that its proposal to adjust the fuel factor would maintain stability
in the way that rates are set and adjusted and that it would be relatively
straightforward to implement, while also avoiding the problems associated
with relying on illiquid electricity forward prices.
TNMP stated that it did not oppose the proposed rule's reliance on the
NYMEX gas index because it agrees that the commission should use a transparent
index of electricity market prices. TNMP did not believe such an index currently
exists. However, TNMP suggested that the commission also consider the impact
of the NYMEX on the affiliated REP by applying the NYMEX to a formula that
incorporates the affiliated REP's resource mix. Therefore, TNMP concluded,
the commission should allow for two types of adjustment mechanisms; one would
entail a simple change in the price of the NYMEX and the second would entail
a more detailed analysis of the affiliated REP's projected resources similar
to the fuel factor proceedings that occur today. TNMP provided sample formulae
for these scenarios.
TXU REP stated that the energy purchases the affiliated REP will make beginning
in 2002 are unlikely to be fuel-specific and will be based on highly confidential,
highly competitive business agreements. According to TXU REP and others, it
would be wholly contrary to the intention of SB 7 for the commission to continue
to apply traditional fuel factor regulation to an affiliated REP's energy
purchases, much less make a prudence determination regarding them.
AEP proposed that a forward looking NYMEX natural gas strip that matches
the adjustment period should be used because it would allow the affiliated
REP to appropriately hedge and would reflect changes in competitive retail
electricity prices vis-à-vis the price to beat. AEP stated that since
natural gas is the fuel on the margin in Texas, and since the initial fuel
factor already reflects the current fuel mix of each utility, it is more appropriate
initially to adjust the fuel factor by the changes in the marginal fuel --
natural gas. AEP reasoned that when a robust forward-looking purchased power
index is available, it should be utilized, since it will better track the
changes in prices paid by affiliated REPs for supply and the prices that affiliated
REPs will use to compete. AEP concluded that adjusting the fuel factor by
fuel mix, as some parties have suggested, will not accurately reflect the
market conditions for purchasing electricity faced by the affiliated REP and
will serve to artificially lower an affiliated REP's fuel factor adjustment.
Other parties contended that an electricity index would be a more appropriate
tool for adjustment. TXU REP, ARM, EPE, Entergy REP, SPS and Shell, stated
that a purchased power index is a more appropriate way to track changes in
the price to beat fuel factor. Shell emphasized that this is an electricity
market -- not a natural gas market, therefore changes in the price of purchased
power should be the key determinant in adjusting the fuel factor to calculate
the price to beat. Shell urged the commission to base changes in the fuel
factor on changes in regional power prices as published in
Megawatt Daily
's Market Report.
EPE stated that relying solely on the use of a gas index to control the
fuel factor component fails to adequately take into consideration other key
drivers that affect the price of power. EPE also stated that since it is the
only Texas utility in the Western Systems Coordinating Council, the use of
the NYMEX Palo Verde power price index is the most appropriate indicator of
the price of power that is available for delivery to the El Paso region. EPE
reasoned that realizing that non-affiliated REPs will have the ability to
pass power costs through to their customers, the commission should consider
using a single index for affiliated REPs that is comparable so that customers
can make an apples-to-apples comparison in choosing a REP. EPE concluded that
if a single mechanism is to be used to control the fuel factor component of
the price to beat, it should be a power index since that is the commodity
that all REPs will trade. SPS stated that an electricity price index should
be used to establish the seasonal fuel factors since the REP is not directly
exposed to gas prices because it does not own generation.
TXU REP suggested that an electricity index is consistent with the statutory
language and superior to a natural gas index for several reasons. The legislature
used the terminology "natural gas and purchased energy" with the knowledge
that an affiliated REP was prohibited from owning generation and therefore,
would not have gas costs that change over time. While a natural gas index
captures changing market conditions in the natural gas market, it is not indicative
of changes in the electricity market. Conversely, changes in the natural gas
market will be subsumed in an electricity index.
Cities maintained that if the PTB is indexed to market prices, the appropriate
base for the index is the cost of generation embedded in the PTB. Cities also
stated that any changes in the price to beat fuel factor should be temporary,
expiring on the first day of the month following a decrease in natural gas
prices below the 10% benchmark established in subsection (g)(1)(C). Cities
asserted that this adjustment was consistent with its belief that a transitory
spike in gas prices should not permanently enrich the affiliated REP.
TNMP argued that the commission should reject proposals to have fuel factor
adjustments expire after a certain period of time. TNMP asserted that this
proposal is prohibited by PURA which provides for changes to fuel factors
only to reflect changes in natural gas and energy prices or where the affiliated
REP's financial integrity is threatened.
Reliant concluded that in order to assure adequate headroom, and thus,
robust competition, it is critical that the price to beat accurately track
the actual price of power, and since the fuel factor is the only mechanism
to adjust the price to beat it should be based not only on the price of gas
but on the prices of purchased energy as well.
TXU REP stated that the natural gas price index referenced in subsection
(g)(1)(A) of the proposed rule would not adequately reflect changes in the
cost of electric energy purchased for consumption by customers. TXU REP noted
that this is problematic because in all cases affiliated REPs will be purchasing
electric energy, but in no case will they be purchasing natural gas for consumption
in generating facilities. TXU REP also expressed concern that capacity auctioned
and sold will not be available to the affiliated REP from its affiliated PGC.
TXU REP asserted that in addition to the purchased power that the affiliated
PGC already acquires to meet the customer requirements of the integrated utility
today, it will also have to acquire power to replace capacity auctioned and
sold. TXU REP contended that the cost of this additional capacity is not reflected
in existing purchased power contracts, but will have to be reflected to track
the affiliated REP's cost changes during the price to beat period since use
of the NYMEX index would not capture these costs. TXU REP stated that a number
of factors ranging from generation capacity shortages to transmission constraints
and major outages could have a significant impact on the cost of purchased
power. TXU REP concluded that the best method to track and adjust for those
variations in fuel and purchased power costs is to set and index the fuel
factor against a tradable power index. Unfortunately, TXU REP pointed out,
a power index equivalent to the NYMEX Henry Hub gas index does not exist within
ERCOT at this time, although it is reasonable to assume that an ERCOT futures
market will develop during the first five years of the price to beat. Therefore,
TXU REP proposed that the rule utilize the NYMEX Henry Hub gas index to adjust
the initial fuel factor established under the proposed rule. TXU REP concluded
that after a futures market has been developed for ERCOT power and an index
is developed that more accurately reflects the affiliated REP's cost of purchasing
energy, then future adjustments of the REP's fuel factor should be based on
this index.
OPC disagreed with TXU REP on use of an electricity index. OPC stated that
even as future indices are developed, it is uncertain whether the transactions
will reflect a liquid, fully competitive market. More importantly, OPC stated
it is unlikely that such indices will reflect the bulk of bilateral contracts
that would comprise the market structure in Texas.
Consumer Commenters also disagreed with proposals to use a purchased power
index for adjustments to the price to beat fuel factor. Consumer Commenters
stated that a purchased power index, or any index which includes capacity
costs should not be substituted for the fuel factor in the price to beat.
Consumer Commenters stated that the commission's current rules permit the
recovery of purchased "energy" costs through the fuel factor, but prohibit
the recovery of purchased "power" capacity or demand charges. Consumer Commenters
and Coalition of Cities pointed out that PURA §39.202(l) uses the term
"purchased energy", not "purchased power" with regard to fuel adjustments
under the price to beat. They also stated that an index will not account for
discontinued contracts and other factors that would lower fuel costs. Therefore,
they reasoned, it is inappropriate to use any automatic cost adjustment process
because it will likely overcharge residential customers. Consumer Commenters
also objected to use of an ERCOT wholesale index. Because the ERCOT generation
market is designed as a bilateral contract market the price of most power
purchases will not be publicly available and thus, Consumer Commenters concluded,
the only type of index that could be developed would be based on spot purchases
or balancing energy -- both high price products.
The Coalition of Cities stated that the price to beat is intended to guarantee
residential and small commercial customers a 6.0% rate reduction and to protect
such customers from potential rate increases caused by competition. The Coalition
of Cities noted that the Legislature limited adjustments to two scenarios.
First, the price to beat can be adjusted to reflect significant changes in
the price of natural gas and purchased energy. Secondly, an adjustment can
be made to protect the financial integrity of the affiliated REP. The Coalition
of Cities contended that the term "purchased energy" is not synonymous with
the term "purchased power." According to the Coalition of Cities, the term
purchased power is much broader than purchased energy and includes things
such as the charges for capacity costs that are not included in purchased
energy. The Coalition of Cities concluded that if affiliated REPs are allowed
to adjust the price to beat for differences in the price of power, the price
to beat would be rendered meaningless. Cities also commented that an index
based on firm purchased power cost would not accurately measure the change
in the price that price to beat customers would have paid with continued regulation.
OPC was also skeptical that an index could be developed for purchased power
transactions that will be compatible with adjustments to the fuel factor.
TNMP clarified at the January 22, 2001, workshop that more recent contracts
typically do not have capacity components. Since TNMP has no purchased cost
recovery factor (PCRF), it recovers its purchased energy costs through its
fuel factor.
AEP urged the commission to consider the implementation of a quarterly
adjustment mechanism to more accurately reflect PTB fuel and purchased power
costs.
Since there is no reliable energy index at this time, several commenters
proposed methods to solve this problem. Reliant stated in its initial comments
that the new purchased energy product could be determined in a number of ways,
although the joint comments with the Coalition detail Reliant's preference.
Reliant expressed confidence that public indices will be developed for purchased
energy. In the interim and until such indices develop, Reliant committed to
working with the Intercontinental Exchange to develop such a product for market
opening. Alternatively, Reliant suggested that pricing for a 5 x 16 product
could be crafted from the existing capacity auction product by: (1) dividing
the premium for the baseload capacity auction product by the on-peak hours
in the delivery period and then adding the strike price; and then (2) dividing
that result by the average gas price over the delivery period. Finally, Reliant
stated that the new purchased energy product could be determined from
Reliant proposed a solution based on the Implied Heat Rates (price of purchased
energy/price of natural gas) that Reliant stated would introduce the concept
of purchased energy into the fuel factor adjustment calculations and make
them more meaningful and accurate. Reliant proposed the following formula
for fuel factor adjustments and the Coalition adopted this formula for the
adjustment of the fuel portion of the price to beat:
Fuel Factor
new
= Fuel Factor
base
* (1+((Gas
new
- Gas
base
)/Gas
base
)) * (1+((Heat Rate
Where:
Fuel Factor
base
= The fuel factor at the time
an adjustment is requested. After the fuel factor has been adjusted the first
time, it would be the fuel factor currently in use at the time an adjustment
is requested.
Gas
new
= NYMEX futures price calculated under §25.41(g)(1)(A)-
(B). The Coalition recommended that the 60-day average contained in the proposed
rule be shortened to any one day between the date of the last energy auction
and the scheduled date of the next energy auction.
Gas
base
= NYMEX futures price calculated under
as proposed. For the first fuel factor adjustment, it would be the NYMEX futures
price calculated under proposed §25.41(f)(3)(D). For all subsequent adjustments,
it would be the Gas
new
from the immediately preceding
fuel factor adjustment.
Heat Rate
base
= the Implied Heat Rate calculated
from the last fuel factor adjustment request. The Implied Heat Rate would
be calculated by dividing the power prices for any given period by natural
gas prices from the same trading day for the same delivery period. For the
initial adjustment request, this number would be calculated by dividing the
daily Peak ERCOT Index Power Price data from
Power
Markets Weekly
by the daily gas price data from Gas Daily's Houston
Ship Channel index, averaged over the entire calendar year 2000. For all subsequent
adjustment requests, this number would be the Heat Rate
new
calculated in the immediately preceding fuel factor adjustment.
Heat Rate
new
= the Implied Heat Rate from
the purchased energy product, which is sold as an annual forward. This value
would be calculated by dividing the forward power price from a purchased energy
product by the NYMEX futures gas price from the same trading day for the same
delivery period covered by that product.
Ideally, the Coalition stated, the Implied Heat Rate should be calculated
from a publicly traded product. Until such a product trades in ERCOT the Coalition
recommended that auctions should occur on September 1 (covering energy delivered
the following January through December), March 15 (covering energy delivered
the following June through May) and July 15 (covering energy delivered the
following November through October) of each year. According to the Coalition's
recommendation, each auction would involve 1.0% of the Texas jurisdictional
installed capacity of the affiliated PGC. To ensure compatibility with true
market prices, auctions should be conducted under standard terms and conditions.
As part of the Coalition's proposal, auction products would be sold pursuant
to a standard agreement such as the Edison Electric Institutes' Master Power
Purchase & Sale Agreement and credit terms should generally follow the
capacity auction rule. The Coalition stated that these auctions would generate
individual monthly prices for 5 x 16 firm energy to be delivered in the time
period covered by the auction.
At the same time the auction occurs (i.e., September 1, March 15 and July
15), the Coalition stated, the NYMEX gas futures price for gas delivered in
each month of the same time period covered by the auction would be calculated.
The monthly 5 x 16 firm energy price would then be divided by the monthly
gas price to obtain a monthly Implied Heat Rate for each of the 12 months
covered in the auction. Finally, these monthly Implied Heat Rates would be
averaged to obtain the Heat Rate
new
. Until the
Heat Rate
new
value is calculated based on a publicly
traded product instead of an auction, all affiliated REPs requesting a fuel
factor adjustment would use the same Heat Rate
new
in the fuel factor adjustment formula (i.e., all affiliated REPs would conduct
the auctions described in this paragraph on the same day, and these auctions
would generate one Heat Rate
new
for all affiliated
REPs).
The Coalition recommended that, at the affiliated PGC's option, the auctioned
capacity would count toward the 15% total statutory requirement in PURA §39.153.
Ideally, the Coalition commented, a commodity product for ERCOT future energy
price will develop and once trading volumes reach significant levels, that
product should be used in place of the auction prices explained above.
This proposal is not a pass-through of purchase power costs, the Coalition
noted. The Coalition pointed out that this is a critical distinction because
it means that this proposal would not result in the same market problems that
San Diego experienced, because this proposal encourages all REPs to hedge
on a forward basis rather than to purchase on a daily spot basis and then
pass on the volatile costs or to accrue those costs for future collection.
This divergence from the traditional fuel factor model is necessary because
the prices of natural gas and purchased energy are not adequately correlated
to allow natural gas to serve as a proxy for both the REP Coalition concluded.
Reliant noted that in general there is a pricing continuum with two pricing
alternatives (fixed and spot) and two purchase contracting alternatives (fixed
and spot). Some alternatives leave the REP more at risk while others leave
the customers more at risk. Reliant contended that at one extreme for example
there is a fixed retail price and a spot purchase contract price that would
result in a situation similar to the one experienced in California by Pacific
Gas and Electric (PG&E) and Southern California Edison (SCE) while a spot
purchase contract price and a spot retail price would bring about a situation
similar to the San Diego situation. Reliant commented that the Coalition Proposal
falls somewhere in between, where there is a small margin for exposure to
volatile prices by either the REP or the customer.
AEP stated that the Reliant and the Coalition proposals have some merit
in that they attempt to make use of forward electricity and natural gas prices
by incorporating an Implied Heat Rate mechanism. AEP's primary concern with
using power prices to adjust the seasonality of fuel factors is that there
is currently not an existing robust forward-looking power index. AEP also
proposed that the timing should be adjusted to reflect forward-looking natural
gas prices rather than lagging prices in order to prevent a timing problem.
AEP also expressed concerns with the heat rate proposed by Reliant and the
Coalition. AEP noted the inherent dichotomy between the Gas
new
portion of the formula (which is a 60-day moving average of NYMEX
futures prices) and Heat Rate
new
(which is an
Implied Heat Rate from the purchased energy product sold as an annual forward).
Specifically, AEP questioned whether the power price used to incorporate the
Heat Rate
new
would be taken at one point in time
and then compared against future forward looking gas prices taken at another
point in time. AEP stated that such a mismatch could result in fuel factor
adjustments that bear no resemblance to actual changes in market prices of
electricity.
OPC claimed that Reliant's fuel adjustment mechanism proposal is apparently
intended as a revision to the mechanism Reliant suggested in its business
separation plan (BSP) filing. The difference is only semantic, making the
adjustment mechanism appear to be a fuel price adjustment. In fact, the proposal
for an "implied heat rate adjustment" to the change in NYMEX gas prices, OPC
deduced, is a thinly disguised power cost index. By applying changes in the
gas-cost-to power-cost ratios to the gas price index, the proposed adjustment
is mathematically the same as a power cost index. OPC stated that it is subject
to the same criticism discussed in OPC's initial comments.
ARM suggested that the fuel factors should be shaped to reflect the different
load factors for the PTB customer classes, since the 5 x 16 energy auction
products described in the Coalition's reply comments would not be appropriate
for serving all classes. While load factors have not typically been taken
into account in establishing fuel factors in Texas, this is common in other
states, according to ARM, and nothing in PURA prevents the commission from
doing this on a going-forward basis. ARM recommended that such shaping could
be preformed by the parties in connection with the technical conferences recommended
by Entergy REP in its initial comments.
If the commission declines to adopt the Coalition proposal, ARM suggested
that the commission allow the fuel factor to adjust for changes in the price
of natural gas, using the NYMEX Henry Hub as an indicator of change, until
a reliable, liquid energy index develops. ARM proposed that the following
factors could be used to determine whether a market is sufficiently liquid:
1. The index should be published, verifiable, and independent (e.g., an
exchange);
2. The index should exhibit significant trading volume;
3. The index should exhibit small bid/asks spread; and
4. The index should have at least a couple of years of published price
history.
For instance, a good index would have two to three years of price history,
several million megawatts' (MWh) of volume trading every day, daily trading
of contracts at least three years out, and prompt-month bid/ask spreads of
less than $0.25. ARM suggested that the commission should solicit public comment
on whether a proposed index meets these criteria prior to effecting this change.
The entire fuel factor should be adjusted by the change in price.
AEP was unclear how Reliant's proposed formula for the adjustment of the
fuel factor would affect Central Power and Light (CPL) and Southwestern Electric
Power Company (SWEPCO). AEP stated that CPL is only required to auction capacity
for one year as a result of their merger agreement and that SWEPCO will be
auctioning capacity in a different market.
Reliant, responding to a request for a plan with a phase-in approach presented
a compromise proposal (Compromise Proposal) at the January 22 workshop. Although
this was not Reliant's preferred approach, Reliant could support it.
The Compromise Proposal would be a phase-in over five years although Reliant
stated that different phase-in periods could also be implemented. In 2002
there would be a 100% historical based price to beat. The natural gas price
index would be used to adjust the price to beat and the materiality threshold
used to make adjustments to the fuel portion of the price to beat would be
reduced from 10% to 4.0%. In 2003, 50% of the fuel factor could be adjusted
for changes in the natural gas prices according to the Compromise Proposal,
and 50% would be adjusted for changes in electricity prices based on the ratio
of the premium price in the most recent one-year or aggregated 12 months of
baseload capacity auctioned to the premium price in the September 2001 baseload
capacity auction. In 2003, the materiality threshold would remain at 4.0%.
In the period between 2004 through 2006, under the Compromise Proposal,
100% of the price to beat adjustment would be based on the electricity price
index that would be indicative of the current market prices of baseload power.
The fuel factor would be multiplied by the ratio of the current electricity
price index to the price of power paid in the September 2001 capacity auction
or the most recent baseload capacity auction price or index used to adjust
the price to beat. If an appropriate price index develops that is representative
of different types of product than the baseload capacity product, 100% of
the price to beat adjustment would be based on the ratio of such index to
the September 2001 capacity auction price paid for auction products that correspond
to the index product.
During 2004-2006 the materiality threshold would be 2.0%. The Compromise
Proposal would also reduce the period that closing forward 12-month gas prices
are averaged from 60 days to 5 business days and revise subsection (g)(1)
as proposed to state that a REP may file a fuel factor adjustment request
that is based upon the results of a full requirements request for proposal
(RFP) to provide service to at least 10% its expected price to beat load for
three years. The adjustment, in $/MWh would be the difference between the
low bid offered by suppliers and the current price to beat minus all non-bypassable
charges, losses, ERCOT fees, commission assessments and gross receipt taxes,
minus $5/MWh.
Reliant stated that given the size of its price to beat loads there would
be only one entity from which it could purchase sufficient power to serve
its price to beat load -- its PGC. Reliant expressed concern over being required
to enter into a below market contract with its PGC without some safety guarantee
from the commission regarding its treatment of the affiliated PGC in the excess
cost over market (ECOM) true up. Therefore, an important aspect of the Compromise
Proposal would be that the affiliated REP would enter into three to five year
contracts with the affiliated PGC for a declining portion of its price to
beat load. The contract prices would equal the regulated cost in the ECOM
model for baseload units and ECOM market price for gas units. Reliant noted
if the ECOM model provides that a baseload unit is valued at $43 in 2002 but
under the buy back contract they have to sell at a lower cost of service price,
i.e., $36, the issue is how the $7.00 differential is treated? Again, Reliant
sought assurances that it would not be required to bear the risk for not recovering
this differential in the ECOM true-up.
AEP agreed with Reliant that if the commission decided that an adequate
fuel portfolio must include buyback contracts between the affiliated REP and
the affiliated PGC, the affiliated PGC should not be penalized in the PURA §39.262
true-up valuation of ECOM for entering into long-term contracts with its affiliated
REP. AEP stated that power contracts between the affiliated REP and the affiliated
PGC should be allowed at either (1) market prices, or (2) prices equal to
or greater than the PTB less the sum of transmission and distribution charges
(T&D), other non-bypassable charges (NBCs), and the ERCOT administrative
fee (EF). If the affiliated REP has conducted a Request for Proposals for
its power needs and receives no price equal to or less than PTB less (T&D+NBCs+EF),
then, by definition, the PTB has been set at less than the market price. If
this is the case, AEP contends that the contract between the affiliated REP
and the affiliated PGC should be deemed to be equivalent to a market-based
contract for purposes of the ECOM valuation in the PURA §39.262 true-up
proceeding. Given such a determination, the ECOM of the PGC should not be
reduced or otherwise adjusted as a result of such a contract.
Entergy REP agreed that using long-term contracts between a PGC and the
affiliated REP in order to hedge the risks associated with its PTB obligations
would help to protect the financial integrity of the affiliated REP and provide
a more stable transition to competition. However, there are other ways that
an affiliate REP can hedge, including buying power and fuel products such
as forward strips and options from the market, financial instruments, or auctioning
full requirements service through an RFP. Entergy REP commented that each
REP should have the flexibility to pursue the hedging strategy that best meets
its needs.
AEP responded to the PGC buy-back issue by stating that it was concerned
that if the REP is prohibited from contracting with the affiliated PGC whether
at market or some other price then the REP could end up in a similar situation
similar to California. AEP expressed concern about a situation where output
has been sold to a third party. Knowing that the REP has to buy at that location,
AEP contended that the price could be driven up as the REP is caught in a
short squeeze.
OPC commented that to the extent that the commission believes it is necessary
to modify the PTB in order to insulate the financial health of the affiliated
REP, approval of such buy back contracts is the lesser of evils. The impact
of such buy backs upon the market- based valuation of the generation assets
during the true-up could be minimized through strict limitation on the duration
of such contracts and in reality may have no adverse impact upon the valuation.
The utilities' choice of market valuation methods (i.e., complete divestiture
versus sale of minority ownership in the capacity) is likely to have a more
significant impact upon the robustness of the market valuations. OPC did not
agree with Reliant's view that buy back contracts should alter the reconciliation
procedure for the 2002-2005 period specified in PURA. According to OPC, the
law contemplates that the affiliated REP will undertake the risk of offering
the PTB and does not contemplate that the cost of the utilities' efforts to
shield the REP from such risk should be added to the ultimate amount of stranded
cost.
Cities stated that if a utility chooses to hedge affiliated REP risks through
contracts with the affiliated generating company, the mix of baseload and
gas capacity purchased should match the PTB load shape.
Shell opposed a delay or phase-in of PTB rates that reflect the true market
cost of power, believing that under Reliant's proposal, non-affiliated REPs
will not be able to compete until after 2006. Shell believed that until then
the PTB will be below market and competitors will only be able to enter the
market by selling at a loss.
At the January 22 workshop, TXU REP proposed its own phase-in compromise
position. It proposed this approach for commission consideration to accommodate
future fuel factor adjustments, as needed, based on changes in the market
price of natural gas until a viable purchased energy index develops.
Among other provisions, the TXU REP phase-in compromise would use an initial
4.0% materiality threshold before fuel factor adjustments could be made, with
the threshold being reduced to 2.0% in 2004. TXU REP noted that a threshold
requirement is unnecessary because affiliated REPs will be limited to two
fuel factor adjustments each year. If the purpose of a threshold is to prevent
frequent and confusing rate changes for customers, the two-adjustment limitation
will accomplish that objective without leaving the affiliated REP exposed
for unrecoverable changes in market prices. Nonetheless, in order to develop
a mechanism acceptable to as many interested parties as possible, TXU REP
proposed an initial threshold starting at 4.0% and moving to 2.0% in 2004.
In 2003, TXU REP proposed to adjust 50% of the fuel factor based on the
ratio of the premium price in the most recent one-year or aggregated 12 months
of baseload capacity auctioned to the premium price in the September 2001
baseload capacity auction. For the years 2004 through 2007, the entire adjustment
to the fuel factor would be based on one of the following:
1. The ratio of the current electricity price index (indicative of current
market prices for baseload power) to the price of power paid in the September
2001 baseload capacity auction (or the most recent baseload capacity auction
price or index price used to adjust the fuel factor).
2. If an appropriate price index develops that is representative of a different
type of product than a baseload capacity product, the ratio of such an index
to the September 2001 capacity auction price paid for auction products corresponding
to the index product.
3. If no appropriate index is available, then the same as the electric
price ratio in 2003, but using the most recent capacity auction price used
to adjust the fuel factor as the denominator.
The commission requested TXU REP to work with other interested parties
on the concepts contained in its proposal and to clarify the "fail safe" language
that would insure that the price to beat is always an above market rate. In
comments subsequent to the January 22 workshop, TXU REP reported that a modified
version of the phase-in compromise supported by certain other interested parties
had been developed. TXU REP supported the newest version, but also supported
the version presented at the January 22 workshop as well as the original Coalition
proposal detailed in reply comments filed on January 2, 2001.
AEP supported several aspects of TXU REP's phase-in-proposal. First, AEP
agreed that it is appropriate to apply the fuel and purchased energy adjustment
to all of the costs of the utility as opposed to some portion of the costs
of the utility. AEP stated that linking the adjustment to the current mix
does not allow the market to open effectively. AEP also supported the fact
that this proposal would utilizes fewer days for the initial gas index, which
would provide utilities a better ability to hedge. Finally AEP supported the
move from a natural gas index to an electric power index. AEP noted that there
was a variation of this proposal that could accommodate SWEPCO.
ARM also supported reducing the period for averaging forward 12-month gas
prices to five days rather than the 60-days originally proposed in the rule.
AEP stated that the shorter time period would be more conducive to properly
managing risk. Also, ARM stated that the materiality threshold should be significantly
lower than 10%. Affiliated REPs are already collared by the fact that they
may only request two adjustments per year. ARM agreed conceptually with TXU
REP's "failsafe" provision although it suggested that the details of the provision
need additional refinement. Specifically, ARM expressed concern about the
"RFP process", the wholesale product that would be solicited, and whether
$5/MWh would provide sufficient headroom.
Entergy REP condoned the use of the capacity auction as a proxy for electric
prices during 2003, allowing for the flexibility to use the auction prices
in 2004 if an appropriate electric index is not available at that time, and
including a "fail-safe" provision. Entergy REP also supported a reduction
in the materiality provision from 10% to 4.0% and the shortened trading period
for calculating the natural gas index price.
AEP supported the fundamental structure of TXU REP's phase-in compromise.
Until a working and reliable purchased power index is operating within ERCOT,
AEP stated that it would support use of the natural gas price index for adjustment
of the fuel factor. In the event that the fuel indexing mechanism does not
properly reflect the market, a fail-safe mechanism should not only adjust
the PTB but should also ensure that customers of utilities without stranded
costs continue to receive the benefits of the 6.0% PTB rate reduction and
ensure that customers of these utilities are not harmed by competition. AEP
proposed to adjust the PTB when market prices increase at a rate greater than
the natural gas price index or future wholesale energy price index. AEP's
concern was that such increases would prevent competition from taking place
and prevent the affiliated REP from recovering its wholesale energy costs.
Consumer Commenters did not agree with TXU REP's proposal. Consumer Commenters
objected to a pass through of some type of market-based electricity price.
They stated that the legislation was passed with the assumption that the price
to beat would be above the retail price, that the market price would be much
lower. Therefore, Consumer Commenters stated that the legislation does not
really give the commission the tools it needs to deal with a different type
of market. If there is a problem that needs to be addressed about the market
not turning out the way it was expected, then Consumer Commenters suggested
such problems be addressed openly and perhaps even through legislation rather
than trying to patch something together under the price to beat rule.
OPC commented that it is unreasonable for the commission to state in advance
that a price index will be adopted, without any knowledge of the markets or
publicly available market indices that may exist in the future. Stating in
advance that an index will be adopted, even though considerable debate may
arise over the adequacy of the market index, seems to predispose the commission
to adopting some type of power cost index even if it is potentially subject
to manipulation. OPC argued that the commission should defer the decision
on whether it will change the PTB adjustment mechanism until 2004.
OPC stated that it would be willing to support a reasonable "fail-safe"
proposal but objected to TXU REP's PTB "headroom" calculation because it doesn't
examine the actual financial integrity of the REP, violates PURA §39.202(p),
and brings the other parts of the price to beat, such as T&D rates and
competition transition charges (CTCs) into the calculation. OPC expressed
concern over other problems including the multiple price to beat rates each
REP has and the resulting possibility of inter-class subsidies, as well as
the failure to link the $5/Mwh target for a REP's margin to actual costs.
If a headroom standard is to be used, it should be based on the adequacy of
the generation component of the PTB plus the fuel adjustment relative to alternative
measures of power costs.
OPC's alternative proposal developed very general standards for an affiliated
REP to request a "fail safe" exception with the applicant bearing the burden
of proof. The affiliated REP would have to show that its actual incurred power
costs were reasonably incurred, reflected prudent diversification and hedging
and that, despite the affiliate REP's best efforts, the level of such costs
continue to exceed the generation component of the price to beat, as adjusted
by the fuel factor.
Cities stated that TXU REP's proposals to phase in market-based indexing
are likely to result in the erosion of PTB protection and in excess profits
for utilities. Initially, an excess of capacity would hold down prices but
the utilities will be protected from fuel cost increases and insulated from
the low capacity utilization. Cities stated that the PTB already protects
utilities from the risk of low capacity charges, since it includes recovery
of costs that might otherwise be stranded as a result of transitory excess
capacity. If initial capacity charges are low, stranded cost associated with
sales to customers not taking PTB service will be recovered in the true up.
Cities added if the true up of ECOM produces stranded cost, PTB customers
are subject to possible double recovery.
Cities commented that TXU REP's proposed transitioning of the fuel factor
adjustment from gas prices to market prices would maximize the potential for
profit. During the first years, the natural gas price index would protect
utilities from cost increases while low capacity utilization raises potential
stranded costs. Later, the market-price based changes would protect the affiliated
REP from higher power prices while the affiliated PGC is reaping the profits
from those higher prices, Cities concluded.
Cities' stated that if the Legislature had intended a $5 per MWh floor
on headroom, SB 7 could have been written to provide such a floor. Cities
recommended that if any headroom floor is approved, it should be designated
as both a ceiling and a floor. However, Cities' argued that creation of headroom
should not be used to undermine the price reductions that SB 7 and PURA §39.202
provide. Cities noted that to the extent a headroom problem is expected to
exist at market opening, the origin of the problem is inflated utility claims
regarding T&D revenue requirements, transition costs and stranded costs.
The lack of headroom demonstrates that the economics of serving PTB customers
make it unlikely that these customers will benefit from competition. It is
illogical to remedy this problem by increasing the PTB to a level that exceeds
the rate that these customers would have paid with continued regulation in
order that they can "benefit" from competition.
Several parties stated that the liquidity of the market index should also
be an issue. Reliant offered the following working definition of liquidity:
when transactions by a single party do not result in a change in market conditions
such as price or bid/ask spread. Unfortunately, liquidity remains a subjective
measure, notwithstanding this working definition, because there is no directly
observable measure of liquidity. Therefore Reliant suggested that the better
question is whether a given index is indicative of true market prices. Reliant
argued that indicativeness can be assumed if the product underlying the index
is accessible by any interested party, the product underlying the index can
be arbitraged by those parties, and the market for the product underlying
the index is broad enough to interest both buyers and sellers.
Reliant concluded if these conditions exist, it would be too costly for
any participant to manipulate the market index. Both the 5 x 16 purchased
energy auction originally proposed by Reliant Energy as well as the capacity
auction for the 7 x 24 product meet these requirements for market indicators,
according to Reliant. The volume of trades that will be generated through
the capacity auctions, the inability of affiliates to participate, and the
use of the auction for the ECOM true-up all argue against the possibility
of manipulation of an index based on these capacity auctions.
Entergy REP expressed concern about using the NYMEX electricity forward
market to index the PTB because of the potential immaturity and illiquid nature
of the NYMEX electricity forward market. This concern arises due to the current
low, even zero, volume of the NYMEX "Into Energy" index and the large spread
between bid and ask prices in over-the-counter trading. Entergy REP stated
that there is no single quantitative measure sufficient to determine the existence
of a competitive, well-functioning, and liquid electricity market. Rather,
according to Entergy REP, there are a number of qualitative characteristics
that should be examined including, but not limited to, the following: trading
volumes on a NYMEX-type forward market; volume of trading; bid-ask spreads
in over-the-counter trading as reported in sources such as
Power Markets Weekly
, and consistency between the capacity auction
prices and the forward markets.
Affiliated REPs expressed concern over their ability to hedge properly
under certain proposals. TXU REP also stated that it had concerns about its
hedging ability when there was a 60-day period over which it would be required
to average gas prices. The TXU traders reportedly believe that the rule should
move to something more near term to allow the traders and all the various
companies the ability to hedge gas prices. TXU REP suggested five days, although
it admitted that five days might not be the perfect number.
AEP responded that its central issue was the importance of the ability
to hedge. An expert from AEP stated that all of the proposed models of the
price to beat do not propose hedging for the price to beat because the company
will not have knowledge of what the customer base is. AEP was concerned that
they currently manage the system day to day and that there are considerable
vagaries that the company has come to live with. For example, the load may
be higher due to weather, the loss of units effectively changes the average
or marginal costs, and what goes on outside of Texas affects the cost of power
in Texas. AEP stated that it currently tries to mitigate these on a daily
basis and as long as the costs are shown to be prudent, they have been protected.
AEP proposed that the commission provide some type of safety net for the affiliated
REP that would allow it to hedge a percentage that would be protected by the
commission up to that point.
Reliant pointed out that there is no fundamental value created by longer-term
purchases versus spot purchases. Financial theory holds that forward electric
prices represent the expected value of future spot price distributions, with
each price discounted appropriately for risk. Thus, according to Reliant,
hedging cannot create value in isolation. However, since REPs will operate
with low margins, some level of hedging is likely in order to prevent excessive
earnings volatility. On the other hand, hedging is also costly. Even with
forward purchases the REP is likely to lose margin due to the bid/ask spread.
Purchasing options to account for the unknown number of customers and their
volumes would also be expensive, particularly for summer volumes, according
to Reliant. In summary, Reliant contended that it is unlikely that long-term
contracting will lead to lower costs to customers. It would, however, limit
price volatility to customers and lower earnings volatility for the REP.
Reliant asserted that use of a one-day price would not increase volatility
significantly, but would allow commercial hedging to take place. TXU REP stated
that the company is putting rules in place to employ short, medium, and long-term
contracts to keep costs low.
TNMP pointed out that regardless of the index used to track changes in
energy costs, it will not account for changes in energy prices attributable
to ERCOT assessed fees. TNMP argued that the rule should incorporate an adjustment
mechanism to reflect significant changes in the ERCOT assessed fees including
independent system operator (ISO) transaction fees, unaccounted for energy
fees, congestion management fees, and others. Consumer Commenters expressed
concern about the levels of these fees and concluded that the fees should
not be automatically included in the fuel factor, but be subject to review
and approval by the commission.
Those parties who argued for power cost indices, OPC commented, ignore
the legislative policy for creating the price to beat. OPC explained that
the legislative policy for the price to beat is to provide a safe haven for
residential and small commercial customers from any adverse impacts of competition
that might arise during the transition period. The use of a fuel factor mechanism
for adjustments, OPC explained, indicates that PTB customers would not face
any consequences greater than under a regulated cost of service rate. OPC
reasoned that the Legislature was aware that this provision placed risks on
the affiliated REP, which no longer owned generation. OPC contended that the
affiliated REP is required to absorb that risk unless it becomes so onerous
that an adjustment to the PTB needs to be requested on financial integrity
grounds.
The commission first notes that notwithstanding the comments of certain
parties in this rulemaking, none of the proposals considered by the commission
should result in Texas experiencing the problems experienced in California
over the past 12 months. Even if the fuel factor adjustments were tied to
a 12 month forward electricity price, the fact remains that it is only the
fuel factor portion of the price to beat that can be adjusted, and even that
portion can be adjusted no more than twice per year. As a result, the monthly
pass-through of average spot market prices (as occurred for San Diego Gas
and Electric customers) cannot occur in Texas while there is price to beat
protection. Conversely, under no circumstance is the price to beat the "hard"
rate cap under which PG&E and Southern California Electric were forced
to operate. Even the sole use of a gas price index would allow the price to
beat to be adjusted for changing market conditions. Additionally, while the
commission hopes the provision is never needed, the ability to raise the price
to beat for financial integrity reasons under PURA §39.202(p) also provides
protection against a significant divergence in wholesale and retail prices.
The commission concludes that it is appropriate to ensure that headroom
under an affiliated REP's price to beat remains no worse than where it initially
exists, positive or negative. In other words, to the extent an affiliated
REP's price to beat is initially above market, a determination should be made
for the headroom that exists on January 1, 2002, and if that headroom were
to shrink, the affiliated REP would be able to request a change in the fuel
factor sufficient to restore the initial headroom. Alternatively, if the price
to beat were initially below market, if market prices of electricity rose
such that the price to beat became further below market, the affiliated REP
could request an increase in the fuel factor sufficient to return the price
to beat to where it started. In both cases, headroom could of course increase
if market prices fell, but an affiliated REP could keep headroom from becoming
worse. However, to the extent that the price to beat remains significantly
below market for a sustained period of time, competition will likely not develop
before the expiration of the price to beat period, and it may be likely that
an affiliated REP will need to also request a change in the price to beat
due to financial integrity issues.
Under this approach, the commission concludes that the market price of
electricity to be used for determining the initial/benchmark level of headroom
and to permit adjustments should be as follows an average of the prices resulting
from a three-year RFP and one year capacity entitlement strips. Under this
proposal, affiliated REPs would file the results of a three-year RFP at the
end of 2001, near the time of the setting of the initial price to beat fuel
factors. Affiliated REPs would then be able to subsequently file RFP results
to justify an adjustment to the price to beat to restore the initial amounts
of headroom. The capacity auction prices used will be from the initial capacity
auctions that will be conducted in September 2001. The commission concludes
that it is most appropriate to use the prices for the baseload products that
would be needed to serve PTB load. This is similar to the TXU REP proposal
and reflects the fact that the capacity auctions will occur frequently during
the course of the price to beat period, and that the baseload product will
have the largest number of entitlements auctioned. Affiliated REPs will then
be able to use the most recent auction of one year-forward strips of auction
products, or the most recent aggregated forward 12 months of products to justify
a change to the fuel factor.
Use of an average of a three year RFP and the capacity auction prices will
allow changes in the PTB due to the average change in wholesale market prices
over two different terms. Therefore, to the extent the prices of three-year
terms are less volatile than the prices of one-year forwards, use of the average
will reflect the commission's belief that it is appropriate for REPs to contract
for a variety of different terms of power in order to hedge against market
volatility. This approach will require affiliated REPs filing the results
of a three-year RFP in late 2001 to calculate the benchmark/initial headroom
figure.
The commission concludes that this approach provides the most consistency
with the statutory language of PURA §39.202(l), which allows for adjustments
to the fuel factor upon a showing that the fuel factor does not reflect significant
changes in market prices. The commission shares the concerns raised by a number
of commenters that recent increases in the price of natural gas and purchased
power may make it difficult for non-affiliated REPs to compete during 2002,
even at the levels of shopping credits anticipated by staff. The commission
agrees that it is critical that the initial price to beat fuel factor be set
as accurately as possible, but disagrees with any assertions that the fuel
factor should reflect anything other than the historic fuel mix of the integrated
utility, as this is how the fuel factor would have been set under continuing
regulation (with allowance for that fuel mix to change as the utility's portfolio
changes).
However, the commission also recognizes the undeniable fact that REPs,
affiliated or not, will not incur costs after 2002 based on a historic fuel
mix; rather, all REPs will be purchasing power in the market. As such, using
a measure of the forward market price for electricity at or near the time
of the final setting of the initial price to beat fuel factor to establish
a benchmark for headroom appropriately reflects the fact that the price to
beat may initially be above market in some areas, and below market in others.
To the extent that any subsequent changes in market prices cause that headroom
to shrink, disappear, or become even more negative, such changes represent
significant changes in market conditions that will not be reflected in the
setting of the initial fuel factor. Therefore, in accordance with PURA §39.202(l),
a change to that fuel factor is warranted. To the extent headroom is initially
insufficient to allow non-affiliated REPs to compete for price to beat customers
in a particular area, competition will clearly not take hold until the market
price of generation falls. However, the commission concludes that maintaining
at least the initial level of headroom is fully consistent with the intent
of SB 7 that the price to beat serve as a protection for customers while still
fostering the growth of a robust competitive retail market.
The rule has been revised to incorporate the changes discussed above. Specifically,
two new terms, "headroom" and "representative power price", have been added
to the definitions section of the rule. Headroom is defined in the rule as
the difference between the average price to beat and the sum of the non-bypassable
charges approved by the commission in the pending unbundled cost of service
(UCOS) cases. This definition requires a headroom calculation for an average
residential and small commercial customer. The term "representative power
price" is defined as the simple average of the RFP for 10% of the PTB load
for three years and the price resulting from the baseload capacity entitlements
in the capacity auctions, using the most recent auction of a 12-month forward
strip or the most recent aggregated forward 12-month entitlement. It should
be noted that the "representative power price" is not indicative of the true
cost to serve a price to beat customer, but instead is simply the blend of
power prices that are to be used to gauge how prices are changing in the marketplace.
Subsection (f)(3)(D) has been revised to require affiliated REPs to file
information in October 2001 to establish the initial headroom that exists
as a result of the initial fuel factor established in October 2001.
Subsection (g)(1)(E) has been revised to permit the affiliated REP to request
an adjustment to the fuel factor if the representative power price has changed
such that headroom under the PTB has decreased and the adjustment is necessary
to restore the amount of headroom established by the commission in the initial
fuel factor.
Language has also been added in subsection (g)(1)(C) and (g)(1)(E) to ensure
that each subsequent adjustment to the fuel factor is based on the gas prices
used at the time of the previous adjustment, if the adjustment is made due
to changes in the averaged forward gas price.
The commission further disagrees with Consumer Commenters and others who
suggest that the establishment and subsequent adjustment of fuel factors under
PURA §39.202 must be applied as it is today and that any change in the
fuel factor may only be made in a fuel reconciliation proceeding. PURA §39.202
does not contain any such limitation. Section 39.202 provides that the fuel
factor may only be changed twice a year and only in order to reflect significant
changes in the price of natural gas and purchased energy. The rule as adopted
includes reasonable procedures for adjusting the fuel factor.
The commission also disagrees with the Cities' suggestion to make fuel
surcharges temporary. While PURA apparently does not prohibit the commission
from imposing this requirement, the commission concludes that such a limitation
is unreasonable and unnecessary. The fact that affiliated REPs may only request
fuel factor changes twice per year together with the materiality threshold
of §25.41(g)(1) should guard against unnecessary fuel factor adjustments.
Section 39.202(l) clearly provides for adjustments to the fuel factor based
on significant changes in the price of natural gas and purchased energy and
affiliated REPs. It is reasonable to allow such adjustments to remain in effect
until the next commission approved adjustment. Additionally, this proposal
would introduce an added layer of price uncertainty into the market. Finally,
the commission concludes that the fuel factor under the price to beat may
be adjusted up or down, which should provide a measure of protection for price
to beat customers. If affiliated REPs fail to timely request a downward adjustment
in the fuel factor, affected customers will presumably seek service from another
provider. Additionally, PURA §39.262(e) recognizes the reality that the
price to beat may be an above market rate, and requires an offset to the final
stranded cost determination to reconcile the amount above market that price
to beat customers will pay if they remain with the affiliated REP.
The commission disagrees with Cities and others that the fuel factor adjustment
should be only applied to the portion of the historical fuel factor that consists
of gas-fired generation or purchased energy. Beyond 2002, the market price
of generation will likely be set by gas-fired generation, and as such, it
is appropriate to apply the changes in the market price of natural gas and
purchased energy to the entire fuel factor in order to maintain the level
of headroom in the price to beat.
Furthermore, the commission finds that it is appropriate, after a sufficiently
liquid electricity commodity index has developed in an affiliated REP's power
region, and the power generation company affiliated with the affiliated REP
has finalized their stranded cost determination and non-bypassable charges
or credits, as appropriate, to allow affiliated REPs to request a change to
its fuel factor in order to reflect changes in the price of purchased energy
indicated by this index. The commission finds that it is not appropriate to
move to such an index until the stranded costs of the affiliated PGC are finalized
as any stranded cost charges (or credits to return prior stranded cost collection)
will not be finalized until stranded costs are finalized. At that time, if
the price to beat for an affiliated REP is in danger of being below market
because of high market prices for generation, the return of any excess mitigation,
or negative stranded costs if the commission determines that it has the authority
to require the return of negative stranded costs, can be used to address concerns
about headroom, and thereby mitigate the effects of high market prices on
price to beat customers. Subsection (g)(1)(F) has been added to allow for
this transition and prescribes these preconditions and the method by which
an affiliated REP must transition to the use of an electricity index.
Question 3: In the provisions of paragraph (g)(1),
is 10% the appropriate threshold for an adjustment to the fuel factors? If
an index other than NYMEX natural gas prices is ultimately chosen by the commission,
what threshold would be appropriate for that index?
Entergy REP stated that in general, a 10% threshold that uses NYMEX gas
prices is appropriate. Entergy REP recommended that the adjustment threshold
be based on the rate of change of the NYMEX gas contract versus a baseline
NYMEX gas contract price and that the gas portion of the baseline price to
beat should be adjusted in cases where the threshold is reached and a requested
change in the fuel factor is made. However, Entergy REP concluded that due
to potential exposure to the affiliated REP at price to beat levels that are
less than the 10% threshold, the affiliated REP should also have an opportunity
to demonstrate to the commission that a change in the market price of purchased
power/gas is significant even if the 10% threshold has not been met. In reply
comments Entergy REP altered its position in favor of a 4.0% threshold.
Several affiliated REPs expressed concern that the 10% factor was too high
or that a set factor was unnecessary. Reliant, TXU REP, and AEP concluded
that a fuel factor adjustment threshold is unnecessary. TXU REP stated that
the 10% threshold is too high, particularly since affiliated REPs are limited
to only two opportunities per year to seek fuel adjustments. TXU REP stated
that under current commission rules utilities are allowed to revise their
fuel factors twice a year and are required to petition the commission to refund
or surcharge if they have materially over or under-collected fuel expenses,
with the materiality threshold being defined as 4.0% of annual estimated fuel
costs. TXU REP pointed out that the significant difference between the proposed
rule and existing fuel factor provisions is that the current process allows
a utility to request a refund or surcharge if its fixed fuel factor has materially
over or under- collected its fuel expenses. Since the proposed rule contains
no surcharge mechanism, if fuel prices increase, an affiliated REP bears all
the costs associated with the difference between its fixed fuel factor and
the cost of the power it buys, because a fuel factor adjustment only provides
a remedy going forward. Therefore TXU REP recommended that the proposed rule
be amended to permit an affiliated REP to request no more than two fuel factor
changes each year without any minimum materiality threshold. TXU REP argued
that the commission should consider the rate shock that customers would experience
if rates were held steady until a 10% or greater change in fuel prices occurred,
at which time the entire increase would be added to the customers' bills.
Reliant stated that the 10% threshold is far too large, especially when contrasted
with the 4.0% threshold under the current fuel rule.
TNMP urged the commission to adopt a materiality threshold of 4.0%, stating
that a materiality threshold of 10% is unnecessarily high and that the result
of imposing this high materiality threshold would be to force affiliated REPs
to maintain prices that are not warranted by the market cost of energy.
TNMP also expressed concern that the procedural schedule under this process
could take as long as 135 days, which could result in additional disparities.
SPS suggested that the appropriate threshold level to use in adjusting the
fuel factors will be dependent on the level of headroom available in the final
price to beat rates. However, the level of headroom won't be known until the
unbundled delivery rates and final price to beat rates are established. SPS
reasoned that if headroom is significantly squeezed, then the proposed 10%
threshold is too high and a lower threshold may be more appropriate.
TNMP and Entergy REP both argued that 4.0% would be a more appropriate
threshold. TNMP stated that some commenters incorrectly assumed that the affiliated
REP would never seek to lower the price to beat. TNMP asserted that if market
prices decrease significantly, the affiliated REP will either lower its prices
or expose itself to competitive disadvantage.
The Coalition proposed a "safe harbor" where any affiliated REP meeting
the criterion (lesser of 4.0% of the index or $40 million in lost headroom
over an annualized period) should be automatically allowed an adjustment as
calculated under Reliant's proposed adjustment.
OPC stated that reliance upon the 4.0% threshold is misplaced for two reasons.
First, OPC argued that the 4.0% threshold in the existing fuel rule exists
in a reconcilable fuel cost regime where over-recoveries will be returned
to ratepayers. Secondly, OPC reasoned the denominator of the 4.0% threshold
in the current fuel rule is based upon the total fuel balance including nuclear
and coal.
Consumer Commenters and OPC both contended that if the commission adopts
a materiality threshold it should be greater than 10%. Consumer Commenters
stated that the rule should not specify a materiality threshold and should
not allow an affiliated REP to change the fuel cost factor based on an index.
All fuel costs must be reviewed Consumer Commenters stated, to assure that
higher costs in one category are not offset by declining costs in another
category. Consumer Commenters added that the rule should specifically state
that the commission or other parties have the right to request to have the
fuel factor lowered to reflect market prices. Consumer Commenters concluded
that the materiality threshold for defining "significant" should be higher
than 10%, and that "significant" changes should be substantial and long term,
especially since they are not subject to reconciliation under the proposed
rule. OPC did not believe that 10% would be an appropriate threshold if it
is assumed that neither the commission nor any other interested party may
request a downward adjustment. OPC concluded that in the absence of additional
information about which index is chosen, a threshold of 15-20% would be more
reasonable without regard to whether the index is based on gas or purchased
power.
AEP suggested that in lieu of a threshold factor, the use of some combination
of a more continual adjustment (i.e., quarterly) of the price to beat with
market prices coupled with deferred accounting treatment of the losses or
gains associated with the affiliated REP's changing supply costs.
ARM expressed concerned about whether non-affiliated REPs will have sufficient
notice prior to a change in fuel factor. To the extent that non-affiliated
REPs offer products that are a percentage discount off of the PTB, those REPs
will need sufficient advance notice to make the corresponding change in their
rates. ARM suggested two options for ensuring sufficient notice would be to
establish a predetermined schedule for affiliated REPs to file for fuel factor
changes, such as designated time periods in the spring and fall, as is being
done to set the initial fuel factor. Another option would be to require a
30-day notice period prior to any change in fuel factor.
Based on the comments received, the commission concludes that a 4.0% materiality
threshold is reasonable. The commission disagrees with those commenters suggesting
that there be no materiality threshold. PURA §39.202(l) specifies that
PTB fuel factors may be adjusted for "
significant
changes in the market price of natural gas and purchased energy...."
(emphasis added). Use of the term "significant" indicates that some sort
of threshold be demonstrated in order to justify an adjustment under §39.202(l).
On the other end of the spectrum, the commission disagrees with OPC and Consumer
Commenters who suggested a threshold in excess of 10%. While some materiality
threshold is appropriate, it should not be excessive. If the threshold is
set too high, affiliated REPs will be unable to meet it without first incurring
significant losses. The commission believes such a result is contrary to the
intent of PURA §39.202.
The commission concludes that a 4.0% materiality threshold is reasonable
because such a threshold is analagous to the existing materiality threshold
in the current fuel rule. While the commission recognizes that the current
4.0% threshold is based on the current solid fuel and gas mix of the integrated
utility, in a competitive market, the market clearing price of purchased power
will be set by the marginal unit in the market, which will most likely be
a combined-cycle gas turbine.
Question 4: In light of the seasonal fuel factors
proposed by subsection (f)(3), is the minimum contract term established in
proposed PUC Substantive Rule §25.477 (a)(8) (published in the September
1, 2000, Texas Register at 25 TexReg 8554) an appropriate or necessary mechanism
to discourage customers from gaming the affiliate REP's price to beat rates?
Although commenters acknowledged that the commission has rejected minimum
term requirements in the customer protection rulemaking (see 26 TexReg 125
(January 5, 2001)), many addressed this issue again in this rule to support
the use of minimum term requirements. Entergy REP offered comments about the
importance of permitting affiliate REPs to require returning customers to
agree to minimum term contracts. Entergy REP stated that anti-gaming provisions
are necessary to ensure a robust, competitive market and to protect the price
to beat supplier from undue risk. Entergy REP commented that the proposed
rule's treatment of the fuel factor may not adequately allow the seasonal
market value of wholesale electric energy to be reflected in the price to
beat. Entergy REP commented that utility fuel factors are cost-based and do
not necessarily track competitive market electricity prices. To mitigate risk
to the price to beat provider, Entergy REP maintained that minimum contract
terms of 12 months or other anti-gaming provisions are appropriate for price
to beat customers who seek to return to price to beat service after receiving
service from a competitive REP.
EPE stated that affiliated REPs are prohibited from including a term of
service in agreements with residential and small commercial customers whereas
non-affiliated REPs do not have this same prohibition. EPE recommended that
all REPs be placed on equal footing in this regard and be given the discretion
to use minimum contract terms in a non-discriminatory manner. SPS, TNMP and
AEP also supported the use of minimum contract terms. SPS stated that a minimum
contract term for price to beat customers returning to the affiliated REP
was necessary because requiring the customer to remain for a minimum term
helps the REP ensure that any monthly imbalances between volatile costs and
non-volatile revenues will balance out over the year. AEP strongly supported
a one-year minimum contract term regardless of the length/nature of past customer
relationships.
AEP and Reliant argued that the prohibition on minimum contract terms for
small commercial customers violates the cost allocation principles underlying
commercial rates that have minimum terms. AEP supported the revision of this
prohibition to take into account commercial rates that currently have minimum
terms. TXU REP commented that large commercial customers should be required
to fulfill any contractual service obligations they have to their existing
retail electric provider before being able to return to the price to beat
rates. Entergy REP concurred with TXU REP on this point.
Reliant proposed mechanisms to discourage customers from gaming the system.
These proposals are addressed above in Question 1. Consumer Commenters opposed
Reliant's plan that required a customer returning to the price to beat to
choose either a seasonal rate rider or balanced billing with an additional
deposit. Consumer Commenters suggested the proposal be rejected as it is inconsistent
with SB 7 and punishes the consumer for exercising a right that is provided
by law.
TXU REP stated that the commission in more than one rulemaking proceeding
has acknowledged a need to develop mechanisms to prevent the kind of gaming
that has occurred in other states where the retail markets have already opened
to competition. TXU REP concluded that seasonal fuel factors should not be
applied to all customers to prevent gaming because of the harsh rate impact
they will have on customers, particularly residential customers, during the
summer months. TXU REP also perceived that significant gaming by residential
and small business customers appears less likely, in large part because of
mechanisms employed in rules like those governing aggregation, provider of
last resort (POLR) and customer protection.
TXU REP proposed a solution that focuses on commercial customers with peak
demands greater than 50 kW but less than 1000 kW. TXU REP reported that its
discussions with Pennsylvania market experts indicated this customer group
has contributed to the gaming problems in Pennsylvania. TXU REP determined
that these customers have the greatest ability to game the affiliated REP's
price to beat, as they are able to assess available pricing options and to
unfairly manipulate the system to choose the most favorable combination of
market-based and semi-regulated rates. In lieu of the seasonal fuel factor
mechanism, TXU REP proposed to give commercial customers over 50 kW two choices
when they return to the affiliated REP: (1) accept service at the price to
beat with a one-year term or (2) accept a price to beat rate under a seasonal
adjustment mechanism (SAM) rider. Under TXU REP's proposal the SAM rider would
be a market price curve, reflecting on a monthly basis, the difference between
the price to beat and the affiliated REP's cost to purchase electricity. TXU
REP contended that a provision should also be added to the rule to prohibit
REPs, aggregators, and agents from gaming the price to beat by providing incentives
or inducements for customers to switch to the affiliated REP and to provide
penalties for violations.
AEP and Entergy REP commented that seasonal fuel factors alone are inadequate
to prevent gaming. Entergy REP stated that TXU REP's claim that seasonal fuel
factors are unnecessary for small commercial customers is unsupported. TXU
REP fails to mention, Entergy REP reported, that the Pennsylvania Commission
had to intervene when a competitive supplier publicly threatened to dump 48,000
residential customers back to price capped service due to high summer prices.
The resulting rule in Pennsylvania required a returning residential customer
to stay for a year at a fixed rate or choose a monthly market price rate.
Entergy REP concluded that the actions in Pennsylvania suggest that anti-gaming
concerns are valid as applied to small commercial customers and their suppliers,
and emphasize the need for seasonal fuel factors to address these concerns.
AEP noted the problems in Pennsylvania and other states where gaming has
occurred. AEP stated that while it believes that gaming provisions should
be directed at larger, more sophisticated commercial customers, it believes
that small commercial customers are equally capable of "gaming" with more
serious consequences, as the profit margins are smaller. AEP stated its support
for the adoption of each of the following methods as a legitimate means to
prevent gaming: (1) requiring customers returning to the price to beat to
remain for one year; (2) prohibiting competitive REPs from making offers that
directly or indirectly seek to game short- term discrepancies; (3) seasonal
price to beat rate riders for returning customers; and (4) the opportunity
for an affiliated REP to require a deposit to cover a balanced billing subsidy.
Shell stated that TXU REP's initial comments on gaming missed the point,
which is that accurate pricing of default service is necessary whether or
not gaming occurs. Shell argued that if the price to beat is set artificially
below the real cost of power, competitors would never be able to offer lower
rates to induce customers to switch suppliers. While that result may serve
TXU REP's interest in maintaining its role as a monopoly provider, Shell commented,
it does not serve the legislative policy and purpose of SB 7.
Reliant pointed out that its proposal is slightly different from TXU REP's.
Reliant stated that small commercial customers with a peak demand of less
than or equal to 50 kW and all returning residential customers should be subject
to no requirements other than those in the proposed rule. However, there should
be a way to remove the incentive for aggregators and REPs to offer incentives
or inducements for customers to switch. Reliant and the Coalition recommended
that there be incentives to prohibit the REP and aggregator from serving as
switching agents for the customers whereby they could effectuate a switch
without further notice to the customer. The penalties, Reliant suggested should
include a mandatory repayment to the affiliated REP of all additional costs
as a result of improper gaming plus administrative penalties and the discretionary
revocation of REP and aggregator certificates. Further Reliant proposed that
affiliated REPs have the right to investigate when they believe gaming by
an aggregator or REP is occurring or has occurred.
TXU REP stated that residential and small commercial customers are unlikely
to engage in gaming of the price to beat rates and that the imposition of
seasonally adjusted prices on these customers is a solution for a problem
that does not exist. The Cities and Consumer Commenters agreed. Consumer Commenters
reiterated that residential customers practically cannot and do not game the
system, and gaming in other states has been done by large customers and REPs
who dump their customers.
TXU REP also proposed and supported another mechanism to minimize the risk
of system gaming without preventing customers who wish to return to the status
quo from doing so. TXU REP's alternative proposal stated that all non-residential
customers with a peak demand greater than 50 kW that return to the affiliated
REP on or after April 1 of any given year must agree to pay the net cost of
service for the period of May through October of that year. The affiliated
REP would track the amount of energy delivered to these customers, the price
these customers actually pay the affiliated REP and the affiliated REP's cost
to purchase energy for these customers (price in the balancing market). TXU
REP stated that this information would be used to calculate a running account
balance with these customers, if one of these customers switches away from
the affiliated REP before the account balance becomes zero, then the customer
must reimburse the affiliated REP for the account balance at the time of the
switch. TXU REP argued that this proposal should eliminate the incentive for
large customers to game the system and would allow other REPs to compete for
these customers by paying the customer's exit fee themselves.
Consumer Commenters agreed with TXU REP that the actual "gamers" should
be punished. While the Consumer Commenters agreed with TXU REP's proposal
they clarified that they wanted to ensure that small customers who might succumb
to inducement by REPs or aggregators should not be punished.
TNMP stated that absent a protective mechanism, a competing REP could undercut
the affiliated REP's higher summer seasonal price to beat and drain off the
affiliated REP's customers during the more lucrative summer season. TNMP further
noted that by simply holding its price constant, the competing REP could shed
those same customers back to the affiliated REP during the less lucrative
winter period, when the price to beat drops below the competing REP's price,
as dictated by the seasonal adjustment. TNMP proposed two mechanisms to address
the potential for gaming. First, TNMP stated that the proposed rule should
allow the affiliated REP to respond to the appearance of gaming by quickly
changing the seasonal differentiation in the factors without changing the
overall revenues received under the factors. TNMP argued that the affiliated
REP should necessarily be able to implement this type of adjustment to the
differential more quickly than the regular adjustments to the overall factors
in order to impact the gaming in the season it occurs. Secondly, TNMP argued
that the commission could lessen the problem in the first instance by using
three seasonal factors instead of two. TNMP suggested the following three
seasonal factors: December-March, April-July and August-November. TNMP concluded
that these three factors should provide a smaller differential change in each
factor because the summer peak months are divided and combined with more moderate
usage months which provides customers with less incentive to game the system.
Cities, Shell, ARM, OPC, and Consumer Commenters opposed use of a minimum
contract term. Shell stated that forcing customers to accept a minimum term
for statutory default service would discourage participation in the competitive
market and would be inconsistent with the customer choice initiatives in PURA.
Shell supported adjusting the fuel factor so that the price to beat would
reflect significant changes in the cost of power. ARM echoed Shell by stating
that allowing the affiliated REPs to tie up customers under annual contracts
would significantly undermine competition. ARM stated that under the utilities'
proposal of forcing returning price to beat customers to a one year term,
not only would the affiliated REPs have all the customers who have not chosen
another supplier at market opening, they would also be able to make returning
price to beat customers unavailable to competing REPs for a year. ARM stated
that a more preferable market based solution would be to incorporate seasonality
in the price to beat.
Cities, Consumer Commenters and OPC commented that they do not foresee
a propensity for residential and small commercial customers to game the system.
Cities stated that unless and until the commission determines a prevalence
of residential customers gaming the PTB for financial advantage during high
cost months, that any term limits the commission may devise should only apply
to industrial and commercial customers. OPC stated that the summer/winter
gaming problem is more likely to arise in the context of non-PTB large commercial/industrial
customers who have sophisticated metering and energy management strategies.
Consumer Commenters added that if returning to the price to beat because a
customer is dissatisfied with higher prices or poor service is "gaming" then
that is exactly what the Legislature intended. OPC argued that the five-year
offering of the price to beat by the affiliated REP was intended to provide
a long term safety net for small customers. ARM agreed with the these commenters
that it would be anti-competitive to require returning price to beat customers
to accept a minimum term contract as no other deregulated industry such as
banking or telecom has these requirements. Limiting customer's right to choose
in this manner is contrary to the purpose of SB 7, ARM argued.
The commission disagrees with those commenters suggesting various penalties
(i.e., minimum contract terms, seasonal rates applied only to returning to
customers, and other monetary penalties) to be applied to returning price
to beat customers as a means of preventing gaming. As discussed previously
in response to preamble Question 1 above, the commission is concerned that
imposition of such restrictions would discourage customers from ever leaving
their incumbent providers and thereby thwart development of a competitive
market. The commission seeks to discourage gaming of the price to beat by
either customers or REPs. One way to address gaming is through the use of
seasonal fuel factors. For reasons discussed previously in response to Question
1 above, the commission has concluded that use of seasonal fuel factors for
small commercial customers should be the only remedy for affiliated REPs who
are concerned about gaming. The commission agrees with those commenters suggesting
that REPs and aggregators be prohibited from serving as switching agents for
the customers whereby they could effectuate a switch without further notice
to the customer.
However, the commission notes that Substantive Rule §25.482 of this
title (relating to Termination of Contract) provides that customers who have
their contract terminated by their REP, or are abandoned by their REP, are
required to be notified that they can select an alternate REP or be switched
to the POLR. Furthermore, Substantive Rule §25.474 of this title (relating
to Selection or Change of Retail Electric Provider) outlines the procedures
for a REP to switch a customer to their service and addresses penalties for
unauthorized switches. As such, the commission does not believe that the opportunity
exists for REPs to serve as a switching agent for customers or to transfer
a large number of customers to the affiliated REP without the affiliated REP's
consent, unless the affiliated REP is serving as the POLR at the price to
beat.
The commission has revised subsection (j) of the rule to place explicit
prohibitions on non- affiliated REPs from providing incentives to encourage
customers to return to the PTB. The commission also agrees with Reliant that
affiliated REPs already possess the right to investigate gaming by aggregators
and REPs and, if necessary, to file a complaint before the commission to address
such problems. This should also reduce the potential for gaming.
Question 5: Should the commission further define
what showing should be required by an affiliated REP under subsection (g)(2)
to demonstrate that the affiliated REP will not be able to maintain its financial
integrity under the price to beat? If so, what standard should be used in
this determination?
AEP, SPS, Reliant, TXU REP, and Entergy REP commented that it is unnecessary
for the commission to define what showing should be required by an affiliated
REP under subsection (g)(2) to demonstrate that the affiliated REP will not
be able to maintain its financial integrity under the price to beat. TXU REP
and ARM commented that the definition of financial integrity has been well
established by prior commission orders and appellate court decisions and that
the commission can rely on these standards with respect to the issue of an
affiliated REP's financial integrity in relation to its ability to provide
service pursuant to the price to beat. TXU REP reasoned that it is very difficult
to predict now what the market will look like in the next few years, much
less what standards should be used to judge whether an affiliated REP's financial
integrity is jeopardized under any particular market conditions. This is an
assessment that will need to be made on a case-by-case basis, TXU REP reported,
relying on information that may potentially be competitively sensitive.
Entergy REP and TNMP commented that the financial integrity standard should
be a low one. TNMP urged that the standard for an adjustment to protect the
affiliated REP's financial integrity be set relatively low because PURA severely
limits the commission's ability to adjust the price to beat. If the threshold
for the adjustment is set too high, TNMP asserted that an affiliated REP will
be pushed to the brink of financial ruin before it can obtain an adjustment
and would then operate prospectively on that brink. TNMP argued that no commenters
offered a legal basis to require affiliated REPs disclose sensitive information.
More importantly, TNMP stated that the imposition of a strict and exacting
standard, while superficially pro-consumer, actually threatens long-term consumer
harm, because while the affiliated REP is losing money the consumer is insulated
from the market conditions.
Entergy REP stated that if the price to beat provider's financial integrity
is impaired because the price to beat is set too low, then barriers to entry
will be erected for prospective market entrants. Entergy REP commented that
the financial integrity test should balance the affiliated REP's interest
and the interest of fostering competition. AEP stated that affiliated REPs
should have the flexibility to demonstrate to the commission why their particular
facts and circumstances will result in their affiliate REP's inability to
maintain their financial integrity under the price to beat.
OPC and Consumer Commenters commented that the standards should be strict.
OPC stated that it is not necessary at this point to outline in detail the
procedures that should govern such a process. However, OPC stated that regardless
of when such a procedural rule is enacted, the standards and procedures for
granting such requests should be very strict. OPC stated that a financial
integrity criterion is meaningless unless the commission simultaneously reviews
the reasonableness and efficiency of the affiliated REP's costs. OPC reasoned
that because almost all of the affiliated REP's costs are likely to be payments
to other affiliated entities, the affiliated transaction standards should
be applied in these proceedings. For that reason, the proceedings will be
extensive and time consuming and should not be undertaken except in instances
of deep financial distress.
OPC suggested (and Consumer Commenters agreed) several criteria for proceedings
under proposed subsection (g)(2). The first suggestion is that the relevant
financial integrity test should hinge on the existence of negative cash flow,
taking into account reasonable and necessary expenses. The second criteria
is that the affiliated T&D utility should be required to justify its costs
whenever the affiliated REP makes an application under this section. This
would allow the commission to correct excessive delivery charges if that is
the cause of the REP's financial distress, OPC suggested. Finally, OPC suggested
that to the extent that the affiliated REP's access to capital is through
the holding company, the overall impact of the REP's financial distress upon
the holding company should be examined.
Consumer Commenters feared an affiliated REP may attempt to limit the financial
information available to the commission and parties' to review based on claims
that it is "competitively sensitive." Consumer Commenters stated that in California
the utilities' claims of financial hardship fly in the face of the substantial
profits earned by the utilities' generation affiliates during the same high
market period.
Reliant reiterated that it is unnecessary at this time for the commission
to set up objective standards for a showing of financial hardship. Reliant
disagreed with the suggestion of OPC and others that the impact of the affiliated
REPs financial distress on the holding company should be looked at when determining
whether the REP is experiencing financial distress. Reliant stated that this
should not be used when and if standards are adopted. Reliant claimed there
is no basis in either past regulation or general logic for this assertion.
Integrated utilities are independent entities; other entities are not required
to subsidize the utilities and the entire holding company is not required
to be in financial distress before the utility can receive a rate increase.
The commission concludes that the standard for an adjustment based on financial
integrity should be high. The commission agrees with TXU REP, ARM and others
that the definition of financial integrity has been established by prior commission
orders and appellate case law and therefore does not believe further definition
of this standard is necessary at this time.
Question 6: Can the registration agent provide
verification for small commercial customers similar to that described for
residential customers in subsection (l)(4)(C)(i)?
ERCOT stated that if ERCOT is designated as the registration agent, it
would be able to provide the commission with verification reports regarding
residential and small commercial customer migration to non-affiliated REPs.
AEP and OPC supported ERCOT as the registration agent. TNMP stated that the
registration agent should be able to provide the information for small commercial
customers. Entergy REP and SPS noted that ERCOT will not have the necessary
load/use data for non-ERCOT customers.
Reliant questioned whether ERCOT, as the registration agent, could differentiate
small commercial customers with peak demand below 20 kW. SPS stated that the
registration agent may be able to provide verification for small commercial
customers under 20 kW, but would not have the consumption data needed to verify
small commercial customers over 20 kW. ERCOT stated that it could differentiate
such small commercial customers.
Based on the comments received, the commission agrees with ERCOT and concludes
that no change to the rule to address this question is necessary.
§25.41(b)
Consumer Commenters commented that the provisions of subsection (b) should
be revised to reflect that the PTB is also intended to provide an immediate
rate decrease for small consumers and to assure consumers there will be a
price capped service option available for the first five years of the retail
market. Consumer Commenters contend that as proposed, subsection (b) only
focuses on competitors, and does not adequately reflect the protection aspect
of the price to beat.
The price to beat serves a dual purpose -- to provide a rate decrease for
residential and small commercial customers and to assure that these customers
will have a price capped service option available for the first five years
of the retail market. The commission believes that the rule as adopted properly
reflects both aspects of the price to beat.
§25.41(c)
EPE commented that the provisions of proposed subsection (c)(4) should
be modified to reflect the fact that EPE measures demand on a 30-minute interval.
As proposed, subsection (c)(4) measures demand only on a 15-minute interval.
The commission agrees and has amended the rule to permit demand measurement
on either 15 or 30-minute intervals.
EPE commented that proposed subsection (c)(5) excludes a part of the corresponding
PURA provision governing price to beat. Specifically, EPE refers to PURA §39.202(n)
which provides that "in a power region outside of ERCOT,
if customer choice is introduced before the requirements of Section 39.152(a)
are met
, an affiliated retail electric provider shall continue to offer
the price to beat to residential and small commercial customers, unless the
price is changed by the commission in accordance with this chapter, until
the later of 60 months after the date customer choice is introduced or the
requirements of Section 39.152(a) are met." (emphasis added). As proposed,
the definition of the price to beat period excludes this phrase.
The commission agrees with EPE on this point and has amended the definition
of "price to beat period" accordingly.
SPS and Entergy REP both commented on the definition of small commercial
customer in proposed subsection (c)(9). Both of these companies commented
that the definition of small customer in the rule should be defined as "a
commercial customer having a peak demand of 1,000 kilowatts or less." As proposed,
the definition uses the term "non-residential retail customer".
The commission disagrees with SPS and Entergy REP. In the absence of a
clear method to distinguish whether a customer is "commercial" or "industrial",
the commission concludes that the intent of PURA §39.202(o) was to provide
the price to beat to any customer with a peak demand of 1,000 kW or less,
regardless of how that customer may otherwise be classified under a particular
utility's tariff.
Cities expressed concern about non-roadway lighting and asked that the
price to beat apply to non-roadway lighting. City of Dallas also expressed
concerns about non-roadway outdoor security lighting and the fact that while
street lighting will remain regulated, the utilities have been contacting
their customers and taking a very narrow view of what regulated lighting is.
City of Dallas proposed either to keep non-roadway lighting on a regulated
rate or the price to beat and expand the definition of street lighting.
The commission concludes that any non-metered point of delivery with peak
demand less than 1,000 kW should be considered a small commercial customer
and therefore eligible for the price to beat. The commission has revised the
definition of small commercial customer to incorporate this change and believes
that this change addresses the Cities' concerns about lighting customers.
§25.41(d)
ARM stated that this section should be clarified to state that the 6.0%
decrease does not apply to fuel and purchased power, but that the discount
applies only after the entire cost of fuel and purchased power is backed out
of bundled rates. TNMP expressed similar concerns. OPC argued that a calculation
of the 6.0% rate reduction only upon the base rate portion of customer bills
is not supported by any reasonable interpretation of SB 7. OPC quoted PURA §39.202(a),
stating that its use of the word "rates" refers to any "compensation, tariff,
charge, fare, toll, rental, or classification that is directly or indirectly
demanded, observed, charged, or collected by a public utility" as defined
in PURA §11.003. OPC argued that the rates in effect on January 1, 1999,
must include fuel charges. OPC stated that the calculation change proposed
by ARM would reduce the ratepayer benefits of SB 7.
The commission disagrees with ARM and agrees with OPC. PURA §39.202(a)
provides for the 6.0% discount to be applied to the average bundled rate in
effect on January 1, 1999, which included a fuel factor. As specified in subsection
(f)(3)(D)(iii), the fuel factors to be used at the beginning of the price
to beat period will be the fuel factor in effect on January 1, 1999, reduced
by 6.0%, plus the difference between the fuel factors established under subsection
(f)(3)(A), (B) and (C) and the fuel factor in effect on January 1, 1999. For
purposes of clarity, the reference in proposed subsection (d) to subsection
(f)(3)(A) has been changed to reference subsection (f)(3)(D).
§25.41(e)
TXU REP stated that there is no need to include additional language regarding
refusal of service since Substantive Rule §25.477 of this title (relating
to Refusal of Electric Service) of the proposed customer protection rules
already addresses this subject. Entergy REP concurs with TXU REP.
The commission agrees with TXU REP and Entergy REP and has referred to §25.477
in subsection (e) to clarify the commission's intent.
TXU REP stated that with regard to term of service requirements of subsection
(e)(1) and (2), TXU REP supports the use of a term of service option for commercial
customers with a peak demand greater than 50 kW in order to prevent gaming.
TXU REP stated that the language relating to refusal of service should be
modified to allow an affiliated REP to refuse the provision of services to
a small commercial customer with a peak demand of greater than 50 kW who was
served by the affiliated REP within the prior 15 months, if the applicant
is unwilling to accept either a one-year term of service with the affiliated
REP or a price to beat rate under a Seasonal Adjustment Mechanism rider. Entergy
REP stated that the rule should be modified to require a minimum one year
or some other form of anti-gaming measure for returning PTB customers in order
to protect the market from the harm created by competitive suppliers dumping
customers back onto PTB service during high market cost months.
Reliant suggested that in order to address the gaming problem, aggregators
and REPs, and their agents, be prohibited from offering incentives for customers
to switch to the affiliated REP, and prohibited from serving as switching
agents for the customers, whereby the agent can effectuate switching without
further notice to customers. Switches that are found to have been the result
of gaming would be reversed back to the date of the switch for settlement
purposes. Further, Reliant proposed that affiliated REPs should have the right
to initiate an investigation when they believe gaming by an aggregator or
REP is occurring or has occurred.
ARM expressed support for the provisions of subsections (e)(1) and (2)(B)
that prohibit affiliated REPs from requiring service agreements for PTB customers
and from providing inducements to encourage PTB customers to agree to a term
of service.
For reasons discussed in response to preamble Question 4 above, the commission
disagrees with those commenters suggesting the addition of a minimum term
contract or different seasonal rates for customers returning to the affiliated
REP. The commission concludes that such provisions would very likely discourage
customers from leaving the affiliated REP in the first place and thereby unnecessarily
thwart the development of the competitive market. The commission has addressed
the allowed measures to address the issue of gaming in its discussion of preamble
Question 4 above.
Reliant suggested language to clarify that the customer is eligible for
the price to beat on a going-forward basis and that the affiliated REP would
not be required to restate the past 12 months bill. Entergy REP and TNMP supported
this proposal.
The commission agrees with Reliant and has made their recommended language
change to subsection (e)(2)(A).
TXU REP argued that language referring to the prohibition of "inducements"
to encourage customers to agree to a term of service should be eliminated
because the word "inducements" is too vague and would expose the affiliated
REP to an undue risk of litigation.
ARM supported the proposed language in the rule and noted that the term
inducements is no more vague than the term incentives included in the statute.
The commission agrees with ARM concerns and declines to make TXU REP's
requested change.
TXU REP proposed that a new section should be added to the proposed rule
in order to accommodate customer choice in choosing their contracted demand
level when they order new service or when they add load at an existing service
location. Entergy REP agreed with TXU REP that commercial customers with contract
demand in excess of 1,000 kW should be allowed to enter into delivery contracts
at competitive prices. However, Entergy REP did not believe that a new subsection
is necessary, referencing subsection §25.41(e)(2)(A) of the proposed
rule. ARM argued that this suggestion would open the door to all sorts of
abuses and should be rejected. ARM stated that it would permit a customer
and an affiliated REP to get around SB 7 provisions prohibiting affiliated
REPs from charging anything but the price to beat to PTB customers in their
service area and that it would be very difficult for the commission to monitor
such abuses.
The commission agrees with ARM and Entergy REP that the proposed language
adequately defines the eligibility of small commercial customers and is consistent
with PURA §39.202(o), which defines small commercial customers through
their actual peak demand, not their contracted demand. No change to this section
has been made.
Entergy REP commented that references to the calendar year 2001, should
be revised to the 12 consecutive months ending September 30, 2001, in order
to alleviate doubt as to what customers are eligible for the PTB. TNMP concurred
with Entergy REP.
The commission agrees with Entergy REP and TNMP that utilizing the 12 months
ending September 30, 2001, will provide necessary advance notice to existing
customers as to whether or not they are eligible for the price to beat. The
commission has revised the rule to reflect this recommendation.
Entergy REP stated that the rule needed to be modified in order to prevent
account-splitting abuse by customers in order to qualify for the price to
beat. Entergy REP suggested that a customer who is ineligible for the PTB
might split his account into several smaller sub-accounts in order to become
eligible for the PTB.
The commission does not foresee account splitting in order to qualify for
the price to beat being a major problem because customers larger than 1000
kW of demand should have access to more attractive rates than those provided
under the price to beat. Under such circumstances, these customers would not
logically attempt to split their accounts in order to qualify for the price
to beat. Therefore, the commission declines to alter the proposed rule as
suggested by Entergy REP. However, it is the commission's intention that the
term "customer" refers to a metered point of delivery. Therefore, if there
are several facilities behind a single meter, it would be inappropriate for
each of the facilities to be considered a separate customer. However, if there
are separately metered facilities on the same site, each facility would properly
be considered a price to beat customer. The commission has modified the definition
of small commercial customer in subsection (c)(9) accordingly.
§25.41(f)(1)
TXU REP opposed the elimination of rates that provide discounts and incentives
for customers who make permanent changes to their consumption patterns, that
develop new technologies, or that promote growth in economically depressed
areas. AEP supported TXU REP's proposed revision. ARM opposed this position,
stating that the Legislature intended the PTB to be a "plain, vanilla rate",
not a competitive alternative. ARM commented that the price to beat rule should
also include a provision explicitly prohibiting affiliated REPs from selling
or marketing any "special" and/or "competitive-like" kinds of electricity
services to PTB customers under the PTB, unless specifically required by commission
rule. ARM proposed that the words "green" and "renewable" be included in the
list of rates and riders for which PTB does not apply. Entergy REP and TLSC
stated that the commission should clarify the rule to insure that low- income
electric customers will continue to receive rate reductions under SB 7.
TXU REP suggested that new rates be introduced by a utility between January
1, 1999 and December 31, 2001 supporting the SB 7 goal for renewable power
be eligible for PTB treatment. ARM opposes this position, stating that the
Legislature intended the PTB to be a "plain, vanilla rate", not a competitive
alternative.
The commission finds that, in order to be consistent with PURA §39.202(a)
that the price to beat is to be based on bundled rates in effect on January
1, 1999, the affiliated REP should be required to offer a price to beat rate
for every rate, tariff, and service option in effect on that date. However,
the commission agrees with ARM that it is inappropriate to establish a PTB
rate for new tariff options introduced after January 1, 1999, as PURA §39.202(a)
specifically requires that the price to beat be based on bundled rates in
effect on that date.
The commission agrees with ARM that it is inappropriate to allow affiliated
REPs to offer "green" or "renewable" service offerings in their service territory,
or to market price to beat service as a "green" or "renewable" product, unless
such rates were in effect on January 1, 1999.
The commission does recognize that it may not be appropriate to develop
a price to beat for certain rates, such as discounted rates or marginal cost
based rates. As such, an electric utility, on behalf of its future affiliated
REP should file tariffs for its price to beat rates within 60 days after the
effective date of this rule. At the time of this filing, the utility may request
that a price to beat not be developed for certain rates in effect on January
1, 1999.
Subsections (d)(2), (f)(1)(A), (f)(1)(B), and (f)(1)(C) of the rule have
been modified accordingly.
TNMP stated that rather than applying the 6.0% rate reduction to each component
of the rates, the rule should allow the price to beat to be calculated based
on an average 6.0% decrease across the class. TNMP argued that this proposal
complies with PURA and offers protection against the negative impacts that
result from the skewed headroom between high usage and low usage customers.
Consumer Commenters opposed the averaging of the 6.0% PTB decrease.
The commission concurs with Consumer Commenters. If the 6.0% decrease were
averaged across all customers, there would be winners and losers. The commission
concludes that it is appropriate to reduce base rates for each retail customer
by 6.0% and as such, declines to change the rule as suggested by TNMP.
§25.41(f)(2) and (3)
Entergy REP recommended that the 60-day period be changed to 30 days because
a 60-day average is too long to reflect current movements in the market and
proposed changes to subsection (g)(1)(A) and (B) to shorten the time requirement
from 60 days to 30-calendar days, and to use forward looking natural gas settlement
prices for each season.
The Coalition agreed with AEP that the 60-day period is too long and would
prevent any REP from being able to adequately hedge its purchases.
The commission concludes that it is appropriate to alter the period over
which the average 12 month forward NMYEX gas price is averaged from a 60-day
average to a ten-day average. Upon review of historical gas price data, the
commission believes that the use of a 60-day average may result in too much
of a lag from actual market prices. Use of a ten-day average should appropriately
capture true trends in gas prices, while allowing adjustments to the fuel
factor to better reflect changing market conditions and assist REPs in hedging
their purchases.
Entergy REP proposed changes to subsection (f)(3)(D)(iii) as it determined
that there should be no mandatory reduction of the fuel factor in effect on
January 1, 1999, for Entergy REP. Entergy REP also proposed a new subsection
(f)(3)(D)(iv) that states that "the fuel factors for affiliate electric utilities
whose base rates were reduced by more than 12% as the result of a final order
issued by the commission after October 1, 1998, to be used at the beginning
of the price to beat period shall be the fuel factor in effect on January
1, 1999, plus the difference between the fuel factors established pursuant
to subparagraphs (A), (B) and (C) of this paragraph and the fuel factor in
effect on January 1, 1999."
The commission agrees with Entergy REP and adds new subsection (f)(3)(D)(iv)
to clarify that the fuel factors to be used at the beginning of the price
to beat period for a utility whose base rates were reduced by more than 12%
shall be the updated fuel factor established pursuant to subsection (f)(3)(D).
The commission has also changed the incorrect reference in (f)(3)(D)(iii)
from subparagraph (A), (B), and (C) to subparagraph (D).
Entergy REP also proposed a new subsection (f)(3)(E) that would state that
the seasonal fuel factors established pursuant to subsection (f)(3) shall
be known as the baseline fuel factors. In addition, Entergy REP raised several
policy issues that it believed needed to be addressed and suggested that one
or more technical conferences be conducted to address these issues and to
gain consensus on these policy questions. Entergy REP's list of policy questions/issues
is as follows:
1. What generation resources should be used to estimate the fuel factor?
2. Is there a "cut-off" date prior to the rate year to determine which
utility owned generation resources are to be used in determining the fuel
factor, what is that cut off date?
3. Should the date be unique for each utility?
4. What issues of fairness among the affiliate REPs are implicated if the
date is different for each utility?
5. What estimate of sales should be used in the development of a fuel factor?
6. If the fuel factor is determined based on the estimate of total system
sales, how is the load shape for non-price to beat sales adjusted out of the
price to beat fuel factors?
7. In the case of those utilities that participate in a FERC-approved system
agreement to allocate generation capacity and energy costs, are these resources
to be included in determining eligible fuel expenses? If so, how?
8. If FERC approves withdrawal of a utility from participation in a FERC-approved
system agreement effective prior to the rate year, how should the fuel factors
be computed?
9. Are eligible non-generation related revenues/expenses to be considered?
If so, how?
10. Must a utility seek a good cause exception for treatment of eligible
non-generation related revenues/expenses different than the treatment of these
revenues/expenses in current fuel factors?
11. How does FERC's order No. 2000 affect treatment of these revenues/expenses
in the computation of fuel factors?
TXU REP also noted that for Southwestern Electric Service Company (SESCO),
as a non- generating investor-owned utility, it had no fuel factor in January
1999. As such, TXU REP proposed that SESCO's purchased cost recovery factor
(PCRF) in effect on January 1, 1999 should be used to calculate SESCO's initial
price to beat fuel factor.
The commission finds, that as stated in subsection (f)(3)(B), the proper
reading of PURA §39.202(b) is that the final fuel factor should be set
in the traditional manner as outlined by the current fuel rule. While the
commission recognizes that the inclusion of a fuel factor based on historical
integrated utility fuel costs as part of the price to beat appears inconsistent
with the market structure under SB 7, where REPs are prohibited from owning
generation, the commission finds that the price to beat was intended to be
calculated from the each utility's regulated rate in effect on January 1,
1999, discounted by 6.0% and updated for a final fuel factor. Utility-specific
issues are to be addressed in the individual fuel factor cases, within the
confines of this finding.
The commission agrees with TXU REP that the proper treatment of the fuel
cost factor for SESCO, as a non-generating utility with no fuel factor, is
that the PCRF in effect on January 1, 1999 should be used for the price to
beat fuel factor. To the extent that SESCO's current purchased power contract
expires during the price to beat period, TXU REP should at that time request
an adjustment to SESCO's price to beat in order to account for the new contract.
The commission also clarifies that any previous commission orders that
address how a utility's price to beat fuel factor is to be set should be given
effect in the utility's fuel factor case.
§25.41(g)
Entergy REP recommended that subsection (g)(1) be modified so that an affiliate
REP may request up to four changes in the seasonal fuel factors in a calendar
year. Entergy REP stated that this approach comports with PURA §39.202(l)
because §39.202(l) contemplates a single fuel factor and since the commission
has established two seasonal fuel factors, then it is reasonable to allow
two separate adjustments to each seasonal fuel factor.
The commission disagrees that that the statutory allowance of two changes
per year can be read to allow more than two changes per year. No change has
been made. See comments on preamble Question 1 for the commission's discussion
of seasonality.
Cities proposed a change to subsection (g)(1)(A) to strike January 1, 2002,
and replace it with September 15, 2001.
The commission has made revisions to subsection (g)(1)(A) to clarify how
the methodology for calculating an adjustment to the fuel factor should work.
While the commission declines to adopt Cities' proposed change, the commission
believes that the changes made in this subsection should address the concerns
raised by Cities.
AEP commented that the procedural schedule referenced in subsection (g)(1)(D)
should be revised to shorten the length of time it takes to obtain a final
order on fuel factor revision applications. AEP supported TNMP's proposal
that the procedural schedule be revised to require the issuance of an order
within 20 days after a petition is filed if no hearing is requested and 45
days after a petition is filed if a hearing is requested within 15 days of
the petition.
TNMP suggested changes to subsection (g)(1)(D) as well. TNMP proposed that
in addition to the adjustment specified in the proposed rule, additional language
be added that would allow the REP to recover the disparity during the period
before the adjustment is implemented. TNMP contends this adjustment is necessary
because the regulatory framework provides neither a mechanism for recovering
the loss if the affiliated REP's costs rise, nor a policy basis for requiring
affiliated REPs to absorb this loss. TNMP also requested adjustments to the
proposed procedural process for adjustments to the fuel factor. TNMP stated
that these adjustments are necessary because the current fuel rule would subject
affiliated REPs to a 90-day delay and could cause additional losses of millions
of dollars. TNMP requested that the procedural schedule be modified to require
that an order be issued within 20 days after the petition is filed, if no
hearing is requested within 15 days of the petition and within 45 days after
the petition is filed if a hearing is requested within 15 days of the petition.
If a hearing is requested, TNMP recommended, the hearing should be held no
earlier than the first business day after the 25th day after the application
is filed.
The commission finds that, for the purposes of an adjustment to the fuel
factor resulting from a change in the NYMEX gas price index, TNMP's proposed
procedural schedule is appropriate. For adjustments to the fuel factor under
subsection (g)(1)(E) based on changes in headroom resulting from significant
changes in the price of purchased energy, the commission will issue a final
order within 60 days after an application is filed under this subsection.
The commission disagrees with TNMP that an affiliated REP is entitled to recover
any loss incurred during the process of evaluating a requested change as PURA
does not contemplate any reconciliation of the price to beat and market prices,
except during the 2004 true-up.
Adjustments to the price to beat based on financial integrity have the
potential to be lengthy, contested cases. The commission therefore declines
at this time to establish in the rule any procedural deadlines for such proceedings.
The procedural schedule for a change in the price to beat due to financial
integrity is more appropriately addressed on a case-by-case basis.
TXU REP proposed to eliminate subsection (g)(1)(E) that restricts the dates
when the fuel adjustment can be filed. TNMP suggested that the 45-day requirement
of subsection (g)(1)(E) be eliminated or that this requirement be changed
to 120 days to allow the affiliated REP to delay an available adjustment to
preserve for itself the option of seeking an adjustment at a subsequent time
of the year.
The commission has revised subsection (g)(1)(E) of the rule in a manner
that should address TXU REP's and TNMP's concerns.
§25.41(h)
TXU REP suggested revising subsections (h)(1) and (h)(2) to include language
that an affiliated REP may not offer rates other than the price to beat rates
to residential and small commercial customers in its "service area," at least
not until the commission determines that "40% or more of the electric power
consumed by residential customers within the affiliated electric utility's
certificated service area before the onset of customer choice is committed
to be served by nonaffiliated retail electric providers."
Entergy REP stated that an interpretation of §25.41(h)(1) would encompass
all affiliated REPs in all service territories so that an affiliated REP would
have to offer the price to beat wherever it had customers and proposed adding
the following language to the above section and also subsection (h)(2): "...in
its affiliated transmission and distribution utility's certificated service
territory...." TNMP in its reply comments supported Entergy REP's clarification
in the above subsection. In addition, Entergy REP agreed with TXU REP's proposal
for §25.41(h).
The commission agrees with TXU REP and Entergy REP and has revised this
subsection of the rule accordingly.
Entergy REP in its reply comments proposed adding the following language
at the end of subsection (h)(1): "except as provided by the rate reduction
program of the commission rules relating to the System Benefit Fund."
The commission agrees with Entergy REP and has made the corresponding change
in subsection (h)(1).
ARM commented that the exception under subsection (h)(3) be strictly construed
and reviewed by the commission to preclude misuse by the affiliated REPs;
also, the commission should require a filing by the affiliated REPs to show
that the customers are above 1000 kW, are commonly owned, or are of the same
franchisor and could approve such filing within 30 days if there are no objections.
ARM proposed that the subsection be revised accordingly. Entergy REP in its
reply suggested rejecting ARM's proposal regarding aggregation exception because
it is not authorized under PURA §39.202(f). Reliant in its reply disagreed
with ARM regarding the need to file proof that aggregated small commercial
loads charged non-PTB rates are eligible for such rates because it would place
unnecessary burden on the affiliated REPs. TXU REP in its reply opposed ARM's
proposal to prove eligibility of the aggregated load to receive rates other
than the price to beat because it exceeds the authority allowed under PURA
and the commission already has authority to investigate any complaints about
improper activity.
The commission agrees with ARM and will require the affiliated REP to make
an informational filing for customers who qualify for this exemption. The
commission has amended subsection (l)(3) to reflect this requirement.
§25.41(i)
TXU REP commented that the proposed methodology cannot be implemented and
that both the threshold target concept and specific language would have to
be altered to be workable. The company stated that the idea of establishing
a consumption baseline is a reasonable one and that it should be used as a
means against which to calculate the 40% loss of load, and not as a target
threshold, which cannot be established by June 1, 2001. TXU REP also stated
that both residential and small commercial consumption should be addressed
in the same manner; and that the following subsections should be renamed:
(i) - "Calculation of baseline consumption for calendar year 2000," (i)(1)
- "Calculation of baseline consumption," (A) and (B) - "Residential baseline"
and "Small commercial baseline." Additionally, language about the 40% target
should be deleted from these two subparagraphs, and added to subsections (h)(1)
and (h)(2); and the "Small commercial baseline" section should be revised
to require establishment of a small commercial customer baseline served in
2000, with no subtractions for ineligible customers, and the actual 40% target
should be calculated after competition begins. TXU REP also noted a problem
in subsection (i)(1)(B), in which 40% of the aggregated load from 2000 consumption
of small commercial class is deducted and not 100% as required by PURA; however,
no changes are needed as other proposed changes would correct this one. If
not, TXU REP and Reliant proposed to delete "times 40%" in subsection (i)(1)(B).
TXU REP commented that dividing total consumption by one-twelfth of the
number of bills does not produce an accurate calculation of the number of
customers because each customer may receive more than one bill. A more accurate
method to determine the average number of customers would be to count customers
once each month for twelve months and then calculate the average over twelve
months. TXU REP suggested modifying subsection (i)(2)(A)(ii) to reflect the
above comments. Reliant in its reply agreed with TXU REP that the consumption
threshold target cannot be calculated with certainty on June 1, 2001, and
supported the proposal to establish a consumption baseline and changes to
subsection (h).
In its reply, Entergy REP agreed with TXU REP regarding computation of
average consumption and opposed using the number of bills in the computation.
Entergy REP also opposed Consumer Commenters' method of counting switches,
partly because some customers may be dropped to the POLR simply because their
REP decides to leave the state; therefore all switches should be counted toward
the threshold target.
The commission agrees with TXU REP and Entergy REP that it is more appropriate
to use number of customers in the calculation of average usage as opposed
to one-twelfth of the number of bills due to re-billings, etc. The commission
also agrees with TXU REP and Reliant that there is a double application of
the 40% in subsection (i)(1)(B) and corrects that subparagraph. The commission
also recognizes TXU REP's concern regarding the establishment of target thresholds
by June 1, 2001 given the uncertainty about what commonly-owned franchisee
aggregated load may qualify and pursue an exemption under the rule. As such,
the commission moves the initial filing date from June 2001 to December 2001
and requires updates to the small commercial threshold, as load is deemed
eligible for the exemption.
TXU REP, SPS, TNMP in its reply, and Reliant opposed the exclusion of customers
served by POLR from the target calculation and stated that the concern that
an affiliated REP may terminate customers just to meet the 40% loss is unsubstantiated
because the customer protection rules have detailed procedures on how terminations
are to be done. Additionally, TXU REP stated that if the POLR customers are
not to be counted because of an assumption that those customers have not exercised
their market choice, this may not be accurate because some customers could
voluntarily choose POLR or be dropped to POLR after having switched to a non-affiliated
REP. TXU REP also argued that even if the affiliated REP drops a customer
to the POLR, this is based on the same concept of choice embodied in SB 7,
because this customer "chose" not to pay their bill. Also, TXU REP and Entergy
REP stated that the law did not provide for this exclusion because it specified
40% or more served by "non-affiliated" REPs; however, if the POLR is the affiliated
REP, then the customers should still count because the affiliated REP is not
a POLR by choice.
Consumer Commenters stated that POLR customers should not count toward
calculating the threshold. Consumer Commenters further noted that the commission
should ensure that those customers who switch to the non-affiliated REP and
then switch back to the affiliated REP are not counted since the threshold
number should represent a point in time and not a cumulative number of switches.
In its reply, ARM stated that in spite of opposition by Reliant and other
utilities, §25.41(i) should be adopted because gaming could still go
on, only those customers who choose a provider should be counted, and the
POLR is not a competitive provider. ARM opposes Reliant's proposal to establish
a process for approving the affiliated REPs' target threshold filings; instead
current procedural rules should apply. If a different timeline is adopted,
then there should be sufficient time for a contested hearing. ARM also disagrees
with the Reliant's suggestion to require a minimum term for small commercial
customers on the PTB.
In their replies, Shell and OPC argued that the utilities' arguments for
the 40% target calculation to include POLR customers should be rejected because
those customers did not exercise choice regarding their provider.
The commission rejects utilities' arguments regarding counting customers
dropped to the POLR and will not count them as "switches." The rationale for
creating the POLR was to have an electric provider for those customers who
may have difficulty exercising choice in the competitive market. Therefore,
dropping customers to the POLR should not be considered a sign of a well functioning
competitive market. Additionally, the commission agrees with Consumer Commenters
that the threshold number is a snapshot in time and not a cumulative number
of switches. No change in the language has been made. The commission finds
that the current procedural rules should apply to the process of approving
affiliated REPs' target threshold filings.
OPC proposed to revise §25.41(i)(2)(A) to say: "The amount of electric
power consumed by residential customers
served
by non-affiliated REPs shall equal...."
The commission agrees and has made the requested change.
Reliant recommended that the commission require filings pursuant to §25.41(i)(2)
be made jointly by the transmission and distribution utility (TDU) and the
affiliated REP.
The commission finds that PURA explicitly requires the TDU to make filings
to show that its affiliated REP has met the threshold. The TDU will have meter
data for all customers, and will also know who the customers' REPs are. The
commission therefore declines to adopt Reliant's suggestion.
Entergy REP asked for a clarification regarding §25.41(i)(1)(B) because
PURA implies that the variable component in this subsection (i.e., the aggregated
load served by the affiliated REP that complies with the requirements of (h)(3))
is to be counted prior to competition, thus removing it from the equation.
Entergy REP also proposed deleting "times 40%" from subsection (i)(1)(B).
ARM commented that the affiliated REP should be required to file information
about customers and load that is deemed to qualify for the aggregated load
exemption, as such an exemption is susceptible to gaming by the affiliated
REP.
As stated above, the commission agrees with the concerns about the calculation
of the small commercial threshold and has (1) moved the filing of the initial
calculation to the end of 2001; and (2) required updates to the small commercial
threshold calculation as load qualifies for the exemption and is served by
the affiliated REP at a rate other than the price to beat rates. The commission
also agrees with ARM that the affiliated REP should make an informational
filing with the commission specifying the customer's name, premise identifications,
size of customer's load, and how the customers qualify for the exemption.
The affiliated REP may file such information under confidential seal, however,
all certified REPs will be deemed to have standing to examine these filings.
This section of the rule has been modified accordingly.
Entergy REP suggested changes to specify that a REP can not offer incentives
to its customers to switch and can not promote competitors' interests or exchange
customers with other REPs. Consumer Commenters went further to suggest that
there be a prohibition against an affiliated REP offering any incentive or
encouragement to competitors to get customers to switch to a nonaffiliated
REP, in order to reach the 40% threshold sooner.
Consumer Commenters supported disclosure of the PTB. TXU REP, however,
objected to the disclosure and offered the following two alternatives: (1)
delete any language about disclosing the PTB when offering a higher price
service; (2) only state the existence of a PTB when offering a higher priced
service. TXU REP's based its objection on the requirement being "burdensome,"
because it would require printing multiple versions of customer education
materials in order to include the specific price to beat rates for which particular
customers would be eligible. Also, TXU REP felt it would be unnecessary because
it might be as much as 36 months before some affiliated REPs could charge
any rates other than the price to beat.
The commission disagrees with TXU REP's assumption that these disclosure
requirements are burdensome. The REP will be required to provide an electricity
facts label and other documents for every rate it offers; therefore, the commission
determines that it will not be burdensome for the affiliated REP to add an
additional column indicating the price to beat and a statement informing the
customer that they are eligible for another rate. The commission also disagrees
with TXU REP's proposal to state only the existence of the price to beat because
not all customers are aware of the price to beat for one reason or another.
For example, a customer moving from out of state would be unaware of the price
to beat and may believe they have no choice. Therefore, the commission concludes
that the language shall remain unchanged.
Reliant recommended that filings under subsections (i) and (l)(2) regarding
power consumption threshold targets be made jointly by the transmission and
distribution utility and the affiliated REP. In addition, Reliant recommended
that a process for approving such filings under subsection (l) be established;
specifically, that commission staff's review, recommendation and final approval
be achieved within 60 days of the filing.
The commission finds that the statute specifies that the distribution utility
make the filings; there is no need for the REP to be involved.
TXU REP objected to subsection (l)(2), which requires a warning filing
when a 35% load loss has occurred. It believes that this requirement is burdensome,
unnecessary and not authorized by SB 7. TXU REP suggested that the commission
utilize reports produced by ERCOT to track the level of switching. Reliant
agrees that this warning requirement is not necessary.
The commission disagrees with TXU REP and Reliant and notes that the commission
only has 30 days to accept or reject this filing. The 35% filing is merely
a informational report that an affiliated REP is approaching the 40% target.
Entergy REP stated that because ERCOT would not have load/use data on non-ERCOT
customers, verification under subsection (l)(4)(C) would be difficult and
costly.
The commission notes that the ERCOT ISO will be acting as the registration
agent for all utilities in the state of Texas, and as such, should be able
to provide information as to how many and which customers have switched to
an alternate provider. Subsection (l)(4)(C) details certain other requirements
for small commercial customers in excess of 20 kW that will be needed to verify
an affiliated REP's claim that they have reached the 40% load loss threshold.
No report from ERCOT is required under the section. The commission declines
to modify the rule.
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 (PURA), Texas Utilities Code Annotated §14.002 (Vernon 1998, Supplement
2001), 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 §39.202 which establishes the price to beat obligation
for affiliated retail electric providers.
Cross Reference to Statutes: PURA §§14.002, 39.152, 39.202, 39.262,
and 39.406.
§25.41.Price to Beat.
(a)
Applicability. This section applies to all affiliated retail
electric providers (REPs) and transmission and distribution utilities, except
river authorities. 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)
Purpose. The purpose of this section is to promote the
competitiveness of the retail electric market through the establishment of
the price to beat that affiliated REPs must offer to retail customers beginning
on January 1, 2002 pursuant to PURA §39.202.
(c)
Definitions. The following words and terms, when used in
this section, shall have the following meanings, unless the context indicates
otherwise:
(1)
Affiliated electric utility--The electric utility from
which an affiliated REP was unbundled in accordance with PURA §39.051.
(2)
Competitive retailer--A REP or a municipally owned utility
or distribution cooperative that offers customer choice in the restructured
competitive electric power market or any other entity authorized to sell electric
power and energy at retail in Texas.
(3)
Headroom--The difference between the average price to beat
(in cents per kilowatt hour (kWh)) and the sum of the average non-bypassable
charges or credits approved by the commission in a proceeding pursuant to
PURA §39.201, or PURA Subchapter G (in cents per kWh) and the representative
power price (in cents per kWh). Headroom may be a positive or negative number.
A separate headroom number shall be calculated for the typical residential
customer and the typical small commercial customer. The calculation for the
typical residential customer shall assume 1,000 kWh per month in usage. The
calculation of the typical small commercial customer shall assumer 35 kilowatts
(kW) of demand and 15,000 kWh per month in usage.
(4)
Nonaffiliated REP--Any competitive retailer conducting
business in a transmission and distribution utility's (TDU's) certificated
service territory that is not affiliated with that TDU.
(5)
Peak demand--The highest 15-minute or 30-minute demand
recorded during a 12- month period.
(6)
Price to beat period--The price to beat period shall be
from January 1, 2002 to January 1, 2007. In a power region outside the Electric
Reliability Council of Texas (ERCOT) if customer choice is introduced before
the date the commission certifies the power region pursuant to PURA §39.152(a)
are met, the price to beat period continues, unless changed by the commission
in accordance with PURA Chapter 39, until the later of 60 months after the
date customer choice is introduced in the power region or the date the commission
certifies the power region as a qualified power region.
(7)
Provider of last resort (POLR)--As defined in §25.43
of this title (relating to Provider of Last Resort).
(8)
Registration agent--As defined in §25.454 of this
title (relating to Rate Reduction Programs).
(9)
Representative power price--The simple average of the results
of:
(A)
a request for proposals (RFP) for full-requirements service
of 10% of price to beat load for a duration of three years expressed in cents
per kWh; and
(B)
the price resulting from the capacity auctions required
by PURA §25.381 of this title (relating to Capacity Auctions) for baseload
capacity entitlements expressed in cents per kWh. The calculation of the price
resulting from the capacity auctions shall assume dispatch of 100% of the
entitlement and shall use the most recent auction of a 12-month forward strip
of entitlements, or the most recent aggregated forward 12 months of entitlements.
(10)
Residential customer--Retail customers classified as residential
by the applicable transmission and distribution utility tariff or, in the
absence of classification under a residential rate class, those retail customers
that are primarily end users consuming electricity for personal, family or
household purposes and who are not resellers of electricity.
(11)
Small commercial customer--A non-residential retail customer
having a peak demand of 1,000 kilowatts (kW) or less. For purposes of this
section, the term small commercial customer refers to a metered point of delivery.
Additionally, any non-metered point of delivery with peak demand of less than
1,000 kW shall also be considered a small commercial customer.
(12)
Transmission and distribution utility--As defined in §25.5
of this title (relating to Definitions), except for purposes of this section,
this term does not include a river authority.
(d)
Price to beat offer.
(1)
Beginning with the first billing cycle of the price to
beat period and continuing through the last billing cycle of the price to
beat period, an affiliated REP shall make available to residential and small
commercial customers of its affiliated transmission and distribution utility
rates that, subject to the exception listed in subsection (f)(2)(A) of this
section, on a bundled basis, are 6.0% less than the affiliated electric utility's
corresponding average residential and small commercial rates that were in
effect on January 1, 1999, adjusted to reflect the fuel factor determined
in accordance with subsection (f)(3)(D) of this section and adjusted for any
base rate reduction as stipulated to by an electric utility in a proceeding
for which a final order had not been issued by January 1, 1999.
(2)
Unless specifically required by commission rule, an affiliated
REP may only sell electricity to price to beat customers labeled or marketed
as "green," "renewable," "interruptible," "experimental," "time of use," "curtailable,"
or "real time," if and only if such a tariff option existed on January 1,
1999 and only for service under the price to beat rate that was developed
from that tariff.
(e)
Eligibility for the price to beat. The following criteria
shall be used in determining eligibility for the price to beat:
(1)
Residential customers. All current and future residential
customers, as defined by this section, shall be eligible for the price to
beat rate(s) for which they meet the eligibility criteria in the applicable
price to beat tariffs for the duration of the price to beat period. An affiliated
REP may not refuse service under the price to beat to a residential customer
except as provided by §25.477 of this title (relating to Refusal of
Service). An affiliated REP may not require residential customers to enter
into service agreements with a term of service as a condition of obtaining
service under the price to beat, nor may an affiliated REP provide any inducements
to encourage customers to agree to a term of service in conjunction with service
under the price to beat.
(2)
Small commercial customers.
(A)
A non-residential customer taking service from the affiliated
electric utility on December 31, 2001, shall be considered a small commercial
customer under this section and shall be eligible for service under price
to beat tariffs if that customer's peak demand during the 12 consecutive months
ending on September 30, 2001, does not exceed 1,000 kilowatts (kW). A non-residential
customer with a peak demand in excess of 1,000 kW during the 12 months ending
September 30, 2001, or during the price to beat period, shall no longer be
considered a small commercial customer under this section. However, any non-residential
customer whose peak demand does not exceed 1,000 kW for any period of 12 consecutive
months after it became ineligible to be a small commercial customer under
this section shall be considered a small commercial customer for billing periods
going forward for purposes of this section.
(B)
All small commercial customers, as defined by this section,
shall be eligible for the price to beat rate(s) for which they meet the eligibility
criteria in the applicable price to beat tariffs for the duration of the price
to beat period. An affiliated REP may not refuse service under the price to
beat to a small commercial customer, except as provided by §25.477 of
this title. An affiliated REP may not require small commercial customers to
enter into service agreements with a term of service as a condition to obtaining
service under the price to beat, nor may an affiliated REP provide any inducements
to encourage customers to agree to a term of service in conjunction with service
under the price to beat.
(f)
Calculation of the price to beat.
(1)
Rates to be used for price to beat calculation. The following
criteria shall be used in determining the rates to be used for the price to
beat calculation.
(A)
Residential. A price to beat rate shall be calculated for
each rate and service rider under which a residential customer was taking
service on January 1, 1999, except as approved by the commission pursuant
to subparagraph (C) of this paragraph. A price to beat rate shall not be calculated
for any new service or tariff option granted to an affiliated electric utility
pursuant to PURA §39.054, or any other rate or tariff option not in effect
on January 1, 1999.
(i)
Beginning with the first full billing cycle of the price
to beat period, residential customers served by the affiliated REP shall be
placed on the price to beat rate derived from the rate under which they were
taking service on December 31, 2001.
(ii)
Beginning with the first full billing cycle of the price
to beat period, residential customers served by the affiliated REP who were
taking service under a rate for which a price to beat rate was not developed,
shall be placed on the price to beat rate derived from any eligible residential
rate that was or would have been available to the customer on January 1, 1999.
(iii)
New residential customers after December 31, 2001, may
choose any price to beat rate for which they meet the eligibility requirements
as detailed in the applicable price to beat tariff.
(iv)
Residential customers who return to the affiliated REP
after being served by a non-affiliated REP may choose any price to beat for
which they meet the eligibility requirements as detailed in the applicable
price to beat tariff(s).
(v)
Notwithstanding clauses (i) - (iv) of this subparagraph,
residential customers may request service under any price to beat rate for
which they are eligible. Selection of the most advantageous rate shall be
the sole responsibility of the residential customer.
(B)
Small commercial. A price to beat rate shall be calculated
for each rate and service rider under which a small commercial customer was
taking service on January 1, 1999, except as approved by the commission pursuant
to subparagraph (C) of this paragraph. A price to beat rate shall not be calculated
for any new service or tariff option granted to an affiliated electric utility
pursuant to PURA §39.054, or for any rate of tariff option not in effect
on January 1, 1999.
(i)
Beginning with the first full billing cycle of the price
to beat period, small commercial customers served by the affiliated REP shall
be placed on the price to beat rate derived from the rate under which they
were taking service on December 31, 2001.
(ii)
Beginning with the first full billing cycle of the price
to beat period, small commercial customers served by the affiliated REP beginning
in January of 2002, who were taking service under a rate for which a price
to beat rate was not developed, shall be placed on a price to beat rate derived
from an eligible rate that was or would have been available to the customer
on January 1, 1999.
(iii)
New small commercial customers after December 31, 2001,
may choose any price to beat rate for which they meet the eligibility requirements
as detailed in the applicable price to beat tariff.
(iv)
Small commercial customers who return to the affiliated
REP after being served by a non-affiliated REP may choose any price to beat
rate for which they meet the eligibility requirements as detailed in the price
to beat tariff(s).
(v)
Notwithstanding clauses (i) - (iv) of this subparagraph,
small commercial customers may request service under any price to beat tariff
for which they are eligible. Selection of the most advantageous rate shall
be the sole responsibility of the small commercial customer.
(C)
An electric utility, on behalf of its future affiliated
REP, shall file within 60 days of the effective date of this section, price
to beat tariffs and supporting workpapers for the price to beat rates developed
in accordance with subparagraphs (A) and (B) of this paragraph. At the time
of this filing, the affiliated REP may request that a price to beat rate not
be developed from a particular rate of service rider along with justification
for the request. The electric utility shall provide notice to all customers
currently taking service under such rates or service riders of the utility's
request.
(2)
Base rate component of price to beat. For the eligible
rates identified in paragraph (1) of this subsection, the affiliated REP shall
reduce each base rate component including any purchased power cost recovery
factor (PCRF), in effect for the affiliated electric utility on January 1,
1999, by 6.0% in order to determine the base rate component of the price to
beat, with the following exceptions:
(A)
If base rates for the affiliated electric utility were
reduced by more than 12% as the result of a final order issued by the commission
after October 1, 1998, then the price to beat shall be the rate in effect
as a result of a settlement approved by the commission after January 1, 1999.
(B)
For affiliated REPs operating in a region defined by PURA §39.401,
the commission may reduce rates by less than 6.0% if the commission determines
a lesser reduction is necessary and consistent with the capital requirements
needed to develop the infrastructure necessary to facilitate competition among
electric generators.
(C)
Except as provided in subparagraphs (A) and (B) of this
paragraph, for any affiliated electric utility that has stipulated to rate
reductions in a proceeding for which a final order had not been issued by
January 1, 1999, such rate reductions shall be deducted from the base rates
in effect on January 1, 1999, in addition to the 6.0% reduction. Such rate
credits shall also be applied to the rates of the transmission and distribution
utility.
(3)
Fuel factor component of price to beat.
(A)
Each affiliated electric utility shall file an application
to establish one or more fuel factors, to be effective on January 1, 2002,
according to the following schedule:
(i)
April 1, 2001 - Reliant Houston Lighting & Power;
(ii)
May 1, 2001 - TXU Electric Company;
(iii)
June 1, 2001 - Texas-New Mexico Power Company and Central
Power & Light Company;
(iv)
July 1, 2001 - Entergy Gulf States, Inc. and West Texas
Utilities;
(v)
August 1, 2001 - Southwestern Electric Power Company and
Southwestern Public Service Company.
(B)
The rate year for the filing shall be calendar year 2002.
The affiliated electric utility shall follow the requirements of §25.237(a)(1),
(b), (c) and (e) of this title (relating to Fuel Factors) and the Fuel Factor
Filing Package of November 23, 1993, for the filing of its fuel factor(s).
To the extent that the commission has issued an order for a utility that includes
provisions relating to the price to beat fuel factor, the price to beat fuel
factor shall be set consistent with such an order.
(C)
Subject to the limitations in clause (i) and (ii) of this
subparagraph, affiliated electric utilities may utilize seasonal fuel factors
to reflect the expected differences in the cost of the market price of electricity
throughout the year.
(i)
Affiliated electric utilities with seasonal fuel factors
in effect on or before March 1, 2001, may request seasonal fuel factors for
their residential and small commercial price to beat customers provided the
level of seasonality is identical to that reflected in its commission-approved
fuel factors on March 1, 2001.
(ii)
Affiliated electric utilities without seasonal fuel factors
in effect on or before March 1, 2001, may request seasonal fuel factors to
be applicable to small commercial price to beat customers only. Any request
for seasonal fuel factors under this clause must demonstrate that the average
small commercial customer will receive, on an annual basis, a 6.0% reduction
from the average bundled rate in effect on January 1, 1999, adjusted for the
final fuel factor determined under subparagraph (D) of this paragraph; provided,
however, that a utility subject to the exception in paragraph (2)(A) of this
subsection must demonstrate that the average small commercial customer will
receive, on an annual basis, the average bundled rate in effect as the result
of a settlement approved by the commission after January 1, 1999, adjusted
for the final fuel factor determined under subparagraph (D) of this paragraph.
(D)
Each affiliated electric utility shall file additional
information on October 1, 2001, to reflect changes in the price of natural
gas for the rate year of 2002. The affiliated electric utility shall also
file information necessary to determine the initial headroom that exists under
the price to beat as a result of the setting of the initial price to beat
fuel factor pursuant to this subparagraph. The adjustment shall be calculated
using the following methodology:
(i)
For the ten-day period ending on September 15, 2001, an
average price shall be calculated for each month of 2002 in the closing forward
NYMEX Henry Hub natural gas prices, as reported in the Wall Street Journal.
(ii)
All other inputs into the calculation of the fuel factors
will be the same as those used to calculate the fuel factor in subparagraphs
(B) and (C) of this paragraph.
(iii)
Except for affiliated electric utilities whose base rates
were reduced by more than 12% as the result of a final order issued by the
commission after October 1, 1998, the fuel factor(s) to be used at the beginning
of the price to beat period shall be the fuel factor in effect on January
1, 1999, reduced by 6.0%, plus the difference between the fuel factor(s) established
pursuant to this subparagraph and the fuel factor in effect on January 1,
1999.
(iv)
The fuel factor(s) for affiliate electric utilities whose
base rates were reduced by more than 12% as the result of a final order issued
by the commission after October 1, 1998, to be used at the beginning of the
price to beat period shall be the fuel factor(s) established pursuant to this
subparagraph.
(E)
For a non-generating investor-owned utility with no fuel
factor as of January 1, 1999, its PCRF in effect on January 1, 1999, shall
be the equivalent to a fuel factor for purposes of calculating its price to
beat rates and future fuel cost adjustments under subsection (g) of this section.
Upon expiration of a purchased power contract of an affiliated REP unbundled
from such a utility, the affiliated REP may request a change in its PCRF to
account for any difference in purchased power costs.
(g)
Adjustments to the price to beat.
(1)
Fuel factor adjustments. An affiliated retail electric
provider may request that the commission adjust the fuel factor(s) established
under subsection (f)(3) of this section not more than twice in a calendar
year if the affiliated retail electric provider demonstrates that the existing
fuel factor(s) do not adequately reflect significant changes in the market
price of natural gas and purchased energy used to serve retail customers.
As part of a filing made pursuant to this paragraph, an affiliated REP may
also request an adjustment to the seasonality imparted to the fuel factor
in accordance with subsection (f)(3)(C) of this section. Alternatively, the
commission may, as part of its approval of an adjustment to the fuel factor,
impose a change in the seasonality imparted to the fuel factor. The methodology
for calculating the adjustment to the fuel factor(s) shall be the following:
(A)
For each business day of the ten-day period ending no more
than ten business days before the filing of a fuel factor adjustment application,
an average of the closing forward 12-month NYMEX Henry Hub natural gas prices,
as reported in the
Wall Street Journal
, is
calculated.
(B)
The average forward price for each business day calculated
in subparagraph (A) of this paragraph will then be averaged to determine a
ten-day rolling price.
(C)
The percentage difference between the averaged ten-day
rolling price calculated under subparagraphs (A) and (B) of this paragraph
and the averaged ten-day rolling price used to calculate the current fuel
factor(s) is calculated. If the current fuel factor was calculated through
an adjustment under subparagraph (E) of this paragraph, then the averaged
ten-day rolling price calculated concurrent with that adjustment shall be
used. If the percentage difference is 4.0% or more, the current fuel factor(s)
may be adjusted.
(D)
To adjust the current fuel factor(s), the percentage difference
is added to one and then multiplied by the current factor(s). The results
are the adjusted fuel factor(s) that will be implemented according to the
procedural schedule in clause (i) and (ii) of this subparagraph:
(i)
if no hearing is requested within 15 days after the petition
has been filed, a final order shall be issued within 20 days after the petition
is filed;
(ii)
if a hearing is requested within 15 days after the petition
is filed, a final order shall be issued within 45 days after the petition
is filed.
(E)
In addition to the adjustment permitted under subparagraphs
(A)-(D) of this paragraph, an affiliated REP may also request an adjustment
to the fuel factor if the headroom under the price to beat decreases as a
result of significant changes in the price of purchased energy. In making
a request under this subparagraph:
(i)
an affiliated REP shall demonstrate that:
(I)
the representative power price has changed such that the
headroom under the price to beat has decreased; and
(II)
the adjustment to the fuel factor is necessary to restore
the amount of headroom that existed at the time that the initial price to
beat fuel factor was set by the commission using then current forecasts of
the representative power price.
(III)
an affiliated REP making an adjustment under this subparagraph
shall also file the gas price calculation in subparagraphs (A) and (B) of
this paragraph for purposes subsequent adjustments to the fuel factor based
on changes in natural gas prices.
(ii)
the commission will issue a final order on an application
filed under this subparagraph within 60 days after the application is filed.
(F)
The commission shall, upon a showing made by an interested
party, that a sufficiently liquid electricity commodity index has developed
for the affiliated REP's relevant power region, allow an affiliated REP to
transition to the use of an electricity commodity index to adjust the fuel
factor for significant changes in the price of purchased energy. The commission
shall only allow the use of the index after the power generation company affiliated
with the affiliated REP has finalized their stranded cost determination. After
the commission has made a finding that a sufficiently liquid electricity commodity
index has developed, the affiliated REP shall be required to perform an additional
adjustment under subparagraphs (A) through (D) or (E) of this paragraph before
utilization of the index to change the fuel factor so that a benchmark index
price can be established. Subsequent changes to the fuel factor shall be based
on the percentage change in the electricity commodity index.
(2)
Adjustment for financial integrity. Upon a finding that
an affiliated REP will be unable to maintain its financial integrity if it
complies with subsection (f) of this section, the commission shall set the
affiliated REP's price to beat at the minimum level that will allow the affiliated
REP to maintain its financial integrity. However, in no event shall the price
to beat exceed the level of rates, on a bundled basis, charged by the affiliated
electric utility on September 1, 1999, adjusted for fuel.
(3)
True-up adjustment. The commission may adjust the price
to beat following the true-up proceedings under PURA §39.262.
(h)
Non-price to beat offers.
(1)
Offers to residential customers. An affiliated REP may
not offer any rates other than the price to beat rates to residential customers
within the affiliated electric utility's service area until the earlier of
36 months after the date customer choice is introduced, or when the commission
determines that an affiliated REP has met or exceeded the threshold target
for residential customers described in subsection (i) of this section, except
as provided by §25.454 of this title (relating to Rate Reduction Program).
(2)
Offers to small commercial customers. An affiliated REP
may not offer rates other than the price to beat rates to small commercial
customers until the earlier of 36 months after the date customer choice is
introduced, or when the commission determines that an affiliated REP has met
or exceeded the threshold target for small commercial customers described
in subsection (i) of this section.
(3)
Offers to aggregated small commercial load. Notwithstanding
paragraph (2) of this subsection, an affiliated REP may charge rates different
from the price to beat for service to aggregated loads having an aggregated
peak demand in excess of 1,000 kW provided that all affected customers are
commonly owned or are franchisees of the same franchisor.
(A)
If aggregated customers whose loads are served by an affiliated
REP in accordance with this subsection disaggregate, those individual customers
may resume service under the applicable price to beat rate(s), provided that
those customers meet the eligibility requirements of subsection (e) of this
section.
(B)
Any usage removed from the threshold calculation in subsection
(i)(1)(B) of this section due to aggregation shall be added back into the
threshold calculation upon disaggregation of the aggregated load.
(i)
Threshold targets.
(1)
Calculation of threshold targets.
(A)
Residential target. The residential threshold target shall
be equal to 40% of the total number of kilowatt-hours (kWh) consumed by residential
customers served by the affiliated electric utility during the calendar year
2000.
(B)
Small commercial target. The small commercial threshold
target shall be equal to 40% of the following difference: the total number
of kWh consumed by small commercial customers served by the affiliated electric
utility during the calendar year 2000 minus the aggregated load served by
the affiliated REP that complies with the requirements of subsection (h)(3)
of this section. The kWh associated with a customer who becomes ineligible
for the price to beat because the customer's peak demand exceeds 1,000 kW
shall also be removed from the threshold target.
(2)
Meeting of threshold targets. Upon a showing by the affiliated
transmission and distribution utility that the electric power consumption
of the relevant customer group served by nonaffiliated REPs meets or exceeds
the targets determined by the calculation in paragraph (1) of this subsection,
the affiliated REP may offer rates other than the price to beat.
(A)
Calculation of residential consumption. The amount of electric
power of residential customers served by nonaffiliated REPs shall equal the
number of residential customers served by nonaffiliated REPs, except customers
that the affiliated REP has dropped to the POLR, times the average annual
consumption of residential customers served by the affiliated utility during
the calendar year 2000.
(i)
The number of customers served by nonaffiliated REPs shall
be determined by summing the number of customers in the transmission and distribution
utility's certificated service area with a designated REP other than the affiliated
REP in the registration database maintained by the registration agent. Customers
dropped to the POLR by the affiliated REP shall not count as load served by
a nonaffiliated REP.
(ii)
The average annual consumption shall be calculated by
dividing the total kWh consumed by residential customers during the calendar
year 2000 by the average number of residential customers during the calendar
year 2000. The average number of residential customers during the calendar
year 2000 shall be calculated by dividing the sum of the total number of such
customers for each month of the year 2000 by 12.
(B)
Calculation of small commercial consumption. The amount
of electric power consumed by small commercial customers served by nonaffiliated
REPs shall be determined using the following criteria, except that customers
served by the POLR shall not count as load served by a nonaffiliated REP:
(i)
The amount of electric power of small commercial customers
with peak demand less than 20 kW consumed by nonaffiliated REPs shall be equal
to the number of small commercial customers with peak demand less than 20
kW served by nonaffiliated REPs times the average annual consumption of small
commercial customers with peak demand less than 20 kW served by the affiliated
electric utility during the calendar year 2000.
(I)
The number of customers served by nonaffiliated REPs shall
be determined by summing the number of small commercial customers with peak
demands less than 20 kW served in the transmission and distribution utility's
certificated service area with a designated REP other than the affiliated
REP in the registration database maintained by the registration agent.
(II)
The average annual consumption shall be calculated by
dividing the total kWh consumed by small commercial customers with peak demand
of less than 20 kW during the calendar year 2000 by the average number of
small commercial customers with peak demand of less than 20 kW during the
calendar year 2000. The average number of small commercial customers with
peak demand of less than 20 kW shall be calculated by dividing the total number
of such customers for each month of 2000 by 12.
(ii)
The amount of electric power consumed by small commercial
customers with peak demand in excess of 20 kW shall be the actual usage of
those customers during the calendar year 2000.
(I)
If less than 12 months of consumption history exists for
such a customer during the calendar year 2000, the available calendar year
2000 usage history shall be supplemented with the most recent prior history
of service at that customer's location for the unavailable months.
(II)
For customers with service to a new location, the annual
consumption shall be deemed to be equal to the estimated maximum annual demand
used by the affiliated transmission and distribution utility in sizing the
facilities installed to serve that customer multiplied by the product of 8,760
hours and the average annual load factor for small commercial customers with
peak demand greater than 20 kW for the year 2000.
(j)
Prohibition on incentives to switch. An affiliated REP
may not provide an incentive to switch to a nonaffiliated REP, promote any
nonaffiliated REP, or exchange customers with any nonaffiliated REP in order
to meet the requirements of subsection (f) of this section. Non-affiliated
REPs may not provide an incentive to return to the price to beat.
(k)
Disclosure of price to beat rate. An affiliated retail
electric provider shall disclose to customers, the price to beat in accordance
with §25.471 (relating to General Provisions of Customer Protection Rules).
In addition, if an affiliated REP offers a rate greater than the price to
beat, the price to beat rate must be disclosed along with a statement that
the customer is eligible for the price to beat. This disclosure must appear
on all written authorizations, Internet authorizations, the electricity facts
label and Terms of Service document. It must also be disclosed during telephone
solicitations before the customer authorizes service.
(l)
Filing requirements.
(1)
On determining that its affiliated retail electric provider
has met the requirements of subsection (i) of this section, an electric utility
or transmission and distribution utility shall make a filing with the commission
attesting under oath to the fact that those requirements have been met and
that the restrictions of subsection (h) of this section as well as the true-up
in PURA §39.262(e) are no longer applicable.
(2)
An electric utility or transmission and distribution utility
shall file a progress report with the commission after its affiliated REP
has met the requirements of subsection (i) of this section using a 35% threshold
target in lieu of a 40% threshold. Such progress reports(s) shall be filed
no later than 30 days after the 35% threshold has been met and shall contain
the same information required in this subsection.
(3)
No later than December 31, 2001, each transmission and
distribution utility shall determine the power consumption threshold targets
under subsection (i) of this section for residential and small commercial
customers within its certificated service area and shall file this information
with the commission and shall also make this information publicly available
through its Internet website. Each transmission and distribution utility,
together with its affiliated REP, shall update the small commercial power
consumption threshold as needed to reflect additional small commercial load
that has met the requirements of subsection (h)(3) of this section and therefore
is appropriate removed from the calculation of the threshold target. Concurrent
with this update, the transmission and distribution utility, together with
its affiliated REP, shall provide, for each group of aggregated customers
that have been removed from the calculation of the threshold target, the customers'
names, electric service identifiers, size of the customers' loads (individually
and in the aggregate), and how the customers meet the requirements of subsection
(h)(3). Such information may be filed under confidential seal. All certificated
REPs shall be deemed to have standing to review such filings.
(4)
Any application filed pursuant to this subsection shall
contain the following information:
(A)
a detailed explanation of how the relevant customer group
has met or exceeded the threshold consumption targets in subsection (i) of
this section;
(B)
calculation of the power consumption threshold target under
subsection (i) of this section for the relevant customer group and the date
such target was met;
(C)
verification of the meeting of the threshold target in
the following manner:
(i)
for the residential customer class, independent verification
from the registration agent verifying the number of customers in the residential
customer class within the transmission and distribution utility's certificated
service area that are committed to be served by non-affiliated REPs.
(ii)
for the small commercial class, an affidavit detailing
the number of customers in the small commercial class with peak demand below
20 kW within the transmission and distribution utility's certificated service
area committed to be served by non-affiliated REPs and the customers with
peak demand in excess of 20 kW with their actual usage calculated in accordance
with subsection (i)(2)(B)(ii) within the transmission and distribution utility's
certificated service area that are committed to be served by non-affiliated
REPs.
(iii)
For purposes of this subsection, a residential and small
commercial customer has committed to be served by a nonaffiliated retail electric
provider if the registration agent has received a switch request for that
customer and any mandated cancellation period pursuant to applicable commission
rule has expired.
(5)
The commission staff shall review all applications filed
under this subsection and shall make a recommendation to the commission within
ten days after the application is filed to approve or reject the application.
If a filing has insufficient information from which the commission can make
a determination, the commission may reject the filing without prejudice for
refiling the application. The commission shall issue an order approving or
rejecting the application within 30 days after the application is filed. An
electric utility or transmission and distribution utility filing an application
under this subsection shall not charge rates different from the price to beat
until the earlier of 36 months after the date customer choice is introduced
or the date such application has been approved by the commission.
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 March 21, 2001.
TRD-200101624
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: April10, 2001
Proposal publication date: November 10, 2000
For further information, please call: (512) 936-7308
Chapter 31.
ADMINISTRATION
Part 3.
TEXAS ALCOHOLIC BEVERAGE COMMISSION