Part 2.
PUBLIC UTILITY COMMISSION OF TEXAS
Chapter 25.
SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS
Subchapter J. COSTS, RATES, AND TARIFFS
1.
RETAIL RATES
16 TAC §25.242
The Public Utility Commission of Texas (commission) adopts
an amendment to §25.242 relating to Arrangements Between Qualifying Facilities
and Electric Utilities, with changes to the proposed text as published in
the January 4, 2002,
Texas Register
(27 TexReg
18). This amendment addresses the sale and purchase of electricity between
qualifying facilities (QFs) and retail electric providers (REPs) with the
price to beat (PTB) obligation (PTB REPs) in the restructured electric market
that became effective on January 1, 2002. The amendment retains the applicability
of the rule pertaining to arrangements between qualifying facilities and electric
utilities in the parts of Texas in which the electric market has not yet been
restructured. This amendment is adopted under Project Number 24365.
The federal Public Utility Regulatory Policies Act of 1978, Public Law
No. 95-617, 92 Stat. 3117 (codified as amended in scattered Sections 815,
816, 842-43) (PURPA) gives QFs the right to sell (put) electricity to electric
utilities at "avoided costs." A state agency is expected to implement this
requirement for "each electric utility, for which it has rate making authority."
16 U.S.C. §824a-3(f)(1)(2000). PURPA defines "electric utility" broadly:
"any person, State agency, or Federal agency, which sells electric energy."
16 U.S.C. §2602(4)(2000). In the restructured Texas market, both REPs
and power generation companies (PGCs) are electric utilities for purposes
of PURPA.
See
Public Utility Regulatory Act
(PURA), Texas Utilities Code Annotated §31.002(10) and (17) (Vernon 1998 &
Supplement 2002). However, the only entities that sell electricity in the
restructured market over which the commission has ratemaking authority are
PTB REPs and providers of last resort (POLRs), pursuant to PURA §39.202
and §39.106, respectively. The PTB REPs and POLRs began providing service
on January 1, 2002.
See
PURA §39.102
and §39.202(a).
On May 17, 2001, the Federal Energy Regulatory Commission (FERC) issued
an "Order Granting Declaratory Order and Denying Waiver of Regulations Implementing
PURPA" in FERC Docket Nos. EL01-49-000 and EL01-60-000. The commission, in
the FERC waiver docket, sought waiver from implementing PURPA upon the belief
that an open, competitive market beginning on January 1, 2002 would render
the PURPA power purchase obligations unnecessary in Texas. The FERC ruled
that the commission must maintain its obligation to implement PURPA after
unbundling and the commencement of competition and invited the commission
to develop a market-oriented method of determining avoided costs consistent
with PURPA and retail competition in Texas.
As part of the drafting process, commission staff conducted workshops in
Austin to receive input from potentially affected persons on August 10, 2001,
August 17, 2001, and March 13, 2002. Written comments from a number of interested
parties were submitted in connection with these workshops. Although standard
rulemaking procedures pursuant to Texas Government Code, Chapter 2001 were
used without incorporating formal negotiated rulemaking procedures, commission
staff nevertheless attempted to find areas of agreement among the parties
during these workshops. The commission considered the draft rule for publication
at the December 19, 2001 open meeting.
The commission received written comments on the proposed amendment on January
25, 2002 from Dynegy Power Inc., Calpine Corporation, Gregory Power Partners,
L.P., and Conoco Inc. (collectively Texas QFs), Texas Industrial Energy Consumers
(TIEC), Reliant Resources, Incorporated (RRI), American Electric Power Service
Company (AEPSC), Entergy Solutions Select Ltd. and Entergy Solutions Essentials
Ltd. (Entergy REPs), TXU Company LP (TXU), First Choice Power, Inc. (First
Choice), Office of Public Utility Counsel (OPUC), and Brazos Electric Power
Cooperative, Inc. (Brazos). On February 4, 2002, the commission received reply
comments from Texas QFs, TIEC, RRI, AEPSC, Entergy REPs, and TXU. On March
27, 2002, the commission received further comments on issues concerning the
commission's jurisdiction from Texas QFs, TIEC, RRI, AEPSC, Entergy REPs,
TXU, and OPUC. On April 1, 2002, the commission received reply comments on
the matter of the commission's jurisdiction from Texas QFs, TIEC, RRI, AEPSC,
Entergy REPs, TXU, and OPUC. Texas QFs filed supplemental comments on April
5, 2002 and RRI filed reply comments to Texas QFs' supplemental comments on
April 11, 2002.
The majority of the parties' comments generally focused on the jurisdiction
of the commission to establish avoided cost rates for the PTB REPs and POLRs,
and the lack of clarity in the phrase "market price" as the definition of
the rate that jurisdictional electric utilities must pay qualifying facilities.
Additional comments were submitted concerning the impact of the proposed rule
on the competitive market and several parties addressed alternatives for the
commission's consideration. The commission first addresses these broad considerations
and then the comments on specific rule language. Due to the overlapping nature
of the issues, arguments and rationale for decisions in this introductory
section shall be deemed as considered under the specific rule sections.
General comments on the competitive market
AEPSC indicated that the commission should seek to implement competitive
solutions rather than regulatory solutions whenever possible. They contended
that the proposed rule does not fully embrace competitive solutions and thus
places PTB REPs at a disadvantage. AEPSC stated that the proposed rule will
distort the competitive market. AEPSC interpreted PURPA to say that an "electric
utility" is an entity that sells electricity in Texas; therefore, all REPs,
power- generating companies, electrical cooperatives, municipal utilities
and power marketers are subject to PURPA's obligations. Because the proposed
rule only applies to PTB REPs and POLRs, it places an unfair burden on them.
AEPSC argued that PURPA, as enacted in 1978, no longer has any relevance to
the Electric Reliability Council of Texas (ERCOT) market that exists today.
PURPA was meant to encourage generation when electric monopolies also had
monopsony power over energy purchases. The introduction of wholesale electricity
competition eliminated this market power. AEPSC further commented that QFs
will have the same opportunity to sell their power as any other generating
company and mandating that PTB REPs and POLRs take their puts amounts to preferential
treatment for the QF. To the extent that these puts displace purchases of
energy from different generating companies, this will result in an inefficient
allocation of resources. AEPSC finally argued that if for some reason, PURPA
is repealed or otherwise rendered obsolete, any rules adopted by the commission
addressing PURPA obligations should also be repealed.
The commission agrees with AEPSC that it should seek competitive solutions
rather than regulatory solutions whenever possible. However, as discussed
below, the commission finds that it has an obligation to implement PURPA and,
for reasons of administrative efficiency and market certainty, chooses to
adopt this rule. The commission adopts this rule with some modification to
the definition of "market price" in order to provide a definition that is
the closest proxy as possible to a market price. The commission agrees that
if PURPA is repealed or otherwise rendered obsolete, the rule should be reconsidered.
Rule alternatives - contested case process, self-implementation,
or ERCOT
Entergy REPs and TXU reasoned that federal law, citing to PURPA and
Generally, RRI argued that the proposed rule is unnecessary for the commission
to fulfill its duties under PURPA. RRI argued that the commission's instruction,
at its December 19, 2001 open meeting, that the ERCOT electric utilities,
as defined by PURPA, continue fulfilling their mandatory purchase obligations
at market prices until such time that this proposed rule becomes finalized
should be left standing as guidance. RRI contends that such guidance to all
electric utilities in Texas, including ERCOT, is all that is necessary in
order for the commission to fulfill its PURPA mandates. RRI argued that the
proposed rule is unnecessary in order to meet PURPA requirements because the
restructured ERCOT market provides more opportunities for qualifying facilities
to sell their power than were envisioned at the time PURPA was enacted. Essentially,
RRI argued that the intent of PURPA -- assurance of QF interconnection and
other services from electric utilities and assurance of electric utilities'
purchases of QF power -- has been outpaced by the opening of the wholesale
and retail markets in ERCOT. Thus, the restructured, competitive wholesale
and retail ERCOT market provides QFs in Texas far superior sales opportunities
than that allowed under regulated markets.
TXU, AEPSC, RRI, and Entergy REPs commented on self-implementation of PURPA.
TXU argued that PTB REPs and POLRs are non-regulated entities, but if required
to implement PURPA, they should be allowed to self-implement. AEPSC suggested
that the commission adopt a rule that encourages electric utilities to self-implement
PURPA, particularly addressing PTB REPs and POLRs, if necessary. RRI stated
that it will comply with its PURPA obligation to self-implement by entering
into mutually agreeable bilateral transactions for energy from QFs. Additionally,
RRI argued that QFs could choose to exercise the PURPA put through bilateral
agreements with any PURPA defined electric utility for as-available energy
which reflects the market prices in the competitive power region. Consistent
with this approach, RRI argued that the commission could endorse procedures
that ensure economic efficiency of the competitive market. Entergy REPs commented
that they support the position that REPs should self- implement their PURPA
obligations and disagreed with the position that urges the commission to adopt
the proposed rule amendments based on a finding of ratemaking authority over
PTB REPs and POLRs.
Texas QFs argued that since January 1, 2002, REPs have self-implemented
with consequences that most of the non-firm energy produced by 10,000 MegaWatt
(MW) of QF energy in Texas has been shut-in since that date. Texas QFs argued
that the "market price" definition will shut down cogeneration in Texas, in
direct contravention of the goals of the U.S. Congress to produce energy efficiencies
and fuel conservation through cogeneration, while decreasing reliance on fossil
fuels. AEPSC objected to the Texas QFs' argument that their energy has been
shut-in in ERCOT, noting there are many new market participants to whom QFs
can now sell their power in addition to the traditional utilities.
Texas QFs' further commented that if the commission is required by PURPA
to set an avoided cost rate for the PTB REPs and POLRs and fails to do so,
it will be treating them as if they were non-jurisdictional electric utilities,
which under PURPA §210(f)(2) are required to self-implement the FERC
rules. The commission cannot assert jurisdiction over the PTB REPs and POLRs
for purposes of implementing PURPA and then allow them to self-implement PURPA
with respect to the avoided cost rate.
Texas QFs noted that the TXU and AEPSC REPs have already purported to illegally
self- implement PURPA, and the rates they are using utilize a "lesser of"
formula whereby QFs will never be paid more than the balancing energy price
-- in direct contravention of the FERC's rejection of the balancing energy
ancillary service administered by ERCOT. AEPSC took issue with the Texas QFs'
comments that self-implementation is illegal, pointing out that the Texas
QFs failed to cite a single law or statue violated by self-implementation
in the absence of commission action.
The commission finds that it has the obligation to implement PURPA and,
thus will do so through this rulemaking rather than allowing self-implementation.
The commission's instruction at its December 19, 2001 open meeting that the
ERCOT electric utilities, as defined by PURPA, continue fulfilling their mandatory
purchase obligations at market prices until this proposed rule becomes finalized
was meant to be strictly transitional. The commission disagrees with RRI that
the temporary implementation directed at the December 19, 2001 open meeting
is all that is necessary for the commission to fulfill its PURPA mandates
and declines to keep such guidance in place as the method of PURPA implementation.
Federal law may allow the States to opt out of implementing PURPA; however,
the States may choose to implement PURPA by several methods, including rulemaking.
The commission chooses to continue implementation of PURPA through rulemaking.
The commission agrees with Texas QFs that implementation on a case-by-case,
contested proceeding hearing approach would waste parties' resources. Additionally,
case-by-case determinations would severely tax the commission's resources
in adjudicating such matters. The commission further agrees with Texas QFs
that a two-step process whereby the commission adopts a transitional avoided
cost pricing methodology that relies on a reasonable proxy for prices until
a liquid, real-time market develops is reasonable and preferable. The commission
finds that the best accommodation of as-available energy from a QF would be
to have that energy delivered to a liquid spot market where QFs receive the
market clearing price of energy at the time that they delivered. Relaxation
or elimination of ERCOT's balanced schedule requirement would facilitate the
development of a liquid spot market.
The second alternative proposed by AEPSC was for the commission to implement
a market- based solution through ERCOT. AEPSC contended that if ERCOT were
to establish a mechanism to accept all QF power, this would treat all electric
providers fairly and energy would settle at an efficient price. OPUC suggested
that ERCOT is better equipped to fulfill QF obligations. OPUC argued that
ERCOT already procures and sells balancing energy. Should ERCOT relax its
balancing schedule requirement, as it is considering, it would have the ability
to auction QF power. However, TXU disagreed with AEPSC's and OPUC's alternative
to implementing PURPA for PTB REPs and POLRs which is to require ERCOT to
purchase all PURPA puts. TXU explained that ERCOT is not a PURPA utility which
sells electric energy. Rather, ERCOT is an agent that acquires ancillary services
on behalf of energy buyers and sellers in the ERCOT market. TXU is concerned
that AEPSC's and OPUC's alternative would "completely destroy the paradigm
of a limited-independent system operator that has been promoted by the market
participants in ERCOT."
The commission finds that ERCOT cannot be required to purchase PURPA puts
because ERCOT is not a PURPA utility, which is defined as an entity that sells
electric energy. While ERCOT acts as an agent to acquire ancillary services
on behalf of entities in the ERCOT market, it never takes title to the electric
energy. Therefore, ERCOT is not a seller of electric energy, which is necessary
to be defined as a PURPA utility obligated to purchase PURPA puts. The commission
agrees with TXU and declines to impose PURPA put requirements on ERCOT.
Comments on jurisdiction
TXU, RRI, and AEPSC argued that the commission does not have ratemaking
jurisdiction over PTB REPs and POLRs. In contrast, TIEC and Texas QFs commented
that the commission has the jurisdiction to implement PURPA with respect to
the PTB REPs and POLRs- electric utilities under federal law over which the
commission has ratemaking authority.
RRI, TXU, and AEPSC argued that the Legislature clearly intended that all
REPs, including PTB REPs and POLRs, be non-regulated entities. RRI asserted
that as a result of restructuring in Texas and the redefinition of "electric
utility" pursuant to Senate Bill 7, 76th Legislature, (SB 7), the commission
does not have the type of ratemaking authority contemplated by PURPA over
PTB REPs and POLRs. RRI disagreed that the commission's remaining ratemaking
authority over REPs, under PURA, Chapter 39, as it pertains to the setting
of the PTB fuel factor, is traditional cost of service ratemaking authority
that would trigger the obligation to implement the PURPA mandates. Thus, RRI
argued that the proposed rule should be rejected. TXU argued in a similar
vein that the commission no longer has traditional cost of service ratemaking
authority over PTB REPs and POLRs, but only has limited authority over rates
charged through the fuel factor of the PTB and the authority to approve POLR
rates. Likewise, AEPSC argued that although the commission sets the PTB fuel
factor and POLR REP's rate, this does not resemble the traditional ratemaking
authority in place at the time PURPA was passed. Without jurisdiction, AEPSC
suggested that the commission decline to adopt the proposed rule.
RRI argued that the proposed rule asserts that the commission's limited
authority over POLRs and PTB REPs, for PURPA purposes, also subjects these
entities to general ratemaking authority. Per RRI, the commission's authority
would go so far as to create a new entity not mentioned in PURA -- PTB REP.
RRI asserted that such action is not supported by, and is contrary to, PURA.
RRI further asserted that the proposed rule ignores the fact that a single
REP, as a single legal entity, can serve both PTB and non-PTB customers, as
well as serve as a POLR. RRI stated that problematic consequences could ensue
in that the proposed rule's stated limited commission authority over the PTB
REP and/or POLR pricing would essentially become broader, general ratemaking
authority over the entire entity, including the non-POLR and non- PTB REP
that do not have PURPA obligations. In order to withstand the regulatory tension,
RRI argued that the only alternative was for the proposed rule to require
that separate entities perform separate functions. However, RRI asserted this
is not required nor allowed by PURA, and such separation would impose burdensome
and higher scheduling, accounting and settlement costs as reflected in PTB
rates or the rates charged to POLR customers.
RRI and AEPSC further argued that no state law authority exists to provide
the commission with the power to regulate PTB REPs and POLRs wholesale power
purchases from QFs. RRI and AEPSC outlined the scope of the commission's power
as a creature of the state, citing to the recent
PUC v. City Public Service Board
, 53 S.W.3rd 310 (Tex. 2001) which
held that the commission only has those powers expressly conferred upon it
by the Legislature and whatever powers that are reasonably necessary to fulfill
its express functions or duties.
RRI, AEPSC, TXU, and Entergy REPs asserted that there is no express grant
of authority upon the commission to direct how the PTB REPs and POLRs will
purchase power. Further, RRI, AEPSC, and Entergy REPs argued that PURA §35.061,
in and of itself, cannot provide the commission power to adopt and enforce
rules encouraging power production. The authority must derive from other grants
of state authority. The limited grants of authority in PURA, Chapter 39 over
the narrow retail end of the REPs' business cannot be expanded to provide
the commission power through PURA §35.061.
OPUC argued that some limited commission authority exists by inference
and/or implication. OPUC asserted that the commission has the authority to
ensure that ancillary services are reasonable pursuant to PURA §35.004(e).
Additionally, OPUC points out that the commission has jurisdiction by implication
by virtue of its oversight authority over the wholesale power markets contained
in PURA §§39.157(a) (addressing market power abuses), 39.151(d)
and (i) (oversight, review and delegation of authority to ERCOT), 39.252(d)
and 39.262(a) (authority to review wholesale transactions that increase stranded
costs).
AEPSC and RRI argued that authority may not be implied because it is not
necessary in order for the commission to carry out its express duties. The
Legislature through SB 7, and the commission through rules adoption, have
developed a deregulated market that encourages economical production of electric
energy from QFs and further satisfies PURA §35.061 without implying additional
powers over PTB REPs and POLRs. Although the FERC addressed this issue in
terms of whether to grant a waiver to the commission under federal law, the
issue presented to the commission is one of state law -- whether the commission
need imply authority over PTB REPs and POLRs to encourage QF power production.
Texas QFs argued that until January 1, 2007, PTB REPs must offer the PTB,
which was initially established by the commission, including the fuel factor
incorporated therein. In addition, the commission has the authority to adjust
the PTB up to twice a year for changes in the prices of natural gas and purchased
energy. The commission also has exclusive jurisdiction to approve rates charged
by POLRs. Texas QFs argued that PURPA defines "State regulated electric utility"
as "any electric utility with respect to which a State regulatory authority
has ratemaking authority." Texas QFs further pointed to
FERC v. Mississippi
in arguing that this very broad definition was
intended to encompass any electric utility for which a state regulatory authority
exercises adjudicatory or ratemaking authority. Texas QFs argued that nothing
in PURPA implies or suggests that "ratemaking authority" means "extensive
ratemaking authority," "traditional ratemaking authority," "general authority
to instigate rate-setting proceeding to revise the rates," or "traditional
cost of service ratemaking." Texas QFs argued that if Congress had intended
such general, comprehensive, cost of service ratemaking authority, it could
have easily stated so.
Contrary to the utilities, Texas QFs further argued that the commission
need not have state law authority to regulate PTB REPs and POLRs wholesale
power purchases from QFs in order for it to be required to implement PURPA.
Texas QFs and TIEC asserted that the obligation to implement PURPA comes from
PURPA, even if the state Legislature has not conferred specific power to regulate
the power purchases. Texas QFs indicated the lack of state authority conferred
on the commission over wholesale QF power purchases from PTB REPs and POLRs
is a non- issue. Notwithstanding, Texas QFs and TIEC argued that the commission
has explicit and implicit state law authority under the mandate in PURA §35.061,
which requires the commission to adopt and enforce rules to encourage the
economical production of QF power.
Texas QFs further argued that, per
FERC v. Mississippi
, the commission has the obligation to implement PURPA if the commission
has "state adjudicatory machinery" in place to enforce and entertain claims
analogous to those granted by PURPA. Thus, if the commission has the power
to adjudicate claims involving QFs and PTB REPs and POLRs, the commission
must implement PURPA. Texas QFs further cited to provisions in PURPA in which
procedural provisions exist that would provide the commission sufficient tools
to implement PURPA consistent with the Court's instruction in
FERC v. Mississippi
. Given the adjudicative and procedural machinery
together with the federal mandate to implement PURPA, the commission must
enforce the FERC PURPA rules.
Finally, Texas QFs argued that implementation is not optional as Entergy
REPs and TXU assert
FERC v. Mississippi
and
Citing to
FERC v. Mississippi
and
Additionally, AEPSC concurred with RRI and TXU that if the commission finds
that it has ratemaking authority over PTB REPs and POLRs, it should be limited
to this rulemaking proceeding.
The commission agrees with Texas QFs and TIEC and finds that it has ratemaking
authority, through PURA Chapter 39, over PTB REPs and POLRs and a federal
mandate to implement PURPA QF power purchase obligations. Although, the ratemaking
powers conferred upon the commission in PURA Chapter 39 may not be "plenary"
or completely resemble "traditional" cost of service ratemaking authority
over vertically integrated utilities, the commission agrees with Texas QFs
that PURPA does not provide any indication of the scope of "ratemaking authority."
The commission disagrees with RRI that the proposed rule broadens the commission's
limited authority over POLRs and PTB REPs, for PURPA purposes, to general
ratemaking authority. Further, the commission finds that it can institute
regulations that implement power purchase obligations upon PTB REPs and POLRs
without affecting REPs' PURPA obligations separate from commission imposed
obligations.
The commission agrees with Texas QFs and TIEC that, together with the federal
PURPA mandate and state ratemaking jurisdiction under PURA Chapter 39, the
commission has underlying state authority to direct how PTB REPs and POLRs
will purchase QF power through PURA §35.061 which mandates the commission
to adopt and enforce rules to encourage the economical production of QF power.
The commission further acknowledges that, pursuant to the FERC's May 17, 2001
"Order Granting Declaratory Order and Denying Waiver of Regulations Implementing
PURPA" in FERC Docket Nos. EL01-49-000 and EL01-60-000, all unbundled REPs,
transmission and distribution companies, and power generation companies are
federally mandated under PURPA to take puts of energy from QFs. The commission
does not agree with the parties who argue that the Legislature altered, through
SB7, the commission's authority under PURA §35.061, with regards to REPs.
Rather, the commission believes that the Legislature did not intend any alteration
of the commission's powers to regulate QF power sale, including to REPs, by
the passage of the PURA Chapter 39 provisions in SB 7. Thus, the commission
finds that through the federal PURPA mandate to implement QF power purchase
obligations, state ratemaking jurisdiction under PURA Chapter 39, the state
mandate under PURA §35.061 to adopt and enforce rules to encourage economical
production of QF power, and an endeavor to regulate consistent with federal
law, the commission has jurisdiction to implement PURPA through this rulemaking.
To the extent that TXU and AEPSC have concerns regarding the expansion of
the commission's ratemaking jurisdiction beyond the authority conferred by
PURA, the commission finds that its retail ratemaking jurisdiction in areas
open to competition is currently limited to the price to beat charged by the
affiliated REP and POLR rates .
Expanding the jurisdictional arguments, Texas QFs noted that the commission
has ratemaking jurisdiction over the transmission and distribution utilities
(TDUs) which, under federal law, retain the obligation to purchase PURPA energy.
Similarly, OPUC noted that if commission staff's interpretation of its jurisdiction
is correct -- that affiliated REPs (AREPs) and POLR's must accept QF puts
because they are subject to rate making procedures -- then this jurisdiction
should extend to affiliated power generation companies (APGCs). OPUC argued
that the APGC should also be forced to accept QF puts, as it is also subject
to the rate making process via the true-up proceeding. In response, TXU contended
that the commission does not have jurisdiction to implement PURPA for TDUs
or APGCs. TXU argued that while the true-up proceeding is an act of ratemaking
authority over TDUs, the TDUs do not sell electric energy, and PURPA obligations
only apply to entities that sell electric energy. TXU further explained that
in the true-up preceding the ratemaking authority is over TDUs and not APGCs,
as the commission only gathers information from the APGCs to adjust the rates
of their affiliated TDUs. Therefore, TXU noted that APGCs must self-implement
their PURPA obligations. AEPSC also disagreed with OPUC's conclusion that
APGCs fell under commission jurisdiction. AEPSC noted that although APGC is
subject to a true-up proceeding, the commission has no authority to change
its rates.
The commission agrees with TXU and declines to impose PURPA put requirements
on TDUs or APGCs. The commission agrees with TXU that the commission does
not have jurisdiction to implement PURPA power purchases over APGCs. The commission
continues to have jurisdiction over TDUs; however, the commission recognizes
that PURPA power will not be put to TDUs.
First Choice objected to the possibility of being forced to accept supplies
from non- competitive suppliers. Its complaint is based upon the fact that
First Choice has a contract with its wholesale supplier that requires it to
purchase most of its power from that supplier. It claims that other PTB REPs
with generation affiliates can accommodate the requirement to purchase power
from QFs, but that it cannot due to the lack of such an affiliate. First Choice
cites proposed subsection (f)(5) as applying to utilities that do not own
generation. TXU disagreed with First Choice's request for an exception for
accepting and pricing power from QFs. TXU noted in their reply comments that
under FERC case law, "PURPA electric utilities that are customers to full-requirements
supply contracts are still obligated to purchase QF power, however their avoided
costs are set at the avoided costs of their full-requirements suppliers."
AEPSC agreed with First Choice that it is in a difficult position, but stated
that First Choice's problem is not unique and that no AEPSC REP owns any generation
either. AEPSC requested that First Choice not receive different treatment
with regard to its PURPA obligations.
The commission finds that First Choice is in a difficult position, but
agrees with AEPSC and TXU that it is not unique, and therefore, should not
receive different treatment with regard to its PURPA obligation. First Choice
must comply with PURPA, as it meets the PURPA definition of "electric utility."
Accordingly, the commission declines to grant First Choice's exception.
General comments on market based price and avoided
cost
RRI, AEPSC, and TXU argued that if the commission is found to have jurisdiction,
then a market-based pricing mechanism should be used. RRI argued that if the
commission determines that a rule must be adopted, the proposed rule's definition
of market price must be maintained in order to avoid conflicts with the PTB
and to ensure that potential POLRs will bid to be POLRs. AEPSC stated that
FERC has encouraged the commission to use market-based pricing.
Texas QFs argued that adopting the "market price" as proposed will give
PTB REPs and POLRs free rein to implement rates which are nontransparent,
calculated only after-the-fact, and highly subject to manipulation and gaming.
However, AEPSC disagreed with the Texas QFs' assertion that self-implemented
QF rates are subject to gaming, pointing out that such rates are heavily dependent
on the market clearing price of energy (MCPE), which is independently determined
by ERCOT. Entergy REPs, in initial and reply comments, commented that a specific
definition for market price should not be included in the rule, and advocated
in favor of restoring a general market standard that can be developed through
self-implementation.
Texas QFs argued that as proposed, QFs will never know what the purchase
price will be at the time of commitment. The Texas QFs argued that the proposed
amendments fail to establish either a methodology for determining avoided
costs, or an avoided cost rate, for purchases from QFs. Texas QFs contended
that the payment methodology based on the market price of energy purchases
proposed in subsection (i)(4), with the definition of market price in subsection
(c)(8), is completely circular and fails to implement avoided cost pricing
rates for purchases of QF energy. Texas QFs argued that the market is left
without a transparent pricing mechanism for non-firm energy, depriving QFs
of not only a reasonable estimate of the price they may be paid for their
non-firm energy at the time they must schedule or deliver it, but also of
the knowledge that payment will be received. Texas QFs commented that this
fails to comply with the PURPA mandate to set avoided cost rates. Texas QFs
argued that the definition of "market price" is too vague and should reflect
the purchasing utility's highest (and least efficient) running costs or purchased
power cost, i.e., the utilities "incremental costs" as required by PURPA.
Finally, Texas QFs argued that granting the PTB REPs and POLRs the discretion
to determine their own avoided costs constitutes an abdication by the commission
of its PURPA responsibility to set avoided cost rates.
Texas QFs proposed the following definition of market price: "Market price
for each 15- minute settlement interval is determined by multiplying the Heat
Rate of the Marginal Unit times a fuel index. The Marginal Unit will be determined
pursuant to the 'unit commitment' plan of the Qualified Scheduling Entity
(QSE) for the PTB REP or POLR as submitted in that QSE's Day Ahead ERCOT schedule
and Resource Plan. The Heat Rate will be based upon those determined to be
appropriate proxies for the Marginal Unit as adopted for utilities' generating
fleets in Section 25.381 of this Title. The fuel index will be an index appropriate
for the type of generating unit on the margin (i.e. for gas units, it will
be the Daily Gas Price)." Texas QFs reasoned that since there is no established
day-ahead or real-time market (e.g. a "power exchange") in ERCOT, their proposal
is based upon the heat rates and fuel prices of the capacity auction products
contained in §25.381, relating to Capacity Auctions, as well as the day-ahead
ERCOT schedule and Resource Plan of the PTB REP's or POLR's QSE. Texas QFs
stated that their proposal, consistent with the FERC's invitation to determine
avoided costs in a market- oriented manner, utilizes the PTB REP's or POLR's
QSE's Day-Ahead unit commitment plan to determine the unit on the margin --
after the QSE has taken into account any possible day-ahead market opportunities.
The units committed to run by the QSE should reflect a market price, because
the QSE would not commit a unit to run if its incremental cost was not at
or below market. Texas QFs noted that this still was not a published market
price, but argued that it reflects what the QSE reasonably expects the energy
market to be, and is therefore not subject to the same abuses and manipulations
as a self-determined or MCPE market price. Once the unit on the margin is
identified, Texas QFs argued, the proposal then utilizes capacity auction
products as commission-approved market proxies for the marginal units determined
by the "unit commitment" of the PTB REP's or POLR's QSE.
Texas QFs commented that their proposal offers the following benefits:
it relies on the actual "unit commitment" schedule of the AREP's or POLR's
QSE, so by definition it is a "market based" rate; it utilizes heat rates
and fuel price indices already approved by the commission in the capacity
auction rule; and because it is reasonable, there is no need for AREPs to
file confidential, competitively-sensitive power purchase agreements with
the commission to verify that they are correctly calculating their avoided
costs.
TXU offered a list of comments regarding TIEC and the Texas QFs' proposed
avoided cost methodologies. First, TXU opposed TIEC and the Texas QFs' proposed
definition of "market price" indicating that it is irrelevant to entities
that do not own generation and could require PTB REPs and POLRs to pay more
than their individual avoided cost for QF power. TXU argued that PTB REPs
and POLRs must purchase all of their power supplies so their avoided cost
should be what they would have paid to purchase power if not for the purchase
of QF power. TXU further commented that while fuel prices and heat rates may
indirectly affect the price of power purchases by PTB REPs and POLRs, these
factors do not necessarily account for all the costs that a particular PTB
REP or POLR avoids with the purchase of QF power. Second, TXU commented that
PTB REPs and POLRs will not always receive power from their APGCs and that
pricing arrangements with suppliers will not always be based on incremental
generating costs of their suppliers. Third, TXU argued that the methodology
proposed by TIEC and Texas QFs would require PTB REPs and POLRs to pay more
than their avoided costs for QF power by imposing firm pricing for non-firm
products. TXU was also concerned that TIEC's and Texas QFs' methodology would
create an arbitrage opportunity for QFs by establishing day-ahead firm avoided
cost prices. Fourth, TXU contended that TIEC and Texas QFs' proposal to use
the "marginal unit" in a PTB REP's or POLR's QSE-unit-dispatch to measure
the REP's avoided cost is illogical for two reasons: (1) a PTB REP's or POLR's
QSE may or may not represent generating units for dispatch; and (2) a QSE
may represent multiple market participants that affect its dispatch decisions
causing the QSE's marginal unit to be unrelated to the avoided cost of the
PTB REP or POLR. Fifth, TXU addressed Texas QFs' initial comments that PTB
REPs and POLRs self-implemented avoided cost will be after-the-fact. TXU explained
that PURPA rules do not require that PURPA electric utilities calculate or
state their avoided costs before-the- fact. The PURPA rules require that electric
utilities make available the data needed to estimate avoided costs. TXU also
stated that no QFs have approached them to acquire any of the above- mentioned
avoided cost data. Finally, TXU argued that TIEC and Texas QFs are seeking
to apply unrelated proxy prices through the use of heat rates and fuel rates
used in the capacity auction to determine avoided costs. TXU deemed that the
proxies were created for the purpose of the capacity auction and therefore
do not represent the actual operation of any particular utility or generating
unit. TXU was concerned that by using the proxy prices as a measure of avoided
cost, there is potential for PTB REPs and POLRs to pay more than their avoided
cost for QF power which is in violation of PURPA and FERC rules.
RRI and AEPSC also disagreed and took issue with the Texas QFs definition
of "marginal unit" which is based on the "unit commitment" plan of the QSE
for the PTB REP or POLR. RRI asserted that it would require creation of a
new QSE for the REP to separately schedule for PTB and/or POLR obligations,
which is not required by PURA and which would impose additional costs on the
REPs and their PTB and/or POLR customers. RRI further pointed out that the
QFs do not offer any feasible method for determining the marginal unit from
the unit commitment plan, which creates insurmountable problems. AEPSC argued
that QSE's are not subject to the commission's jurisdiction and other market
participants' QSEs are not required to disclose such information. AEPSC argued
that disclosing its marginal heat rates will put a PGC at a competitive disadvantage,
and a QSE may have more than one marginal unit.
RRI also took issue with the Texas QFs assertion that "the QSE would not
commit a unit if its incremental cost was not at or below market." To the
contrary, RRI stated a QSE may commit a unit even if its incremental cost
is above market in order to have the units available to meet peak obligations,
to participate in the ancillary service markets when the profit more than
offsets the loss on energy sales, and the units may be forced by ERCOT to
run for reactive power. Thus, RRI asserted that these given circumstances
should not be considered "unit on the margin" for determining price that should
be paid for QF energy deliveries. Ultimately, RRI argued that the Texas QFs
proposal is unworkable, creates gaming opportunities and will result in higher
costs to customers.
Additionally, RRI also pointed out that responsibility transfers are further
complicated because QSEs do not have the capacity to dynamically adjust resources
in its QSE to accommodate the PURPA put. Without the supply resources in its
supply portfolio to directly control, the QSE used by the PTB REP and POLR
would be exposed to the balancing energy market for QF deliveries. Under such
scenario, the PTB REP or POLR would not be purchasing from the QF but rather
would have purchased power that is sold to ERCOT via the balancing energy
market. Thus, the definition of market price contained within the proposed
rule would not correctly apply because the PTB REP or POLR would not have
foregone power purchases due to the purchase from the QF. RRI asserted that
only the QSEs are authorized under the ERCOT Protocols to schedule energy,
so the PTB REPs and POLRs therefore will not be able to implement responsibility
transfers on their own. Texas QFs agreed in reply comments, but stated it
should be a simple matter for the PTB REPs and POLRs to require such capability
in their contracts with their QSEs.
In reply comments, RRI generally agreed with OPUC that the Texas QFs' approach
"encourages market manipulation and gaming which distort the market and raise
power costs. The effect of such tariffs would be to develop a floor price
for QF power, since the QF producer would always be free to sell at market
rates when it is more beneficial to do so."
AEPSC commented that "market price" should be defined by the MCPE as determined
by ERCOT. AEPSC stated that the rule's definition of "market price" is too
vague and will result in commission imposed prices, rather than market-based
prices. AEPSC argued that the proposed definition depends on which purchases
were forgone by the REP and will lead to complaints by the QF. Texas QFs'
objected to this proposal, noting that FERC found that ERCOT energy imbalance
price neither constitutes a market price nor is it an adequate substitute
for a QFs right under PURPA to sell to a purchasing utility at its avoided
cost rates. Texas QFs commented on the FERC's statement that ERCOT ancillary
purchases occur only after utilities have fully bilaterally arranged for and
dispatched their own generation to their affiliated REPs. Texas QFs argued
that the ERCOT imbalance service effectively is a "last stop" reliability
service that is in no way related to a utility's incremental costs of generation.
Texas QFs pointed out that the ERCOT imbalance market is "far smaller" than
the short-term market as a whole. Texas QFs argued that due to its small size,
lack of liquidity, and the fact that no market participant can purchase energy
from the imbalance bid stack, it is not a market at all. Texas QFs argued
that the price in that market has often been negative or zero.
AEPSC argued in its reply comments that FERC did not prohibit the use of
MCPE for pricing purposes as the Texas QFs suggested. Rather, AEPSC argued
that FERC did not address the issue of MCPE and simply ruled that the opportunity
to sell ancillary services to ERCOT does not fulfill PURPA obligations. AEPSC
further contended that the use of MCPE is a superior pricing method than that
suggested by the Texas QFs and TIEC. AEPSC stated that formulaic pricing is
inconsistent with market-based pricing and will hinder the development of
a fair and competitive energy market. AEPSC also argued that the capacity
auction heat rate is inaccurate, and therefore, inferior to MCPE. AEPSC also
responded to the Texas QFs' statement that a negative or zero price for balancing
energy indicates that the market is not working properly. AEPSC directly disagreed
and stated that such prices indicate that the marginal benefit of additional
power is negative. Therefore, a negative price for balancing energy is sometimes
appropriate. AEPSC also noted that balancing energy prices are negative a
small percentage of time. AEPSC countered the Texas QFs' argument that pricing
after the fact is unacceptable by stating that it is necessitated by logistical
constraints. AEPSC also stated that QFs could enter into bilateral contracts
with purchasers if they demanded increased price certainty.
RRI also asserted that a PURPA defined electric utility operating in the
competitive market place should not be obligated to pay more than market price,
nor should it be obligated to take more than it is able to accept consistent
with its other obligations. RRI stated that residual QF energy could be put
to ERCOT in real-time which would exercise decremental balancing energy bids
to accommodate such energy. Per RRI, the avoided cost for such placement would
be the market-clearing price for balancing energy less any imbalance penalties.
Alternatively, RRI argued that residual energy put to the PURPA defined electric
utility would appear as resource imbalance and receive the market-clearing
price less any imbalance penalties.
First Choice proposed that the price should be the balancing energy market-clearing
price for the ERCOT congestion zone in which the power is produced if it is
required to take power from other QF suppliers. First Choice argued that any
market price definition that comes out of this rulemaking needs to recognize
this congestion zone distinction.
TXU proposed changing the defined term for subsection (c)(8) from "market
price" to "power purchase avoided cost" to prevent confusion as the term market
price has different meanings to different parties. AEPSC disagreed with TXU's
suggestion, arguing that "market price" was more in the spirit of the FERC
ruling and SB 7. On the other hand, Entergy REPs agreed with TXU's position
that the proposed market price definition in the proposed rule does not actually
define a market price, but instead refers to a "purchased power avoided cost."
Entergy REPs did not believe that "purchased power avoided cost" would be
a desirable formula for determining the price to be paid for as-available
QF energy. Entergy REPs indicated that this market priced definition will
often refer to REPs' costs under bilateral contracts, rather than market price.
Given that the bilateral contract price may be above or below market at times,
QFs may take advantage of making their as-available power sales at a price
that will create arbitrage opportunities and ultimately distort the market
and impose additional costs on the purchasing REP. TXU likewise commented
that a PTB REP's or POLR's avoided cost for QF power could be based on a bilateral
contract and not necessarily the market price for energy in a certain market.
Entergy REPs recommended, if a definition is included, that the commission
adhere to market standards that will treat all market participants equally
and allow recovery of all costs associated with QF transactions. Entergy REPs
further contended that the problems created by the use of the "purchased power
avoided cost" formula will also be avoided through adherence of market price
standards. TXU supported the proposed definition which utilizes individualized
determination of avoided costs.
TXU further opposed Entergy REPs' proposal to defer the creation of an
avoided cost methodology to compliance filings. TXU responded to Entergy REPs'
concerns of arbitrage opportunities resulting from contract prices for power
prices being revealed by explaining that most power purchase contracts are
not fixed price contracts. TXU further explained that most power purchase
contracts have prices determined by indices or costs that create uncertainty
in the final dollar amount paid upon settlement which also creates uncertainty
to prevent arbitrage opportunities.
The commission finds that it is appropriate to use a market-based pricing
method for calculating avoided cost as opposed to a pricing method that is
formulaic in determining avoided cost. Specifically, the commission finds
that the closest approximation of a market price for avoided cost is the market-clearing
balancing energy price for the ERCOT congestion zone in which the power is
produced, minus any administrative costs, including an appropriate share of
ERCOT-assessed penalties, and fees typically applied to power generators.
The commission finds that this price most closely reflects avoided costs for
the marginal unit of energy. To the extent that it is impossible for a REP
to predict its load with 100% accuracy, each REP will have to either buy or
sell a small amount of balancing energy. To the extent that QF energy displaces
any of the REP's demand for balancing energy, the balancing energy price is
the REP's avoided cost. Likewise, when a REP over-schedules with ERCOT, it
receives the balancing energy price for its excess energy. This is true regardless
of whether or not the REP would have overscheduled had it not fulfilled its
PURPA obligations. Therefore, the commission finds that the balancing energy
price is the most appropriate estimate of avoided cost.
The commission further finds that the balancing energy price should be
used to determine avoided cost because it reduces the ability for any interested
party to conduct in gaming. This is precisely because prices are not revealed
until after the market has cleared. If the price was known
ex ante
, then it could act as either a price floor for QFs or a price
ceiling for REPs. Either situation would encourage market manipulation. Furthermore,
while PURPA mandates that a REP must accept energy from a QF, PURPA does not
mandate that the QF must put to a particular REP. If the QF seeks a more certain
price, the commission notes that it is free to seek other markets for its
energy, such as entering into long-term bilateral contracts. The commission
finds that it is also appropriate to explicitly permit a QF to agree to commit,
on a day-ahead basis, to deliver firm power for the next day to a PTB REP.
If a QF commits to deliver firm power on a day-ahead basis, the commission
finds that rates for purchases of this power shall be based on prices for
the day that the power was actually delivered as reported or published in
an independent third party index or survey of trades of commonly traded power
products in ERCOT, provided that the index or survey is ERCOT-specific and
is based upon enough transactions to represent a liquid market, and the commitment
to deliver shall correspond with the relevant hours of delivery of those products.
The commission finds that this additional option is appropriate because it
will provide another option for QFs while preventing the arbitrage opportunities
identified by several of the commenters. Subsection (g)(3) has been added
to prescribe the rates for purchases from a QF that has committed to delivering
firm power on a day-ahead basis.
To the extent that the price of balancing energy is zero or negative, this
does not negate a REP's PURPA obligations. Rather, a non-positive price indicates
that the cost that the additional energy creates exceeds its benefits. The
fact that the price may be zero or negative reflects the risk inherent in
the current market structure and can be appropriate for non-firm energy. Finally,
the use of such a price is revenue neutral to the REP. Thus, there should
be no increase in costs to pass along to PTB REP or POLR customers.
The commission understands the argument made by the QFs and TIEC that granting
them the opportunity to sell ancillary services, such as balancing energy,
does not fulfill PURPA obligations. However, the commission finds that said
parties are misinterpreting the decision made by FERC in its May 17, 2001
"Order Granting Declaratory Order and Denying Waiver of Regulations Implementing
PURPA" in FERC Docket Nos. EL01-49-000 and EL01-60-000. The commission understands
the FERC ruling to say that the opportunity to bid into the Independent System
Operator run markets does not fulfill PURPA obligations. However, that is
not the solution that the commission adopts. Rather, the commission finds
that the PTB REPs and POLRs have an absolute obligation under PURPA to accept
energy on behalf of the QF. The commission also finds that the balancing energy
price is the appropriate determination of avoided cost and should be used
to determine proper compensation for all energy supplied to the REP by the
QF, absent any other private agreement reached by said parties.
Another issue of debate among the parties was the issue of requiring REPs
to provide certain cost data. Texas QFs argued in the alternative, that if
the circular definition of "market price" is adopted, the PTB REPs and POLRs
should be required to provide their avoided cost data to the QFs, as set forth
in 18 C.F.R. §292.302. In addition, the PTB REPs must be required to
file all agreements under which they purchase energy, and QFs must be allowed
to review such agreements to ensure that the prices they are paid truly reflect
the PTB REPs avoided cost of energy. RRI and AEPSC opposed the Texas QFs proposal
that AREPs be required to file and make public, pursuant to 18 C.F.R. §292.302,
certain detailed cost data. RRI asserted that after restructuring such requirement
upon AREPs made little practical sense. RRI reasoned that prior to restructuring,
a single entity controlled a generation and distribution "system" and that
there were no competitive concerns. Post restructuring, AREPs no longer have
such a system as contemplated by 18 C.F.R. §292.302, and thus is inapplicable.
RRI surmised that AREPs likely now rely on competitive information in order
to compete in the market, and an unequal filing requirement of such information
will provide a competitive advantage for QFs to the detriment of AREPs. AEPSC
argued that disclosure of such information would put said AREPs at a comparative
disadvantage and stunt the growth of a competitive market. AEPSC also mentioned
that the commission does not have the authority to make PTB REPs and POLRs
disclose such information.
The commission finds that disclosure of REPs cost data is not necessary
in view of the market-based pricing method adopted by the commission. Therefore,
the commission declines to adopt Texas QFs proposal and does not require the
production of cost data for the PTB REPs and POLRs.
Concern over POLR rates
Additionally, RRI, TXU, AEPSC, and OPUC commented that applying the rule
to POLRs may raise additional concerns. RRI argued that the proposed rule
would be particularly problematic for POLR service, to the point that it would
act as a disincentive for REPs to bid to become POLRs because they would be
subject to additional commission regulations beyond the POLR regulations.
TXU also suggested that by classifying POLRs as state-regulated PURPA electric
utilities that are subject to commission ratemaking authority, the commission
will discourage REPs from applying for POLR status. TXU argued that while
REPs, as electric selling entities, have the federal obligation to purchase
QF power, REPs could be discouraged knowing that by achieving POLR status
they give up their right to self-implement PURPA. AEPSC agreed with TXU and
RRI that the proposed amendments will discourage REPs from attempting to become
POLRs. AEPSC argued that the amendments would result in the QF favoring puts
to the POLR REP, increase the uncertainty associated with providing such service,
and lead to an increase in POLR rates.
OPUC made the point that POLR rates are already high because it is difficult
for the POLR to predict its load, and therefore use hedging contracts to control
the price of their inputs. Forcing the POLR to accept stochastic QF puts will
only exacerbate this effect. OPUC stated that accepting QF power may result
in an inefficient allocation of resources that could cause the costs associated
with providing PTB and POLR services to increase. OPUC pleaded that the AREP
not be allowed to use such an increase in costs to justify an increase in
rates for PTB and POLR customers. OPUC further argued that prices for QF power
should be determined through market-based methods, rather than through formulaic
tariffs that set avoided cost. Using tariffs will have the effect of creating
a price floor, and hence, encourage gaming. OPUC was concerned that the proposed
rule does not mandate a market-based approach, but rather adopts it if and
only if the QF agrees to such a method. In response to OPUC, TXU asserted
that an appropriate avoided cost determination would nullify OPUC's concern
that imposing the PURPA obligations on the PTB REPs and POLRs will drive up
retail rates for residential and small commercial customers. TXU stated that
an appropriate avoided cost determination will have no effect on PTB REPs'
and POLRs' purchase power costs as the idea is for the PURPA electric utility
to pay no more for QF power than it would have paid to otherwise obtain power.
The commission agrees with the concerns raised by OPUC, RRI, TXU, and AEPSC
regarding the potential disincentives that this rule may have on REPs seeking
to become POLRs. However, the commission finds that PURPA requires state commissions
to implement PURPA for all entities over which the state commission has ratemaking
authority, which this commission clearly does have with respect to POLRs.
As a result, the commission declines to make this rule applicable to POLRs,
and instead will address PURPA implementation for the POLR REPs on a case-by-case
basis.
Comments on specific rule sections
§25.242(b) - Application
Brazos offered clarifying language to dismiss any misconceptions that even
as a POLR, this section would not be applicable to an electric cooperative.
Brazos explained that in PURA §41.053 an electric cooperative may designate
itself or another entity to be the POLR within the electric cooperative's
certificated service area. If the electric cooperative acts as the POLR, the
electric cooperative must offer the customer the standard retail service package
as approved by the electric cooperative's board of directors. Brazos proposed
language to clarify the idea that the commission has no jurisdiction over
the rates of electric cooperatives or municipalities. AEPSC noted that the
comments made by Brazos that the proposed rule does not apply to cooperatives,
even if they are acting as POLR, underscored its jurisdictional concerns.
For the reasons discussed above in
Concern over
POLR rates
, the commission declines to implement PURPA over POLRs through
this rulemaking. Thus, the commission does not believe it necessary to adopt
Brazos' proposed clarification language. Notwithstanding, PURA Chapter 41
has altered the commission's jurisdiction over electric cooperatives much
more comprehensively than that over REPs. The commission asserts jurisdiction
over PTB REPs and POLRs in part based on the ratemaking authority it possesses
through PURA Chapter 39. PURA Chapter 41 specifically places ratemaking authority
over electric cooperatives in the hands of the cooperative's board of directors.
The electric cooperative board of directors' ratemaking authority extends
to electric cooperative POLRs pursuant to PURA §41.053(d).
§25.242(c) -Definitions
TXU offered amendments to make the definition of "cost of decremental energy"
in subsection (c)(3) consistent with the use of the term in proposed subsection
(i)(3). AEPSC commented that subsection (c)(3) should be clarified and specifically
reference electric utilities, not simply utilities.
The commission declines to adopt the revisions recommended by TXU and AEPSC.
The commission finds that the term decremental energy only exists in subsection
(i)(3) which applies to electric utilities as defined in subsection (c)(4).
First Choice expressed concern about the usage of subsections (c)(1) and
(c)(8) under the amended rule.
The commission acknowledges First Choice's concerns regarding amendments
made to (c)(1) addressing the definition of "avoided costs" and (c)(8) adding
a definition of "market price." However, the commission adopts the definitions
changes made based on its reasoning expressed in this preamble.
§25.242(f) - PTB REP and electric utility
obligations
§25.242(f)(1) - Obligation to purchase from qualifying facilities
AEPSC commented that subsection (f)(1)(A)(i) and (ii) should be deleted.
They are confusing and not applicable under the new ERCOT market structure.
The commission finds subsection (f)(1)(A)(i) and (ii) still applies to
electric utilities as defined in subsection (c)(4). In the case of PTB REPs,
it reiterates the point that delivery from the QF may be directly connected
via the affiliated TDU to the facility or via transmission to PTB REPs located
in other TDU service areas.
AEPSC commented that subsection (f)(1)(B) should be amended to specifically
address the 90 day notice requirement for PTB REPs and POLRs.
The commission notes that many of the provisions in (f)(1)(B) relate to
interconnection of the QF to the transmission and/or distribution grid and
therefore, are not applicable to PTB REPs and POLRs. Additionally, for the
reasons discussed above in
Concern over POLR rates
, the commission declines to implement PURPA over POLRs through this
rulemaking. However, the commission agrees with AEPSC that similar timelines
for finalizing agreements to purchase energy should be completed in a timely
manner but does not agree that such agreements should take 90 days to reach
given the prescriptive avoided cost methodology in this rule. The commission
adds new subsection (f)(1)(C) to clarify this obligation.
§25.242(f)(2) Obligation to sell to qualifying facilities
AEPSC commented that subsection (f)(2) should be changed to only apply
to POLR REPs. AEPSC argued that the commission does not have the authority
to order any REP to provide service to a non-PTB customer. Alternatively,
AEPSC suggested that the phrase "market based rates" be changed to "mutually
agreed upon rates" to circumvent this problem.
TXU opposed TIEC's proposal to require PTB REPs and POLRs to sell energy
and capacity to QFs at the REPs avoided cost plus reasonable administrative
expenses. TXU contended that PURPA rules require a PURPA electric utility
to sell to QFs at rates that are nondiscriminatory. TXU further argued that
there is no precedent to use avoided costs to determine rates for energy and
capacity sold to QFs. First Choice expressed concern about the lack of a definition
for "market based rates" in subsection (f)(2).
Entergy REPs generally agreed with proposed subsection (f)(2), which governs
sales to QFs. However, Entergy REPs stated that this section fails to explicitly
provide for recovery of incidental administrative, billing and metering costs
from QFs, and expressed preference that such provision be explicitly inserted
in the subsection (f)(2). Nonetheless, Entergy REPs believed that full cost
recovery is implicit in the market standard contained in the proposed rule.
Entergy REPs, in reply comments, disagreed with TIEC's proposed pricing mechanism
that would price sales to QFs at avoided costs plus an allowance for administrative
costs, stating that such mechanism would not recover demand-related charges
that are often associated with sales to QFs.
The commission finds that its jurisdiction is limited to POLR and PTB REPs.
For the reasons discussed above in
Concern over POLR
rates
, the commission declines to implement PURPA over POLRs through
this rulemaking. The commission finds that the avoided cost for PTB REPs is
the MCPE for the ERCOT congestion zone in which the power is produced, minus
any administrative costs, including an appropriate share of ERCOT-assessed
penalties, and fees typically applied to power generators. The commission
finds, pursuant to PURPA, that QFs selling to non-POLR and non-PTB REPs should
self-implement PURPA and set avoided cost at a mutually agreeable price and
in a non-discriminatory manner. The commission also finds that it is not a
commission requirement but a PURPA requirement that electric utilities sell
standby, back up, and maintenance power to QFs at market rates. The commission
further finds that this requirement has been harmonized by allowing these
rates to be at the market value for these services.
§25.242(f)(4), Transmission to other electric utilities
AEPSC commented that subsection (f)(4) should be deleted because it is
confusing and not applicable under the new ERCOT market structure.
The commission disagrees with AEPSC's comment that subsection 25.242(f)(4)
should be deleted. QFs receiving or providing electricity from the grid will
require transmission service. The obligations and rules of Subchapter I continue
to govern transmission service irrespective of the new ERCOT market structure.
The rules of Subchapter I were developed to support the new ERCOT market structure
and the commission declines to delete this subsection.
§25.242(f)(5), PTB REP and POLR scheduling with qualifying facilities
TXU recommended deletion of proposed subsection (f)(5) as it regards the
use of dynamic scheduling and responsibility transfers. TXU supported the
initial comments of RRI and OPUC as well as echoed their comments that these
forms of scheduling are not yet part of the ERCOT protocols. Further, TXU
deemed that dynamic scheduling and responsibility transfers are not needed
for QF puts and that static scheduling will accomplish QF puts leaving QFs
exposed to the same financial imbalance concerns that apply to all PGCs in
the new market. TXU also urged that the commission allow QFs and purchasing
utilities to continue to work together to determine appropriate means for
the technical transactions as it done in the past and not to use the rule
to fix technical specifications that will likely change and evolve over time.
Likewise, AEPSC urged the commission to reject Dynamic Resource Scheduling
(DRS) because many different generators serve unpredictable loads and requiring
DRS would give QFs an unfair advantage over other generators. AEPSC further
contended that DRS will result in increased costs for PTB REPs and POLRs as
certainty commands a price premium and that requiring dynamic scheduling would
discourage efficient production of electricity. Furthermore, AEPSC argued
it would require the REP to seek additional flexibility from its other suppliers.
In this vein, AEPSC argued that subsection (f)(5), which requires PTB and
POLR REPs to offer DRS, should be deleted.
Likewise, OPUC asked that the commission delete subsection (f)(5), requiring
the availability of DRS. Although this service has been traditionally provided
by integrated utilities, the new market structure does not support this because
the generation and control areas no longer operate in a bundled manner.
RRI also argued that DRS is an optional service and is not necessary for
QFs to deliver PURPA put energy nor are they required by ERCOT, although efforts
are underway at ERCOT to define how such scheduling might work. RRI recommended
revisions to subsection (f)(5) to indicate the service is optional. RRI asserted
that static scheduling is adequate and will be used by other PGCs on a regular
basis. RRI argued that QFs should be subject to the same balancing energy
market exposure taken by other PGCs in the ERCOT market, if scheduling is
not met. RRI argued that QFs would be advantaged and have arbitrage opportunities
should they be allowed to avoid such exposure. RRI also suggested that the
proposed rule be clarified to indicate that responsibility transfers can only
be undertaken by QSEs on behalf of REPs and QFs under the ERCOT Protocols,
and that the ERCOT Protocols allow QSEs to offer responsibility transfers
at their option under mutually agreeable contract terms.
Texas QFs and TIEC argued that it is imperative that DRS and/or responsibility
transfers be utilized to accommodate PURPA energy, due to the intermittent,
variable, non-firm and uncontrollable nature of the energy produced by QFs
in excess of the needs of their steam hosts. TIEC also argued that the commission
should require, through the rulemaking, that contracts between entities obligated
to purchase PURPA power and QSEs make DRS available as quickly as possible
if it not already available without "tying" such other services that a QF
might be required to purchase.
The commission agrees with the Texas QFs and TIEC about DRS to the extent
that it is desirable to better accommodate the fluctuating nature of their
production. It does not agree with the recommendations that subsection (f)(5)
be deleted. DRS should remain available as an option subject to the ability
of the QF and its QSE to meet ERCOT's protocol requirements. The commission
disagrees with the assertions that DRS would give the QFs an unfair competitive
advantage because DRS is available to any energy supplier/QSE willing to utilize
it.
§25.242(g) - Rates for purchases from a qualifying
facility
§25.242(g)(2) - market based rates
OPUC stated that the term "just and reasonable operating expenses" is unclear
and asked that the last sentence of subsection (g)(2) be deleted. OPUC claimed
that this sentence could conflict with the PTB rule and create confusion.
TXU, however, opposed OPUC's recommendation to delete the "just and reasonable
operating expenses" provision from this subsection because it would be unfair
not to allow PTB REPs and POLRs to recover costs from their customers.
AEPSC argued subsection (g)(2) should be deleted because the method of
calculating avoided cost has not been fully determined and could result in
the disclosure of a REP's cost information, putting it at a competitive disadvantage.
AEPSC also commented that subsection (g)(2) contains a typographical error
that should be corrected.
TXU suggested amending the second to last sentence of proposed subsection
(g)(2) to create consistency between the subsection and PURPA rules at 18
C.F.R. §292.304(5).
TIEC supports the language proposed by Texas QFs as a modification of the
definition of market price with the provision that if there is so much PURPA
power available that more than one unit (or more than one type of unit) is
avoided, then the heat rate and fuel index should be the average of the stack
of all units avoided.
For the reasons discussed above in
Concern over
POLR rates
, the commission declines to implement PURPA over POLRs through
this rulemaking. The commission finds that this section relates to longer
term purchases of energy and capacity and as such, in the context of PTB REPs
should be fully negotiated between buyers and sellers in the competitive wholesale
market. Alternatively, QFs may sell energy on a nonfirm, as available basis,
and the commission finds that the MCPE is the appropriate estimate of avoided
cost as defined in subsection (i)(4). Additionally, the term "just and reasonable
operating expenses" does not apply in the context of a PTB REP as all of its
purchases, including those from QFs, will be done at market based rates. Subsection
(g)(2) has been modified to clarify that the term "utility" refers to still
bundled electric utilities.
§25.242(i) - Tariffs setting out the methodologies
for purchases of nonfirm power from a qualifying facility
AEPSC commented that subsection (i) should be clarified in the following
manner: Paragraphs (1) and (3) apply to electric utilities and paragraphs
(2) and (4) apply to PTB and POLR REPs. AEPSC sought clarification whether
PTB REPs and POLRs must file actual tariffs or simply a description of the
methodology that will be used to determine rates and whether PTB REPs and
POLRs have the authority to choose which method will be used when either the
QF agrees to the method or when the QF chooses the method.
§25.242(i)(2)
TXU proposes amending the term "market price" to read "power purchase avoided
cost" to be consistent with TXU's proposal for change in proposed subsection
(c)(8). AEPSC commented that subsection (i)(2) should be clarified that the
period of sale is negotiated, as this section deals with average costs.
Entergy REPs, in reply comments, disagreed with TXU's suggestion that proposed
subsection (i)(2) be revised to refer to average "purchased power avoided
costs" rather than average market price. Entergy REPs reason, as with its
general discussion concerning avoided costs determination, is that QFs will
benefit from arbitrage opportunities that would ultimately distort market
prices with added costs to REPs. The Entergy REPs also recommended deletion
of any reference to "average market price" or TXU's suggested "purchased power
avoided cost" because parties should be free to enter into contractual arrangements
based on mutually agreeable terms and conditions.
For the reasons discussed above in
Concern over
POLR rates
, the commission declines to implement PURPA over POLRs through
this rulemaking. Concerning PTB REPs, the commission agrees with the concerns
raised and has made corresponding revisions to the language in subsection
(i)(2) and (i)(4) to address these concerns. Particularly, the commission
has now revised subsection (i)(2) to specifically address the manner in which
PTB REPs and QFs can mutually agree to the terms of rates for energy sales
to QFs that are different than the market price as defined in subsection (c)(8).
Nevertheless, the commission believes what the rate is called is irrelevant
to the issue to the extent that both parties in question agree on the price
for QF energy.
§25.242(i)(4)
OPUC recommended that subsection (i)(4) be amended such that "shall" replaces
"may," and that the phrase "at the option of the qualifying facility" be deleted.
TXU opposed OPUC's recommendation, arguing that it would be unfair not to
allow PTB REPs and POLRs to recover costs from their customers.
The commission disagrees with OPUC's recommendation. However, in light
of the above decision to revise subsection (i)(2) with regards to PTB REPs
and QFs reaching mutually agreeable terms for nonfirm sales to QFs, the commission
has made corresponding changes to subsection (i)(4). The commission revises
subsection (i)(4) to allow rates for purchases of nonfirm power to be based
on the market price of energy (as defined in (c)(8) as MCPE) at the time of
the sale to the QF, unless alternative arrangements have been made pursuant
to subsection (i)(2).
§25.242(i)(5)
Texas QFs commented that they object to subsection (i)(5) which states
that PTB REPS and POLRs must file with the commission a description of the
methodology that will be used in calculating these rates for purchase, to
the extent that it does not explicitly require commission approval for the
methodology that will be used to calculate the individual utilities' avoided
costs. Texas QFs stated that they want an opportunity for a contested case
proceeding with commission approval of the ultimate methodology.
The commission deletes subsection (i)(5) given that it has adopted the
MCPE as market prices. Because, through the adoption of the MCPE no methodology
will need to be established, it is unnecessary for PTB REPs to make filings
with the commission.
§25.242(j), Periods during which purchases
not required
§25.242(j)(1)
TXU offered amended language throughout the subsection to carry the idea
that in certain circumstances, electric utilities, PTB REPs and POLRs are
permitted to decline to purchase QF power. TXU added that resource ramp limitations
are not the only operational circumstances that could cause electric utilities,
PTB REPs and POLRs to be in a position to pay more than their avoided costs
for QF power.
AEPSC argued against subsection (j)(1), stating that the ability of a PTB
REP or POLR to cease delivery because of operation concerns conflicts with
the ability for the QF to obtain dynamic scheduling. There is no opportunity
to provide notice under dynamic scheduling. AEPSC further argued that in addition
to being an operational limitation, that ramp rate limitations may also be
contractual limitations that a REP may have with its supplier. AEPSC stated
that the commission should clarify that "utility" should refer to PTB REPs
and POLRs and that the last sentence of the section does not clearly state
the PTB REP's and POLR's obligations.
AEPSC commented that the commission's authority to verify operational limitations
conflicts with the QF's ability to request dynamic scheduling in subsection
(j)(3).
Additionally, RRI asserted that the proposed rule should be modified to
ensure that the amount of the PURPA put energy scheduled or delivered to the
PTB REP or POLR does not exceed the total load associated with those services.
RRI recommended language to be added as subsection (j)(4), consistent with
this recommendation.
The commission agrees with the parties that the term utility, in this rulemaking,
should also apply to PTB REPs. It also agrees with RRI that language should
be added to limit the amount of energy that may be put to a PTB REP to no
more than the PTB REP needs to serve its load. If a QF chooses to use DRS,
it does so with the understanding that it may have a different degree of notice
available in case of curtailments due to operational concerns. The commission
has made corresponding revisions to subsection (j)(4) consistent with the
position that the amount of energy put may be limited.
§25.242(l), Interconnection costs
TXU proposed language to clarify that subsection (l) is addressing "electric"
utility's Open Access Transmission Tariff.
The commission agrees with TXU and added "electric" in subsection (l) for
clarity.
§25.242(m), System emergencies
AEPSC commented that subsection (m) it is not clear as to why PTB and POLR
REPs cannot discontinue purchases and sales during a system emergency. The
subsection should be amended or clarified.
The commission declines to make the revision suggested by AEPSC because
the proposed rule did not recommend a change to this subsection. Therefore,
no substantive change can be made to this provision at this time. However,
the commission notes that a comparable provision exists in the FERC's rules
relating to PURPA obligations at 18 C.F.R. §292.307.
25.242(n), Enforcement
AEPSC requested that the commission reject Texas QFs' suggestion that the
commission evaluates via a contested case the compliance filings of each PTB
and POLR REP. AEPSC argued that contested cases are not in the spirit of competition
and that the commission should rely on market based prices instead.
In reply comments, Entergy REPs disagreed with Texas QFs' proposal that
each implementation filing under the proposed rule be subject to review in
a contested proceeding. Entergy REPs argued that affected parties have the
ability under PURA and the commission's rules to initiate a complaint proceeding
if disagreement exists with the implementation filing.
The commission believes Entergy's and AEPSC's concerns have been addressed
by the deletion of subsection (i)(5).
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 amendment is adopted under the Public Utility Regulatory
Act, Texas Utilities Code Annotated, §11.002 (Vernon 1998 & Supplement
2002) (PURA), 16 U.S.C. §824a-3(f) (2000), and 18 C.F.R. Part 292 (2001)
which grants the Public Utility Commission the authority to make and enforce
rules necessary to protect customers of electric services consistent with
the public interest; PURA §14.002 which provides the commission with
the authority to make and enforce rules reasonably required in the exercise
of its powers and jurisdiction; PURA §35.061 which provides the commission
with the authority to make and enforce rules to encourage the economical production
of electric energy by qualifying facilities; and 16 U.S.C. §824a-3(f)
(2000) and 18 C.F.R. Part 292 (2001), which require state regulatory authorities
to implement federal Public Utility Regulatory Policies Act regulations addressing
arrangements between certain entities that sell electric energy.
Cross reference to statutes: Public Utility Regulatory Act §§11.002,
14.002, and 35.061; 16 U.S.C. §824a-3; and 18 C.F.R. Part 292.
§25.242.Arrangements Between Qualifying Facilities and Electric Utilities.
(a)
Purpose. The purpose of this section is to regulate the
arrangements between qualifying facilities, retail electric providers with
the price to beat obligation (PTB REPs), and electric utilities as required
by federal and state law in a manner consistent with the development of a
competitive wholesale power market.
(b)
Application. This section shall apply to all PTB REPs,
transmission and distribution utilities (TDUs), and electric utilities in
Texas. This section shall not apply to municipal utilities, river authorities,
or electric cooperatives.
(c)
Definitions. The following words and terms, when used in
this section, shall have the following meanings, unless the context clearly
indicates otherwise:
(1)
Avoided costs -- The incremental costs to a PTB REP, or
electric utility of electric energy, which, but for the purchase from the
qualifying facility or qualifying facilities, such PTB REP or electric utility
would generate itself or purchase from another source.
(2)
Back-up power -- Electric energy or capacity supplied to
replace energy or capacity ordinarily generated by a qualifying facility's
own generation equipment during an unscheduled outage of the qualifying facility.
(3)
Cost of decremental energy -- The cost savings to a utility
associated with the utility's ability to back-down some of its units or to
avoid firing units, or to avoid purchases of power from another utility because
of purchases of power from qualifying facilities.
(4)
Electric utility -- For purposes of this section, an integrated
investor-owned utility that has not unbundled in accordance with Public Utility
Regulatory Act §39.051.
(5)
Firm power -- From a qualifying facility, power or power-producing
capacity that is available pursuant to a legally enforceable obligation for
scheduled availability over a specified term.
(6)
Host utility -- The utility with which the qualifying facility
is directly interconnected.
(7)
Maintenance power -- Electric energy or capacity supplied
during scheduled outages of the qualifying facility.
(8)
Market price -- The market-clearing price of energy (MCPE)
in the balancing energy market for the Electric Reliability Council of Texas
(ERCOT) congestion zone in which the power is produced, minus any administrative
costs, including an appropriate share of ERCOT-assessed penalties and fees
typically applied to power generators.
(9)
Non-firm power from a qualifying facility -- Power provided
under an arrangement that does not guarantee scheduled availability, but instead
provides for delivery as available.
(10)
Parallel operation -- A mode of operation which enables
a qualifying facility to export automatically any electric capacity which
is not consumed by the qualifying facility or the user of the qualifying facility's
output. Parallel operation results in three possible states of operation at
any point in time:
(A)
The qualifying facility is generating an amount of capacity
that is less than the customer's load. The customer is therefore a net consumer.
(B)
The qualifying facility is generating an amount of capacity
that is more than the customer's load. The customer is therefore a net producer.
(C)
The qualifying facility is generating an amount of capacity
that is equal to the customer's load. The customer is therefore neither a
net producer nor a net consumer.
(11)
Purchase -- The purchase of electric energy or capacity
or both from a qualifying facility by a PTB REP or electric utility.
(12)
Purchasing utility -- The electric utility that is purchasing
a qualifying facility's capacity and/or energy.
(13)
Quality of firmness of a qualifying facility's power --
The degree to which the capacity offered by the qualifying facility is an
equivalent quality substitute for firm purchased power or an electric utility's
own generation. At a minimum the following factors should be considered in
determining quality of firmness:
(A)
reliability of generation and interconnection;
(B)
forced outage rate;
(C)
availability during peak periods;
(D)
the terms of any contract or other legally enforceable
obligation, including, but not limited to, the duration of the obligation,
performance guarantees, termination notice requirements, and sanctions for
noncompliance;
(E)
maintenance scheduling;
(F)
availability for system emergencies, including the ability
to separate the qualifying facility's load from its generation;
(G)
the individual and aggregate value of energy and capacity
from qualifying facilities on the electric utility's system;
(H)
other dispatch characteristics;
(I)
reliability of primary and secondary fuel supplies used
by the qualifying facility; and
(J)
impact on utility system stability.
(14)
Retail electric provider with the price to beat obligation
(PTB REP) -- A REP that makes available a PTB pursuant to PURA §39.202.
(15)
Sale -- The sale of electric energy or capacity or both
supplied to a qualifying facility.
(16)
Supplementary power -- Electric energy or capacity regularly
used by a qualifying facility in addition to that which the facility generates
itself.
(17)
System emergency -- A condition on a utility's system
that is likely to result in imminent significant disruption of service to
customers or is imminently likely to endanger life or property.
(18)
Transmission and distribution utility (TDU) -- As defined
in §25.5 of this title (relating to Definitions).
(d)
Negotiation and filing of rates.
(1)
Negotiated rates or terms. Nothing in this section shall:
(A)
limit the authority of any PTB REP or electric utility
or any qualifying facility to agree to a rate for any purchase, or terms or
conditions relating to any purchase, which differs from the rate or terms
or conditions that would otherwise be required by this section; or
(B)
affect the validity of any contract entered into between
a qualifying facility and a PTB REP or electric utility for any purchase before
the adoption of this section.
(2)
Filing of rates. All rates for sales to qualifying facilities,
contractual or otherwise, shall be contained in the schedule of rates of the
electric utility filed with the commission.
(e)
Availability of electric utility system cost data.
(1)
Applicability. Paragraph (2) of this subsection applies
to large electric utilities whose total sales of electric energy for purposes
other than resale exceeded 500 million kilowatt-hours during any calendar
year beginning after December 31, 1975, and before the immediately preceding
calendar year. Paragraph (3) of this subsection applies to all other electric
utilities.
(2)
Data request for large electric utilities. Large utilities
shall file the following data:
(A)
the estimated avoided cost on the electric utility's system,
solely with respect to the energy component, for various levels of purchases
from qualifying facilities. Such levels of purchases shall be stated in blocks
of one, ten and 100 megawatts or not more than 10% of the system peak demand
for systems of less than 1,000 megawatts. The avoided cost shall be stated
on a cents-per-kilowatt-hour basis, during daily and seasonal peak and off-
peak periods, by year, for the current calendar year and each of the next
nine years.
(B)
the electric utility's plan for the addition of capacity
by amount and type, for purchases of firm energy and capacity, and for capacity
retirements for each year during the succeeding nine years.
(C)
for the current year and each of the next nine years, the
estimated capacity costs at completion of the planned capacity additions and
planned capacity purchases, on the basis of dollars-per-kilowatt, and the
associated energy costs of each unit, expressed in cents per kilowatt-hour.
These costs shall be expressed in terms of individual generating units and
of individual planned firm purchases. Such information shall be submitted
in accordance with the Federal Energy Regulatory Commission Regulations, 18
Code of Federal Regulations, §292.302 and shall be sufficient for qualifying
facilities to reasonably estimate the utility's avoided cost. Accompanying
each filing pursuant to this rule shall be a detailed explanation of how the
data was determined, including sources and assumptions employed.
(3)
Special requirements for small electric utilities. Affected
utilities shall, upon request:
(A)
provide to an interested person comparable data to that
required under paragraph (2) of this subsection to enable qualifying facilities
to estimate the electric utility's avoided costs; or
(B)
with regard to an electric utility that is legally obligated
to obtain all its requirements for electric energy and capacity from another
electric utility, provide to an interested person the data of its supplying
utility and the rates at which it currently purchases such energy and capacity.
(4)
Filing date. By February 15 each year, large electric utilities
shall file with the commission and shall maintain for public inspection the
data set forth in paragraph (2) of this subsection.
(f)
PTB REP and electric utility obligations.
(1)
Obligation to purchase from qualifying facilities.
(A)
In accordance with this subsection and subsection (g) of
this section, each PTB REP and electric utility shall purchase any energy
that is made available from a qualifying facility:
(i)
directly to the PTB REP or electric utility; or
(ii)
indirectly to the PTB REP or electric utility in accordance
with paragraph (4) of this subsection.
(B)
Each electric utility shall purchase energy from a qualifying
facility with a design capacity of 100 kilowatts or more within 90 days of
being notified by the qualifying facility that such energy is or will be available,
provided that the electric utility has sufficient interconnection facilities
available. If an agreement to purchase energy is not reached within 90 days
after the qualifying facility provides such notification, the agreement, if
and when achieved, shall bear a retroactive effective date for the purchase
of energy delivered to the electric utility correspondent with the 90th day
following such notice. If the electric utility determines that adequate interconnection
facilities are not available, the electric utility shall inform the qualifying
facility within 30 days after being notified for distribution interconnection,
or within 60 days for transmission interconnection, giving the qualifying
facility a description of the additional facilities required as well as cost
and schedule estimates for construction of such facilities. If an agreement
to purchase energy is not reached upon completion of construction of the interconnection
facilities or 90 days after notification by the qualifying facility that such
energy is or will be available, the agreement, if and when achieved, shall
bear a retroactive effective date for the purchase of energy delivered to
the electric utility correspondent with the time of interconnection or the
90th day, whichever is later. Nothing in this subsection shall be construed
in a manner that would preclude a qualifying facility from notifying and contracting
for energy with a utility for sale of energy prior to 90 days before delivery
of such energy.
(C)
Each PTB REP shall purchase energy from a qualifying facility
with a design capacity of 100 kilowatts or more within a timely fashion after
being notified by the qualifying facility that such energy is or will be available.
(2)
Obligation to sell to qualifying facilities. In accordance
with subsection (k) of this section, each electric utility shall sell any
energy and capacity requested to any qualifying facility located within the
electric utility's service area. Each PTB REP shall also sell any energy requested
to any qualifying facility; however, those sales shall be at market based
rates. Nothing shall restrict the ability of any qualifying facility to purchase
energy from any REP.
(3)
Obligation to interconnect. The obligation of electric
utilities and TDUs to interconnect with qualifying facilities is set forth
in Subchapter I of this chapter (relating to Transmission and Distribution)
with respect to qualifying facilities seeking to interconnect with TDUs in
the ERCOT, and in the respective electric utility's Open Access Transmission
Tariff for electric utilities in non-ERCOT power regions.
(4)
Transmission to other electric utilities. Transmission
service provided by an electric utility to a qualifying facility shall be
governed by Subchapter I of this chapter.
(5)
PTB REP and scheduling with qualifying facilities. A PTB
REP shall use dynamic resource scheduling or responsibility transfer in ERCOT
with any qualifying facility that requests such scheduling, as permitted by
ERCOT. The PTB REP's cost of using dynamic resource scheduling or responsibility
transfer attributable solely to purchases from qualifying facilities shall
be charged to qualifying facilities that use such scheduling. If a qualifying
facility uses static scheduling, the qualifying facility shall bear the costs
for any imbalances resulting from the qualifying facility's failure to submit
a schedule or to comply with the schedule.
(g)
Rates for purchases from a qualifying facility.
(1)
Rates for purchases of energy and capacity from any qualifying
facility shall be just and reasonable to the customers of the electric utility
or PTB REP and in the public interest, and shall not discriminate against
qualifying cogeneration and small power production facilities.
(2)
Rates for purchases of energy and capacity from any qualifying
facility shall not exceed avoided cost. Rates for purchase shall be based
upon a market-based determination of avoided costs over the specific term
of the contract or other legally enforceable obligation, the rates for such
purchase do not violate this subsection if the rates for such purchase differ
from avoided cost at the time of delivery. Payments which do not exceed avoided
cost shall be found to be just and reasonable operating expenses of the electric
utility.
(3)
A QF may agree to commit, on a day-ahead basis, to deliver
firm power for the next day to a PTB REP. Rates for purchase of this power
shall be based on prices for the day that the power was actually delivered
as reported or published in an independent third party index or survey of
trades of commonly traded power products in ERCOT, provided that the index
or survey is ERCOT-specific and is based upon enough transactions to represent
a liquid market, and the commitment to deliver shall correspond with the relevant
hours of delivery of those products.
(h)
Standard rates for purchases from qualifying facilities
with a design capacity of 100 kilowatts or less.
(1)
There shall be included in the tariffs of each electric
utility standard rates for purchases from qualifying facilities with a design
capacity of 100 kilowatts or less. The rates for purchases under this paragraph:
(A)
shall be consistent with subsection (g) of this section,
as it concerns purchases from a qualifying facility;
(B)
shall consider the aggregate capacity value provided by
multiple qualifying facilities with a design capacity of 100 kilowatts or
less; and
(C)
may differentiate among qualifying facilities using various
technologies on the basis of the supply characteristics of the different technologies.
(2)
Terms and conditions unique to qualifying facilities with
a design capacity of 100 kilowatts or less such as metering arrangements,
safety equipment requirements, liability for injury or equipment damage, access
to equipment and additional administrative costs, if any, shall be included
in a standard tariff.
(3)
The standard tariff shall offer at least the following
options:
(A)
parallel operation with interconnection through a single
meter that measures net consumption;
(i)
net consumption for a given billing period shall be billed
in accordance with the standard tariff applicable to the customer class to
which the user of the qualifying facility's output belongs;
(ii)
net production will not be metered or purchased by the
utility and therefore there will be no additional customer charge imposed
on the qualifying facility;
(B)
parallel operation with interconnection through two meters
with one measuring net consumption and the other measuring net production;
(i)
net consumption for a given billing period shall be billed
in accordance with the standard tariff applicable to the customer class to
which the user of the qualifying facility's output belongs;
(ii)
net production for a given billing period shall be purchased
at the standard rate provided for in paragraph (1)(A) and (B) of this subsection;
(C)
interconnection through two meters with one measuring all
consumption by the customer and the other measuring all production by the
qualifying facility;
(i)
all consumption by the customer for a given billing period
shall be billed in accordance with the standard tariff applicable to the customer
class to which the customer would belong in the absence of the qualifying
facility;
(ii)
all production by the qualifying facility for a given
billing period shall be purchased at the standard rate provided for in paragraph
(1)(A) and (B) of this subsection.
(4)
In addition, each electric utility shall offer qualifying
facilities using renewable resources with an aggregate design capacity of
50 kilowatts or less the option of interconnecting through a single meter
that runs forward and backward.
(A)
Any consumption for a given billing period shall be billed
in accordance with the standard tariff applicable to the customer class to
which the user of the qualifying facility's output belongs.
(B)
Any production for a given billing period shall be purchased
at the standard rate provided for in paragraph (1)(A) of this subsection.
(5)
Interconnection requirements necessary to permit interconnected
operations between the qualifying facility and the utility and the costs associated
with such requirements shall be dealt with in a manner consistent with Subchapter
I of this chapter.
(6)
The rates, terms and conditions contained in the standard
tariff for qualifying facilities with a design capacity of 100 kilowatts or
less shall be subject to review and revision by the commission.
(7)
Requirements for the provision of insurance under this
subsection shall be of a type commonly available from insurance carriers in
the region of the state where the customer is located and for the classification
to which the customer would belong in the absence of the qualifying facility.
An enhancement to a standard homeowner's or farm and ranch owner's policy
containing adequate liability coverage and having the effect of adding the
electric utility as an additional insured or named insured is one means of
satisfying the requirements of this paragraph. Such policies shall in each
instance be on a form approved or promulgated by the Texas Department of Insurance
and issued by a property or casualty insurer licensed to do business in the
State of Texas.
(i)
Tariffs setting out the methodologies for purchases of
nonfirm power from a qualifying facility. Tariffs setting out the methodologies
for purchases of nonfirm power from a qualifying facility shall be filed with
the commission based on one of the following approaches:
(1)
Rates for purchases of nonfirm power may, by agreement
of both the electric utility and the qualifying facility, be based on the
utility's average avoided energy costs. Administrative, billing, and metering
costs shall be recovered through a monthly customer charge to the qualifying
facility.
(2)
PTB REPs and QFs may mutually agree to rates for purchases
of nonfirm power that differ from the rates described in paragraph (4) of
this subsection. Any such agreements shall be made on a nondiscriminatory
basis. Such agreements may include provisions to prevent the potential for
arbitrage.
(3)
Rates for purchases of nonfirm power may, at the option
of the qualifying facility, be based on the full cost at the time of delivery
of decremental energy that would have been incurred by the electric utility
had the qualifying facility not been in operation.
(A)
The following factors should be considered in the calculation
of the cost of decremental energy:
(i)
fuel costs;
(ii)
variable operating and maintenance costs;
(iii)
line losses;
(iv)
heat rates;
(v)
cost of purchases from other sources;
(vi)
other energy-related costs;
(vii)
capacity costs, if, as a class, qualifying facilities
providing nonfirm energy offer some predictable capacity; and
(viii)
for short term energy purchases, the time and quantity
of energy furnished.
(B)
If practical, the avoided cost should be determined by
calculating by time period, using the utility's economic dispatch model (or
comparable methodology), the difference between the cost of the total energy
furnished by both the qualifying facility and the utility, computed as though
the energy furnished by the qualifying facility had been furnished by the
utility, and the actual cost of energy furnished by the utility.
(C)
The economic dispatch model should take into consideration
the following factors:
(i)
fuel costs;
(ii)
variable operating and maintenance costs;
(iii)
line losses;
(iv)
heat rates;
(v)
purchased power opportunity;
(vi)
system stability; and
(vii)
operating characteristics.
(D)
Time periods should be hourly if the utility has an automated
economic dispatch model available; otherwise the shortest reasonable time
period for which costs can be determined should be used.
(E)
Administrative, billing, and metering costs shall be recovered
through a monthly customer charge to the qualifying facility.
(4)
Rates for purchases of nonfirm power shall be based on
the market price of energy at the time of sale from the QF unless other arrangements
have been made in accordance with paragraph (2) of this subsection. Administrative,
billing, and metering costs shall be recovered through a monthly customer
charge to the qualifying facility. Such agreements may include provisions
to prevent the potential for arbitrage.
(j)
Periods during which purchases not required.
(1)
Any PTB REP or electric utility which gives notice to each
affected qualifying facility in time for the qualifying facility to cease
delivery of energy or capacity to the PTB REP, or electric utility will not
be required to purchase electric energy or capacity during any period during
which, due to operational circumstances, including resource ramp rate limitations
that could cause imbalances or the amount of energy put by the QF exceeds
the PTB REP's load, purchases from qualifying facilities will result in costs
greater than those which the electric utility would incur if it did not make
such purchases, but instead generated an equivalent amount of energy itself,
provided, however, that this subsection does not override contractual obligations
of the PTB REP or electric utility to purchase from a qualifying facility.
(2)
Any PTB REP or electric utility which fails to give notice
to each affected qualifying facility in time for the qualifying facility to
cease the delivery of energy or capacity to the PTB REP or electric utility
will be required to pay the same rate for such purchase of energy or capacity
as would be required had the period of greater costs not occurred.
(3)
A claim by PTB REP or an electric utility that such a period
has occurred or will occur is subject to such verification by the commission
either before or after the occurrence.
(k)
Rates for sales to qualifying facilities.
(1)
General rules.
(A)
Rates for sales to qualifying facilities shall be just
and reasonable and in the public interest, and shall not discriminate against
any qualifying facility in comparison to rates for sales to other customers
served by the electric utility. Rates for standby or other supplementary service
shall be based on the amount of capacity contracted for between the qualifying
facility and the electric utility, and shall not penalize electric utilities
that also purchase power from qualifying facilities. The need for and cost
responsibility for special equipment or system modifications shall be determined
by application of Subchapter I of this chapter.
(B)
Rates for sales that are based on accurate data and consistent
system-wide costing principles shall not be considered to discriminate against
any qualifying facility to the extent that such rates apply to the electric
utility's other customers with similar load or other cost-related characteristics.
(2)
Additional services to be provided to qualifying facilities.
(A)
Upon request of a qualifying facility within its service
area, each electric utility shall provide:
(i)
supplementary power;
(ii)
back-up power;
(iii)
maintenance power; and
(iv)
interruptible power.
(B)
An electric utility shall not be required to provide supplementary
power, back-up power, or maintenance power to a qualifying facility if the
commission finds that provision of such power will:
(i)
impair the electric utility's ability to render adequate
service to its customers; or
(ii)
place an undue burden on the electric utility.
(3)
Rates for sales of back-up power and maintenance power.
The rate for sales of back-up power or maintenance power:
(A)
shall not be based upon an assumption (unless supported
by factual data) that forced outages or other reductions in electric output
by all qualifying facilities on an electric utility's system will occur simultaneously,
or during the system peak, or both; and
(B)
shall take into account the extent to which scheduled outages
of the qualifying facilities can be usefully coordinated with scheduled outages
of the utility's facilities.
(l)
Interconnection costs. The establishment and reimbursement
of interconnection costs are set forth in Subchapter I of this chapter with
respect to qualifying facilities seeking to interconnect with TDUs in ERCOT,
and in the respective electric utility's Open Access Transmission Tariff for
electric utilities in non-ERCOT power regions.
(m)
System emergencies.
(1)
Qualifying facility obligation to provide power during
system emergencies. A qualifying facility shall be required to provide energy
or capacity to an electric utility during a system emergency only to the extent:
(A)
provided by agreement between such qualifying facility
and electric utility; or
(B)
ordered under the Federal Power Act, §202(c).
(2)
Discontinuance of purchases and sales during system emergencies.
During any system emergency, an electric utility may discontinue:
(A)
purchases from a qualifying facility if such purchases
would contribute to such emergency; and
(B)
sales to a qualifying facility, provided that such discontinuance
is on a nondiscriminatory basis.
(n)
Enforcement. A proceeding to resolve a dispute between
an electric utility, PTB REP and a qualifying facility arising under this
section may be instituted by filing of a petition with the commission. Electric
utilities, PTB REPs, and qualifying facilities are encouraged to engage in
alternative dispute resolution prior to the filing of a complaint.
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 June 24, 2002.
TRD-200203964
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: July 14, 2002
Proposal publication date: January 4, 2002
For further information, please call: (512) 936-7216
3.
CAPACITY AUCTION
16 TAC §25.381
The Public Utility Commission of Texas (commission) adopts
an amendment to §25.381 relating to Capacity Auctions with changes to
the proposed text as published in the January 18, 2002
Texas Register
(27 TexReg 425). The amendment implements the Public
Utility Regulatory Act (PURA), Texas Utilities Code Annotated §39.153
(Vernon 1998, Supplement 2002), as it relates to the establishment of procedures
by which affected affiliated power generation companies (PGCs) will auction
entitlements to 15% of their Texas jurisdictional installed generation capacity.
PURA Chapter 39, Restructuring of Electric Utility Industry, became effective
September 1, 1999, as part of Senate Bill 7, 76th Legislative Session (SB
7), to effectuate a competitive retail electric market that allows each retail
customer to choose its provider of electricity and encourages full and fair
competition among all providers of electricity. This amendment is adopted
under Project Number 24492.
The commission received comments on the proposed amendment from Alkera,
Inc. (Alkera); Central Power and Light Company (CPL), West Texas Utilities
Company (WTU), and Southwestern Electric Power Company (SWEPCO) (CPL, WTU,
and SWEPCO collectively known as AEP); Coral Power, L.L.C. (Coral); Dynegy
Inc. (Dynegy); Tenaska Power Services Company (Tenaska); Entergy Gulf States,
Inc. (EGSI), Entergy Solutions Ltd., Entergy Solutions Select Ltd., Entergy
Solutions Essentials, Ltd. (collectively the Entergy REPs); Green Mountain
Energy Company (GMEC); New Power Company (New Power); Office of Public Utility
Counsel (OPUC); Steering Committee of Cities Served by TXU (Cities); Reliant
Energy, Inc. (REI); Reliant Resources, Inc. (RRI); Southwestern Public Service
Company (SPS); TXU Generation Company LP (TXUG), and TXU Energy Trading Company
LP (TXUE) (TXUG and TXUE collectively referred to here as TXU).
Comments on specific questions posed in the preamble:
Question Number 1: In regards to ongoing creditworthiness:
a. Should a seller be allowed to require additional
security from a purchaser, if the creditworthiness or financial responsibility
of the purchaser becomes unsatisfactory, in the reasonable judgement of the
seller, at any time during which the entitlement is in effect?
Sellers of entitlements (AEP, EGSI, REI, and TXU) supported allowing additional
security to be required from a buyer. Entergy REPs, OPUC, and Cities supported
the position of the sellers, but expressed the same concerns that led other
parties to oppose the additional security. Coral, Dynegy, Tenaska, GMEC, New
Power, and RRI opposed allowing additional security to be required mainly
because they felt that allowing additional security "in the reasonable judgement
of the seller" gave too much subjective power to the seller and would permit
discrimination. AEP proposed new language to allow an affiliate PGC to request
additional performance assurance if the entitlement holder's creditworthiness
becomes unsatisfactory. EGSI added that it is appropriate to request a reasonable
amount of additional financial security from buyers to ensure that they are
able to meet their continuing obligation with respect to purchased products.
TXU and REI's comments closely resembled the sentiments of AEP and EGSI with
the addition that REI believed that a seller would not invoke the "reasonable
judgement" provision arbitrarily, because if a seller did not act reasonably
it would be in breach of its agreement and would be liable to the buyer for
damages.
The Entergy REPs stated that additional security from the purchaser should
be allowed if the financial security of the purchaser materially changes,
as long as the criteria for requiring additional security are clearly identified
in the seller's credit requirements and there are clear parameters for exercising
"reasonable judgement." OPUC and Cities echoed this view but felt that "reasonable
judgement" should be quantified by an appropriate formula to prevent abuse
by sellers. Coral, Dynegy, and Tenaska stated that sellers should not be permitted
to demand unlimited credit assurance without defined and definitive causes,
such as a credit downgrade. GMEC and New Power added that the repercussions
of leaving the decision to the affiliated PGC could be severely detrimental
to the market for a number of reasons, including placing parties on unequal
footing in trades. RRI commented that the "reasonable judgement" provision
is arbitrary and that even objective standards should prevent an overdependence
on input from one source of credit information.
In reply comments, AEP and TXU stated that parties that fear the affiliated
PGC could unilaterally impose onerous credit requirements upon the other party
have not recognized that there would be significant constraints on the PGC's
actions. The EEI/NEMA contract itself would deem an unreasonable request for
assurances as a breach of contract, triggering significant penalties. Coral
argued that the additional credit provision is not accepted by Coral in other
commercial transactions, nor do they believe it is accepted by the majority
of purchasers in such transactions. Coral also noted that legal remedies for
an unwarranted demand for additional security are problematic, because litigation
is costly and slow. EGSI explained that sellers are accountable to the commission
and are not likely to abuse the credit provision by treating the same counterparties
differently in the capacity auction than they would in bilateral market transactions.
RRI commented that it was concerned that "reasonable" judgements and additional
credit requirements imposed unexpectedly and without objective standards would
increase credit related financial burdens. RRI contended that credit requirements
should be specific, fair, and not create unnecessary barriers to capacity
auction participation. TXU argued that the right of a seller to ask for credit
assurances is not only standard practice in the energy industry, it is a vital
right considering that capacity auction sellers are required to offer unsecured
credit to potential buyers pursuant to the standards set forth in the rule.
TXU stated that it is not true that capacity auction sellers could use the
credit assurances provision at their whim to keep certain non-investment grade
entities out of the auctions.
b. What are the positives and negatives associated
with allowing additional security to be required from the purchaser?
AEP stated that the positives would be allowing the risk of non-performance
to be allocated directly to the party causing the risk. The Entergy REPs commented
that a positive would be that the additional security would provide stability
to the auction process and would mitigate the risk of default by the purchaser.
REI opined that allowing additional security provides the seller necessary
protection against changed circumstances during the entitlement period. TXU
commented that without the additional security, sellers could be left with
significant unpaid capacity auction debt or pennies on the dollar for unsecured
capacity auction debts. This would defeat the purpose of the capacity auctions
and endanger the financial standing of capacity auction sellers. GMEC commented
that potential negatives included the facts that asymmetry of this sort creates
an opportunity for the affiliated PGC to distort the number of bidders and
the type of bidders, and that allowing the affiliated PGC to increase the
deposit requirement does not have equal impact on bidders. An additional dollar
of escrow or surety bond affects a company more than an additional dollar
applied against a credit rating, which GMEC states has potential liquidity
implications for the auctions. New Power added that allowing sellers to exercise
their "reasonable judgement" might allow sellers to squeeze out certain REPs
and in effect discriminate against companies that do not have an investment
credit rating, or discriminate for other arbitrary and capricious reasons.
RRI stated that the provision could serve as a barrier to entry for the new
market participants and lessen the interest of those currently active in the
capacity auction process.
The commission finds arguments on both sides of this issue persuasive.
The commission agrees with capacity auction sellers that they are required
to participate in the capacity auctions and that there is risk that the purchasers
of capacity auction entitlements will not be able to pay for those entitlements
due to circumstances that change after the auction is held. However, the commission
also agrees with the purchasers of capacity auction entitlements that allowing
sellers the ability to require additional credit at any time for any reason
is too much subjective power to grant to the sellers, as it could lend itself
to discrimination based on current or prior affiliations.
The commission concludes that capacity auction sellers should be allowed
to require additional security from entitlement purchasers only if the financial
condition of the purchaser materially changes after the auction, and if the
criteria for determining a material change and the form of additional security
are clearly identified in the seller's credit requirement provisions of the
Agreement. Language has been added to the rule to reflect this decision.
c. Should an additional security provision be
in place for the seller as well as the purchaser?
The parties were again split on this issue. AEP, EGSI, Entergy REPs, and
REI were against the purchaser being able to require additional security from
the seller. Coral, Dynegy, Tenaska, GMEC, New Power, and RRI, as potential
buyers, opined that purchasers should be allowed to request additional security
from sellers; OPUC and Cities supported this position. The position generally
echoed by Coral, Dynegy, Tenaska, GMEC, New Power, OPUC, Cities, and RRI was
that buyers and sellers should be afforded equal, symmetrical credit protections
through objective credit standards. In their view, the buyer is subject to
as much risk as the seller in these auctions; therefore, symmetry of deposit
requirements is appropriate. Coral, Dynegy, and Tenaska also pointed out that
entitlement holders face a significant credit risk. In the short run, buyers
of entitlements bear the risk that generation requested pursuant to an entitlement
will be curtailed in the middle of a schedule resulting in the entitlement
holder being liable for the imbalance charges assessed by the Electric Reliability
Council of Texas (ERCOT). In the long run, the capacity purchased could be
unavailable for a prolonged period. In addition to not receiving the service
that it has paid for, the entitlement holder would also be unable to meet
its commitments to sell electricity to its customers without purchasing that
power from other sources. In addition, GMEC deemed that the draft language
seems equipped to protect the seller from buyer's default in payment, but
needs to add symmetry to the transaction by giving protection to buyers from
the financial impact of seller's default. GMEC proposed language that would
hold the affiliated PGC responsible for any assessments from ERCOT for imbalanced
schedules, failure to procure ancillary services, or any other charges due
to the failure of the affiliated PGC to fulfill the auctioned obligation.
AEP, EGSI, Entergy REPs, and REI stated that no additional security should
be given to the buyer as the sellers have a legal obligation to perform and
buyers will weigh the perceived risk into their bids.
In reply comments, Coral, Dynegy, and Tenaska noted that sellers argue
that if buyers are in any way dissatisfied with the terms or bid prices they
can simply choose to not participate in the capacity auctions. Coral, Dynegy,
and Tenaska contended that this is the very reason the rule should require
bilateral credit. The absence of symmetrical, bilateral credit protection
in the capacity auctions would provide a significant incentive for buyers
to choose products available in the commercial market over those available
in the capacity auctions. Coral, Dynegy, and Tenaska commented that certain
parties argue that buyers have no risk because sellers' regulatory compliance
will assure performance of their obligations. However, if a credit event prevents
a seller from generating, no matter how badly that seller may wish to comply
with the commission's regulations, it will be unable to do so. Regulatory
compliance will take place only when sellers are financially and economically
able to comply. In terms of implementation, Coral, Dynegy, and Tenaska explained
that stakeholders would select the cover sheet options such that credit protections
afforded only to sellers would be made applicable to both sellers and buyers.
They propose that the same ERCOT Qualified Scheduling Entity (QSE) credit
standards that have been used to quantify the security requirements applicable
to buyers also be made applicable to sellers. Unrated sellers may have to
obtain guarantees from a rated parent or affiliate if they do not meet minimum
financial requirements. This would not expose them to additional expense.
While the commission is sympathetic to the plight of buyers regarding the
risk of a seller's default, the commission declines to impose the additional
cost associated with meeting bilateral credit requirements on the capacity
auction sellers. However, the commission finds that an entitlement holder
shall be allowed to request credit assurances from the entitlement seller
in the event of a downgrade event for the entitlement seller which would put
the entitlement holder at risk. If a downgrade event occurs, the entitlement
holder may request credit assurance from the seller in a commercially reasonable
manner. If the seller does not provide the credit assurance within three business
days of receipt of notice, then the entitlement holder shall have the right
to suspend performance as prescribed in the Agreement (and thus suspend payments
for energy not yet delivered) and may ultimately terminate the Agreement after
the suspension period. Language reflecting these decisions has been incorporated
into the rule. A downgrade event for the seller shall be structured, on the
cover sheet of the Agreement, in the same fashion as is currently employed
for the entitlement holder, except that the downgrade event is defined as
any lowering of the seller's credit rating, and not below a particular threshold.
Question Number 2: In regards to auction mechanics:
a. Should non-Electric Reliability Council of
Texas, Inc. (ERCOT) and non-stranded cost companies be allowed to have different
auction processes or mechanics from other companies?
AEP strongly supported the ability of non-stranded cost companies to devise
commercially reasonable auction processes and products. AEP added that for
non-stranded cost companies, the commission's sole goal should be to ensure
that the affiliated PGC has designed its auction process to sell 15% of the
Texas jurisdictional installed generation capacity. AEP argued that the proceeds
from the capacity auctions for such companies go directly to their bottom
line and the commission should grant such companies the ability to structure
the auctions in a way that fits management's view of the market. In its reply
comments, AEP clarified that all it is seeking is an explicit recognition
that there is a difference between the amount of regulatory review required
for stranded cost companies as opposed to non-stranded cost companies.
Coral, Dynegy, Tenaska, EGSI, OPUC, Cities, RRI, and TXU were generally
opposed to allowing this type of flexibility in the auction process. Coral,
Dynegy, and Tenaska simply stated that the auction should be conducted according
to the same terms and procedures utilized in the ERCOT auction. EGSI offered
that the capacity auction rule and mechanics currently offer sufficient uniformity
for efficient auctions statewide, and noted in reply comments that while not
opposed to the overall philosophy of tailoring product offerings, it does
not anticipate offering products other than those defined in the proposed
rule. GMEC explained that uniform auctions would encourage as many bidders
as possible and perhaps "ramp up" retail competition in non-ERCOT regions.
OPUC and Cities argued that it did not make sense to take a step backward
to non-standardized auction processes. In addition they stated that no company
should be allowed to offer products inferior to or different from products
other companies are offering, except to the extent some differences already
exist. RRI noted that there is no legislative basis for allowing non-ERCOT
and non-stranded cost companies to have different auction processes or mechanics.
TXU echoed the statements of OPUC and Cities and stated that it saw no reason
why non-ERCOT and non-stranded cost companies should not also have to follow
the uniform processes and mechanics, with the only exception being the differences
already delineated in the proposed amendments to the capacity auction rule.
TXU commented in its reply comments that in order to achieve a true liquid
market through the Texas capacity auctions, the capacity auction products
must be tradable. Allowing some capacity auction sellers to design and sell
alternative capacity auction products would interfere with tradability of
capacity auction products and would stunt the growth of a liquid market. TXU
also noted in reply comments that if the commission finds that there is some
value in allowing divergent capacity auction processes and products, then
it is only equitable to allow all of the capacity auction sellers to have
different processes and products.
b. What are the potential gains to allowing differing
processes or mechanics and what potential detriments exist in regards to efficiency
and loss of standardization?
AEP explained that the benefits would include the ability to tailor both
products and procedures to the marketplace in ways that more clearly meet
market demands without causing inefficiencies from the loss of standardization
between ERCOT and non-ERCOT companies. Coral, Dynegy, and Tenaska offered
that, to the extent the auctions mirror the ERCOT auctions, REPs will face
less of a burden to participate in these auctions. If the auctions are different,
REPs will require additional resources to participate, which will reduce participation
and liquidity. GMEC added that differences in auction mechanics make participation
more difficult and more costly, which could be a barrier to the bidder's entry
into the auction, especially in markets that are less robust. GMEC also noted
that the benefits of continuity are significant to markets all over the state,
including those areas that have yet to open for competition. OPUC and Cities
stated that a loss of standardization will impose greater burden on bidders
who would have to learn multiple sets of rules to bid into multiple auctions
instead of a single set of auction rules. This unnecessary complication could
lead to confusion on the day of the auction if bidding on both ERCOT and non-ERCOT
products. RRI largely echoed these sentiments in stating that differing mechanics
could result in market confusion that results in less participation, lost
efficiency, and loss of standardization as overlapping or contradicting sets
of rules and regulations may cause disputes among the players and lead to
lengthy and extensive dispute resolution or litigation.
The commission finds that the arguments of AEP are not persuasive. The
commission agrees with the other commenting parties that there is no reason
to allow any company to offer products inferior to or different from products
other companies are offering, except to the extent differences already exist.
The commission finds that allowing differing mechanics could result in market
confusion, resulting in potential losses in participation, efficiency, and
standardization which could lead to overlapping or contradictory rules and
disputes. The commission disagrees with AEP and finds that all capacity auction
sellers should be subject to the same amount of regulatory review to ensure
that an affiliated PGC has auctioned 15% of its Texas jurisdictional installed
generation capacity. Allowing differing auction mechanics would also create
a regulatory burden in determining that an affiliated PGC has in fact met
its auction requirement. The commission declines to make the recommended changes
proposed by AEP.
Question Number 3: Should the Power Generating
Companies (PGCs) involved in the capacity auction use a common auction platform?
None of the parties representing buyers or sellers of capacity auction
products supported the use of a common platform. AEP explained that within
ERCOT, only WTU (which will only offer a few products and a few entitlements)
will be on a different auction platform (after CPL's divestiture of 1,354
megawatts (MW) of generation capacity in 2002). AEP added that requiring all
companies to use the same platform would mean additional programming and transition
costs for the companies that do not use that platform already. If an all-new
platform is adopted, the old software and the associated expense of the old
platform would become stranded. AEP contended that before such a cost is imposed,
the commission should determine that the benefits significantly exceed the
costs. EGSI argued that no buyer raised a concern or complaint regarding EGSI's
auction process, which suggests that buyers were able to negotiate the process
with relative ease. EGSI offered that while a common auction platform might
offer some limited efficiency to buyers who participate in multiple auctions,
there does not appear to be any assurance that the benefits of such efficiency
would cause the market prices to rise to a sufficient level to offset the
expense of developing and implementing a common auction platform. EGSI added
that ERCOT sellers may have different needs than non-ERCOT sellers in order
to coordinate and schedule within ERCOT. This situation should not result
in non-ERCOT sellers being forced to incur additional costs for a new common
platform that includes features not applicable to non-ERCOT sellers. EGSI
contended that the two existing auction platforms have proven workable and
based on input from interested stakeholders, there does not appear to be a
strong interest in, or need for revision of, the two existing auction platforms.
Entergy REPs were concerned that requiring PGCs to use a common platform
at this time may in fact prove to be disruptive and undermine any perceived
benefits. Entergy REPs noted that the PGCs currently participating in the
auctions as required by PURA have already developed, tested, and implemented
hardware and software programs used in the September 2001 auctions. To require
a common auction platform now will necessarily involve additional expenditures,
development, testing, and training of purchasers prior to implementation.
OPUC and Cities commented that it is not apparent that a common auction platform
would improve the efficiency of the auction process. Given that fully functional
platforms have been independently developed and deployed by all of the auctioning
PGCs, OPUC and Cities stated that it makes little sense to impose the additional,
unnecessary financial burden of requiring that everyone adopt a new platform
solely for the purpose of consistency.
REI pointed out that 86% of all capacity auctioned under this rule already
uses a common platform. In all, 92% of all capacity auctioned is auctioned
under a common platform. REI offered that there are benefits to a common platform,
but was concerned that the costs of such an approach this late in the process
may outweigh those benefits. REI stated that it does not support any mandate
that parties be required to purchase new, duplicative software in order to
meet this goal. REI also argued that parties have already spent considerable
sums developing their own systems and that requiring parties to adopt a completely
new platform now, one that has not been used to date, might actually result
in increased overall costs to the sellers, buyers, and ultimately the retail
customers. RRI explained that although it would be convenient if all auction
products used the same platform, it does not believe that the commission can
force a seller to use a common platform if it chooses otherwise.
TXU stated that it had spent hundreds of thousands of dollars developing
its auction platform to comply with the commission rule (money for which there
is no recovery) and that to now require PGCs to expend more money in developing
a common auction platform to comply with a revised rule would be patently
unfair and potentially confiscatory. TXU added that there is no evidence that
a common platform would have resulted in higher prices in the September 2001
capacity auctions. TXU further stated that by all accounts the prices that
were achieved were in line with what most market participants would consider
the market price for these products. TXU commented that there is a real possibility
a common auction platform would only increase seller's expenses without a
commensurate increase in auction prices, leaving sellers with decreased revenues.
TXU deemed that requiring expensive and unnecessary repairs to a process that
has already performed efficiently seems wasteful and unreasonable. In its
own experience, TXUE offered that it bid under several auction platforms and
was not at all deterred by the differences in these platforms. TXUE added
that it does not believe that the use of a common auction platform would cause
additional bidders to participate in the auctions or would in any way increase
auction prices. As a follow-up, in reply comments, AEP pointed out that a
strong consensus appears to have developed that no change is needed with regard
to a common auction platform or a switching rule.
The commission concludes that a common auction platform is not needed.
The combined comments of the parties indicate that the two existing auction
platforms have proven workable and a change at this time may prove disruptive
and reduce the benefits of the auction. Existing platforms have already been
developed, tested, and implemented. Requiring a common platform would involve
unnecessary additional expenditures for development, testing, and training
of purchasers to implement a rule that may or may not improve the efficiency
of the auction process. The commission declines to require a common auction
platform, as it is not clear that the benefits of a common platform outweigh
the detriments of implementing the common platform, namely, the additional
costs and disruptions in the auction process.
Question Number 4: Should the Capacity Auction
include a switching rule to minimize price differences across PGCs?
Only one party (who is not a buyer or seller in the capacity auctions)
filed comments in support of a switching rule. Alkera, which designs and develops
auction software and processes, recommended that the commission adopt a switching
rule so as to limit the risk that prices would fail to achieve market-clearing
levels. Alkera stated that there is significant risk that this could happen
in the upcoming auctions, yet provided no support for this conclusion. In
addition, Alkera stated that the problems associated with no switching rule
(wrong bidders winning the wrong products resulting in buyers and sellers
being worse off and average prices being lower) may not have happened in the
most recent Texas auction. RRI did not take a position on this issue but addressed
some of the aspects involved if a switching rule were implemented.
The remaining parties that commented on this issue (AEP, EGSI, New Power,
OPUC, Cities, REI, and TXU) generally stated that they were not opposed to
the theoretical aspects of a switching rule. However, for the reasons stated
below, all of these parties were united in opposing the implementation of
a switching rule for the Texas capacity auctions. AEP explained that the commission
must make sure that the benefits of a switching rule exceed the costs of such
a rule. AEP noted that it does not believe that it is possible to accurately
state how much benefit there is to such a rule. AEP added that CPL may not
be auctioning after 2002, whether SWEPCO does so depends on the development
of retail competition in the Southwest Power Pool (SPP) Power Region, and
WTU offers only a few products in a zone where there may not be a lot of ability
for bidders to switch between product offerings. Thus, AEP is very sensitive
to the question of cost. AEP also commented that since the benefits of such
a rule inure to the buyers, at least part of the cost of the rule should be
imposed on those that obtain the benefits from the rule. AEP also explained
that allocating the costs of a switching rule to buyers will give the commission
better insight into the value that bidders place on a switching rule. If bidders
do not support a switching rule, the commission should recognize such non-support
as a signal that a switching rule needs to be carefully examined.
New Power elaborated on this idea, stating that it is their understanding
that none of the parties that might benefit from a switching rule is clamoring
to institute one. OPUC and Cities concluded that it must be determined whether
any of the auction participants feel that auction outcomes will be significantly
improved by switching and if neither buyers nor sellers feel there is a need
for switching, the issue can be put to rest. REI commented that because a
switching rule is potentially expensive to implement, it must have some perceived
benefit before implementation is even considered. To REI's knowledge, none
of the buyers or sellers in past auctions have expressed the opinion that
the prices of entitlements would increase if switching were allowed.
EGSI noted that for switching to be effective, there must be multiple auctions
with interchangeable products and that these two features may not exist in
the non-ERCOT regions of Texas, which suggests that a switching rule may offer
little, if any, benefits outside of ERCOT. EGSI suggested that buyers will
not attempt to switch between ERCOT and non-ERCOT products to leverage prices
among similar products because the products are not interchangeable between
regions. In addition, EGSI stated that it and SWEPCO appear to be on different
time lines to implement retail open access and the imposition of a switching
rule before there are two sellers to switch between would be illogical. Also,
if EGSI and SWEPCO join separate Regional Transmission Organizations (RTOs),
then limits on the physical capability to transfer power between regions and
the associated cost of transferring power may diminish the benefits of a switching
rule. EGSI concluded by stating that it would be premature to incur the additional
expense to develop and apply a switching rule that might offer little, or
no, practical value to buyers and sellers in the non-ERCOT region of East
Texas.
TXU commented that it could not be sure that the potential benefits of
a switching rule would outweigh the certain costs of developing and implementing
a switching rule. In addition, TXU noted due process concerns if the commission
requires the implementation of a switching rule. TXU also proposed that the
rule be republished so that parties are provided notice and a reasonable opportunity
to be heard, if a switching rule is to be adopted. TXU explained that there
were price differentials among PGCs in the September 2001 capacity auction,
but those price differentials were appropriate price differentials. At the
time of the auction, REI's baseload and gas-cyclic products were simply not
perfect substitutes for TXU baseload and gas-cyclic products in the south
2001 congestion zone. The bidders knew that the delivery point for TXU's baseload
and gas-cyclic products would be moving into the north 2002 congestion zone
under ERCOT's planned zonal changes for 2002. The price differentials that
were experienced for these products were at least partly a result of bidders
valuing capacity in the north 2002 congestion zone more than they valued capacity
in the south 2002 congestion zone. TXU then noted that a switching rule would
not have changed this fact and would not necessarily have changed the price
differentials. In addition, TXU noted that two of the largest buyers in the
capacity auctions (TXU and REI) would be limited in their use of a switching
rule due to affiliate relationships (an affiliate of a capacity auction seller
may not purchase entitlements from that seller). TXU argued that Dr. David
Salant (of Alkera), has said that there is no guarantee that the addition
of a switching rule will increase Texas capacity auction revenue; thus requiring
sellers to spend hundreds of thousands more to modify their capacity auction
systems to comply with a revision that may not increase auction revenue is
unreasonable.
In reply comments, AEP stressed the importance that after examining a switching
rule, the only commenter that has voiced unqualified support for a switching
rule has the most to gain from its implementation by offering to supply software
to solve the "problem" it has identified. AEP contended that Alkera's comments
are long on speculation and significantly short of explicit proof of its conclusions.
AEP noted that this is highlighted by the remarkable conclusion of Alkera
that "a few additional bids being facilitated by switching are worth tens
of millions of dollars to the sellers". AEP then stated that if Alkera had
proof of that contention, every seller would be demanding a switching rule.
Unfortunately, such proof does not exist, and AEP is skeptical that any such
proof could exist. OPUC and Cities offered in reply comments that if Alkera's
assertions are correct, there could be enormous implications for the final
determination of stranded costs and that sellers could conceivably oppose
a switching rule as a means to keep auction prices low, with the intentions
of recovering the potential price differential as stranded costs. TXU's reply
comments added that Alkera has failed to acknowledge that the price disparities
that were experienced between various sellers' products in the September 2001
capacity auction may very well be explained by several factors, including
the different strike prices and congestion zones in the auction, and the anticipation
of changing ERCOT congestion zones in 2002.
The commission finds the comments filed by the parties regarding a switching
rule not to be persuasive. Therefore, the commission believes that the public
interest requires a switching rule to minimize price distortions. The commission
believes that the price disparities in the September 2001 and March 2002 Capacity
Auctions cannot be explained solely by the differing strike prices and different
congestion zones, but are based, in part, on the lack of appropriate switching
provisions in the current auction design. The commission finds that the inability
of bidders to switch during the auction from one affiliated PGC's products
to a similar or identical product of another affiliated PGC whose price is
lower, reduces the expected revenues from the auctions, and did so in the
recently concluded March 2002 auction. The commission believes that the affiliated
PGCs within ERCOT should implement switching procedures to reduce the risk
of such price disparities in future Capacity Auctions. The affiliated PGCs
within ERCOT shall provide the commission with proposed switching procedures,
including detailed activity rules, for implementation in the September 2002
auction.
Several parties also provided redlined versions of the proposed rule suggesting
rule language that should be used to incorporate their recommendations and
comments. To the extent that language is duplicative of the comments received,
such language is not repeated here. To the extent that reply comments did
not significantly add to or change a party's original arguments, those reply
comments are not summarized here.
Alkera's comments focused solely on a switching rule and included a description
of a switching rule, the elements it would include, and how a switching rule
would work. Those comments are outside the scope of the preamble questions
and thus are not summarized in detail here. In addition, SPS did not specifically
comment on the preamble questions, but pointed out that under PURA Chapter
30, Subchapter I, competition in SPS's service territory will be delayed until
at least January 1, 2007.
REI filed reply comments concerning how to alleviate potential congestion
cost problems. These comments were filed late and address new issues outside
the scope of the published proposed rule and are therefore not addressed or
summarized in this preamble.
Comments on specific sections of the rule:
Subsection (c)(6) Definitions:
AEP recommended that the use of "local Austin, Texas time" may be confusing
to bidders outside of the state of Texas and that the use of "central prevailing
time" would be more effective.
The commission agrees that referencing Austin, Texas may be confusing.
This language has been changed to refer to "central prevailing time."
Subsection (d) General requirements:
AEP recommended that specific language be adopted to allow non-ERCOT and
non-stranded cost companies the flexibility to alter their auction products
and mechanics as discussed in Preamble Question 2.
As discussed above in connection with Preamble Question 2, AEP's recommended
language is not adopted.
Subsection (e)(1) Available entitlements and amounts:
AEP recommended deleting the detailed descriptions of the products contained
in subsections (f) and (g).
The commission declines to adopt the recommendation of AEP. The detailed
product descriptions which AEP feels are unnecessary are included in the rule
language to specify the product descriptions, instead of allowing the possibility
for the offered products to change from auction to auction and seller to seller.
This standardization will facilitate efficiency in the capacity auctions and
liquidity in the secondary market as auction entitlements will be more easily
traded.
Subsection (e)(2)(B) Forced outages:
AEP stated that the use of the word "firmness" is not entirely accurate
in the context of the rule and that "availability" would more accurately express
the commission's intent. RRI commented that proposed subsection (e)(2)(B)
should apply only to those sellers operating two or fewer generating units
in total. Sellers operating fleets of generation in multiple congestion zones
should not be allowed to bypass the current rule's reliability standard because
they have one or two generating units in a particular zone and the remainder
of the fleet in another. REI proposed clarification that only one of the units
associated with an entitlement product must be down in order to trigger the
forced outage reduction.
In reply comments, AEP commented that REI's comments accurately capture
the intent of the parties and if adopted, AEP's proposal would not be necessary.
AEP clarified its support for REI's proposal and its opposition of RRI's proposal
by stating, for example, that WTU's baseload entitlement is supported by a
single plant. If that plant were to experience a forced outage, it is true
that other WTU resources would continue to produce electrons, but this replacement
energy would be a product at a significantly higher cost than the fuel cost
mandated for the baseload product under this rule. Also, this would give the
entitlement holder an availability factor greater than the underlying units,
at a lower cost than that incurred by the owners of the plant. EGSI agreed
with the proposed change of REI and stated that RRI's proposal is inconsistent
with PURA. OPUC and Cities supported the proposal of RRI and were concerned
that the forced outage rate could easily be gamed to the detriment of the
entitlement holder.
The commission agrees with REI's proposed language to clarify the intent
of the provision on forced outage reduction and has modified the rule accordingly.
The commission does not agree with the arguments of OPUC and Cities in support
of RRI's proposed interpretation. The commission finds the reply comments
of AEP persuasive in illustrating that RRI's interpretation would give the
entitlement holder an availability factor greater than the underlying units,
at a lower cost than the actual owners of the plant. This was not the intent
of the rule and the commission declines to adopt RRI's interpretation of the
forced outage reduction provision.
Subsection (e)(2)(C) Forced outage notification:
AEP recommended that, for clarification purposes, the hour-ahead schedule
is the appropriate time frame for determining the existence of emergency conditions
and would allow the buyer the opportunity to adjust its scheduling.
The commission agrees and has modified the appropriate language in the
rule.
Subsection (e)(3) Planned outage:
AEP recommended that the rule be modified to include Planned Outage Hours
and Maintenance Outage Hours to determine the reductions that should be applied
to the number of entitlements offered by the affiliated PGCs. Accordingly,
AEP suggested that proposed subsection (e)(3) be deleted and offered substitute
language. RRI recommended language that shifts entitlement adjustments for
planned outages to non-shoulder months and ensures that the 15% requirement
for the capacity auction is met. REI recommended clarifying language to the
rule.
In reply comments, AEP stated that it believes its language proposal is
best, but believes that REI's proposal is easier to understand than the proposed
rule. AEP stated that it did not understand the language proposed by RRI.
EGSI opposed the language of RRI and stated that the capacity auction is intended
to provide bidders with a "slice" of the seller's owned generation. That owned
capacity will be subject to planned maintenance to ensure the continued reliable
and efficient operation of generating units. The proposed rule provides a
reasonable schedule for planned maintenance and should not be revised to insulate
entitlement holders from the necessity for planned maintenance. TXU echoed
the opinions of EGSI, arguing that RRI's proposed change is a thinly veiled
attempt to require capacity auction sellers to sell more than 15% of their
capacity, in violation of PURA §39.153.
The commission finds the reply comments of AEP, EGSI, and TXU persuasive
and declines to adopt the proposed language of RRI. For clarifying purposes,
the proposed language of REI is adopted in lieu of AEP's proposed language.
Subsection (e)(4) Generation units offered:
AEP recommended that the language that specifies planned outage history
for the years of 1998, 1999, and 2000 be modified to the most recent three
operating years, as the specific years in the rule were used for the initial
capacity auction when those were the most recent three operating years.
In reply comments, TXU argued that there was no reason to make AEP's proposed
change. TXU noted that the planned outages for a given unit are unlikely to
change significantly between the year 2000 and the end of the Texas capacity
auctions. The sellers have already gathered their planned outage histories
for 1998, 1999, and 2000. It does not seem cost-effective to require sellers
to go through the significant expense of creating new planned outage histories
when a unit's planned outages are unlikely to have changed to any great extent.
The commission agrees with the reply comments of TXU and finds that it
is not cost-effective to require the calculation of new planned outage histories.
It is unlikely that a unit's planned outages will change significantly. The
commission declines to adopt AEP's recommended language.
Subsection (e)(5) Obligations of affiliated PGC:
AEP recommended language that would need to be included if the details
of the capacity auction products were deleted from the rule and only included
in the Capacity Auction EEI/NEMA Master Power Purchase & Sale Agreement.
The commission finds the recommended language of AEP inappropriate, consistent
with the commission decision to retain the detailed product descriptions in
the rule.
Subsection (e)(7)(A) Credit requirements:
RRI proposed that this subsection include the ratings from Fitch Investor
Services and that calls for additional security should be based on a blend
of the three services in lieu of the lower of the three. RRI also recommended
that subsection (e)(7)(A)(ii) be amended to require posting of capacity and
energy payment security no more than 90 days in advance of the month when
the entitlement may be dispatched.
In reply comments, TXU argued against RRI's proposal of not posting credit
until 90 days before the entitlement month. TXU argued that the capacity auction
seller would have no guarantee until 90 days before dispatch that the buyer
could actually pay for the entitlement.
The commission finds that the recommendation of RRI to include the ratings
from Fitch Investor Services is unnecessary. The current language on credit
requirements is sufficient and not significantly changed by the addition of
another rating service. The commission also declines to make the recommended
change proposed by RRI regarding the posting of credit. The commission finds
it is inappropriate to allow potential bidders in the capacity auction the
equivalent of unlimited buying credit, without any assurance of the ability
to pay for awarded entitlements until after the auction and 90 days before
dispatch. During this period, a buyer's financial condition could change,
imperiling its ability to pay for the power. If this were to happen, the seller
would be at risk for the purchase price agreed to in the auction.
Subsection (e)(7)(B)(i) Unsecured credit:
AEP recommended that the language and table be deleted and that the commission
use the working group to set credit limits on an auction-by-auction basis.
AEP provided substitute language to facilitate this recommendation.
The commission declines to make the change recommended by AEP. The commission
believes that standardizing the credit requirements will facilitate the effectiveness
of the auctions, rather than resorting to a working group to meet before each
auction to negotiate new credit limits.
Subsection (e)(7)(H) Credit requirements (New
language):
AEP proposed specific language to accompany its recommendation concerning
Preamble Question Number 1.
Consistent with its decision in Preamble Question Number 1, the commission
adopts a modified version of the language proposed by AEP regarding credit
requirements.
Subsections (f) and (g) Product descriptions for
capacity auctions in ERCOT and non-ERCOT areas:
AEP recommended that this section be deleted. REI proposed modifications
to several portions of subsection (f) that clarify that ERCOT is the entity
that dispatches ancillary services, as well as other clarifying language.
TXU disagreed with AEP in reply comments and stated that when issues have
already been negotiated and agreed on for three different capacity auctions,
it seems wasteful and inefficient to throw those same issues up for debate
for each capacity auction. By building the product descriptions into the capacity
auction rule, both capacity auction buyers and sellers will receive a measure
of certainty that the dispatch systems that have already been designed will
not have been designed in vain, and that the liquid wholesale market that
has begun in Texas will continue. AEP recommended a slight modification to
the language provided by REI, should AEP's recommendation for deletion not
be adopted.
Consistent with its decision on subsection (e)(1), the commission declines
to delete the detailed product descriptions in subsections (f) and (g). The
commission finds the reply comments of TXU persuasive in justifying the detailed
product language contained in subsections (f) and (g), and to a lesser extent
in subsection (e)(1). The commission agrees that ERCOT is the entity that
dispatches ancillary services and also adopts other clarifying language recommended
by REI to eliminate potential confusion in subsection (f).
Subsection (f)(2)(A) Responsibility transfers:
GMEC recommended that given the preparations that the entitlement holder
must make under subsection (f)(2)(B)(i), responsibility transfers (RTs) by
the affiliated PGC should be completed a minimum of ten days before the commencement
of the entitlement. TXU recommended a clarifying change to recognize that
respective QSEs of a capacity auction seller and buyer may not have a RT agreement
in place before the purchase of capacity auction products.
TXU argued against the proposal of GMEC in reply comments and stated that
before a responsibility transfer can be established, essentially four parties
must come together to an agreement: the buyer, the buyer's QSE, the seller,
and the seller's QSE. TXU argued that it would be inappropriate and inequitable
to impose the risks of an agreement not being reached on only one party to
those negotiations. TXU further explained that a capacity auction seller does
not have sole control of when a responsibility transfer is put into place.
Under GMEC's proposal, a capacity auction buyer would have an incentive to
drag its feet in reaching an agreement so that the capacity auction seller
could be held liable for the financial implications if the seller failed to
meet its contractual obligations.
The commission declines to adopt GMEC's changes to the proposed language.
The commission finds TXU's reply arguments that it would be inappropriate
to add this risk to the capacity auction seller persuasive, as it does not
have sole control of when a responsibility transfer is put into place. For
clarification purposes, the commission adopts the proposed language of TXU.
Subsection (f)(2)(B)(i) Notice of grouped entitlements:
TXU recommended a clarifying change to recognize that dispatch systems
of some affiliated PGCs do not require the use of a written list of entitlements.
The commission adopts TXU's proposed language for clarification purposes
and has made the corresponding change to the rule language.
Subsection (f)(3) - (6) Timing of scheduling for
baseload, gas-intermediate, gas-cyclic, and gas-peaking:
TXU recommended language to account for possible changes in the ERCOT protocols
regarding the timing of scheduling.
The commission finds it prudent to adopt TXU's recommended language to
account for possible changes in ERCOT protocols concerning the timing of scheduling.
Subsection (f)(4)(A)(v) Default schedule for gas-intermediate
product:
TXU recommended additional clarifying language to this subsection to account
for the limitation on the number of starts for a gas-intermediate product
imposed by proposed subsection (f)(4)(A)(iv)(IV).
The commission agrees with TXU that clarifying language is justified and
has made corresponding changes to the rule language.
Subsection (f)(5)(A)(ii)(I) and (V) Timing of
gas-cyclic scheduling:
AEP recommended that this section be deleted, but if the commission decides
to keep it in the rule, AEP provided clarifying language to avoid confusion
over the term "daily capacity commitment."
In reply comments, TXU stated that if the commission implements AEP's proposed
language a May 2003 gas-cyclic product that was sold as a two-year strip in
the September 2001 auction would be slightly different from a May 2003 gas-cyclic
product sold as a one year strip in the September 2002 auction. Such differences
would not only make gas-cyclic products difficult to trade, but would make
it impossible to group them for dispatch.
Due to concerns over the liquidity of the wholesale market, and thus the
ability to trade capacity auction products, the commission finds TXU's reply
comments persuasive and declines to make AEP's recommended change.
Subsection (h) Auction process:
AEP recommended an introductory statement to clarify that non-ERCOT and
non-stranded cost companies do not have to follow the auction processes described
herein, if AEP's position is adopted by the commission.
Consistent with the commission's decision in Preamble Question Number 2,
the commission declines to adopt AEP's recommended language.
Subsection (h)(1)(B)(iv) Auction conclusion:
TXU proposed clarifying language regarding the 15% requirement for auction
conclusion. In reply comments, AEP opposed the language suggested by TXU and
stated that TXU's language made the rule less clear.
The commission finds that TXU's proposed language clarifies the intent
of the rule and thus adopts the recommendation.
Subsection (h)(2)(A) Auction administration:
AEP noted that if a common platform is adopted by the commission, this
subsection would need to be amended accordingly.
Consistent with the commission's decision in Preamble Question Number 3,
no language modification is required for subsection (h)(2)(A).
Subsection (h)(2)(B)(i) Method of notice:
AEP recommended that a better approach than administrative review would
be a method where the PGC files notice and, if no protests are filed, the
notice is deemed approved. AEP supplied language to this effect.
The commission agrees with AEP and finds that the proposed methodology
is less administratively burdensome and thus adopts AEP's recommended language.
Subsection (h)(2)(B)(ii) Contents of notice:
TXU recommended clarifying language to illustrate that it is no longer
necessary for an affiliated PGC to include a bid increment formula in its
capacity auction notice because proposed subsection (h)(2)(B)(ii)(I) specifies
standard bid increment ranges for all capacity auction sellers.
The commission agrees with TXU that the standard bid increment ranges replace
the bid increment formula and thus the notice no longer needs to include a
bid increment formula. The commission adopts TXU's clarifying language. The
commission also clarifies subsection (h)(2)(B)(ii)(II) that for an entitlement
subject to the forced outage provision in subsection (e)(2)(B), the most recent
three-year rolling average of the forced outage rate will be included in the
notice of capacity available for auction, when the designation of which power
generation units will be used to meet the entitlement to be auctioned is made.
Subsection (h)(2)(B)(iii)-(v) Timing of capacity
auction document submittal for notice:
TXU recommended changes necessary to ensure that capacity auction sellers
will have sufficient time to review the creditworthiness of perspective bidders.
In addition, these changes will ensure that approved bidders have sufficient
time to review the amount of credit that has been granted and to return in
executed form the applicable capacity auction-specific master agreement.
The commission finds TXU's recommended language prudent in that it will
allow all parties sufficient time to review credit issues. The commission
adopts TXU's recommended language.
Subsection (h)(2)(B)(v) Credit adjustment:
AEP recommended that the language that disallows additional credit after
an auction begins be deleted and that new language allowing the practice be
adopted.
The commission declines to adopt AEP's recommendation. While the commission
recognizes that there may be benefits associated with allowing bidders to
request and receive additional credit after an auction begins, the commission
sees numerous problems associated with implementing such a subjective provision
in a fair and non-discriminating fashion. No change has been made to the language
of the proposed rule.
Subsection (h)(3)(B)(vi) Subsequent auctions:
TXU proposed a clarification concerning the start date of the September
2003 capacity auction, which was supported by EGSI in reply comments.
The commission agrees with TXU and EGSI that the start date in the rule
needs to be clarified and modifies the rule accordingly.
Subsection (h)(7) Establishment of opening bid
price:
RRI suggested that subsection (h)(7)(A) be amended to require sellers to
issue opening bids prior to each auction subject to the challenge provisions
in the proposed rule, as opening bids may be arbitrarily high, based upon
outdated calculations. RRI explained that contingent on its recommendation
for subsection (h)(7)(A), (h)(7)(B) would no longer be needed and recommended
its deletion. REI proposed language to subsection (h)(7)(B) to clarify that
the comparison of the weighted average opening bid must be completed for all
entitlements of a given product across all congestion zones, and recommended
that for clarification purposes, the terms "owner" and "purchaser" be replaced
with "holder" throughout the rule. RRI commented that subsection (h)(7)(C)
should be amended such that a seller would be deemed to have met the 15% requirement
if the unsold entitlements are made available to the market through other
auction mechanisms. TXU recommended clarifying language to subsection (h)(7)(C)
regarding the meeting of the 15% requirement.
In reply comments, TXU was against the proposal of RRI regarding opening
bids and stated that RRI seems to misunderstand the genesis of the opening
bid prices in Texas. TXU stated that the capacity auction opening bid prices
are cost-based and not market-based. TXU commented that contrary to RRI's
assertion, market forces do not and will not change the seller's variable
cost for operating its capacity. As a result, even though the market for capacity
may change from auction to auction, there is no need to require auction sellers
to change the opening bid prices from auction to auction. TXU also opposed
RRI's proposal concerning the 15% requirement. TXU offered that the Texas
capacity auctions are monitored and sanctioned by the commission to protect
both capacity auction buyers and Texas consumers. A separately conducted capacity
auction would not have such protections. Moreover, allowing a separately conducted
capacity auction to satisfy the 15% requirement would essentially defeat the
purpose of the Texas capacity auctions. EGSI also commented against RRI's
proposal concerning opening bids and stated that the most volatile variable
cost associated with plant operations is the cost of fuel for gas-fired generation,
which is not included in the bid price. EGSI also disagreed with RRI's proposal
regarding the 15% requirement. EGSI stated that the proposed rule provides
sufficient commission oversight through the requirement that an affiliated
PGC make a proposal to the commission through the auction notice to satisfy
the 15% requirement if there is an auction where no month awards all of the
entitlement of a particular product. EGSI supported REI's proposed language
change regarding the use of the word "holder."
The commission declines to make RRI's recommended changes. The commission
finds the reply comments of TXU and EGSI persuasive on these issues. The commission
does, however, adopt the recommended clarifying language changes proposed
by REI and TXU. The commission finds the proposed language consistent with
the intent of the rule.
Subsection (j)(2) True-up process:
EGSI noted that the proposed rule does not incorporate the settlement of
stranded cost issues in EGSI's Unbundled Cost of Service (UCOS) case and could
be misinterpreted as requiring EGSI to participate in a true-up process that
the commission has found to be inapplicable to EGSI. EGSI proposed language
to clarify that it is not subject to the capacity auction true-up.
The commission agrees with EGSI and for clarifying purposes adopts modified
language which is more general in nature, but consistent with the concerns
of EGSI.
Subsection (m) Contract terms:
AEP recommended the restoration of a sentence addressing a standard agreement,
contingent on its recommendation that the detailed contract language is deleted
from the rule. In addition, AEP noted that Paragraph F of Schedule CA, concerning
alternative dispute resolution, should be included in subsection (m) and supplied
such language. TXU recommended that this section be revised to remove the
references to bilateral credit requirements. GMEC's proposed language stated
that failure to supply the purchased generation will result in the assessed
charges being the PGC's responsibility and not the entitlement holder's.
In reply comments, TXU again opposed the bilateral credit provision and
added that the capacity auction products are essentially 98% firm products
backed by multiple generation units. The odds of a capacity auction seller
being physically unable to meet its capacity auction obligations are extremely
low. Even a catastrophic credit event for a capacity auction seller would
have no effect on the seller's ability to deliver the output from its assets.
This fact alone illustrates why bilateral credit terms are not necessary.
TXU also offered that bilateral credit terms would be extremely difficult
to implement and would be potentially financially destructive to capacity
auction sellers. It would be difficult to quantify the amount of collateral
that a seller would need to post in order to assure its obligations. TXU did
not oppose the language recommended by GMEC as TXU felt it confirmed the buyer's
rights. However TXU felt that this issue would be more appropriately dealt
with in the contract and not in the Substantive Rules. Therefore, TXU offered
clarifying language. Coral, Dynegy, and Tenaska supported GMEC's proposed
language and stated that they believe that the language will protect buyers
from ERCOT fees assessed due to short-term delivery failures by capacity auction
sellers. However, they also asserted that the bilateral credit protections
are necessary to protect buyers from long-term risks associated with a seller's
default.
Consistent with its decision not to delete the detailed product language
in subsections (f) and (g), the commission declines to adopt AEP's recommendation
to restore a sentence addressing a standard agreement. The commission agrees
with AEP that language concerning alternative dispute resolution should be
included in subsection (m) and adopts AEP's proposed language. The commission
finds TXU's reply comments persuasive and has removed the references to bilateral
credit requirements. While the commission is sympathetic to the plight of
buyers regarding the risk of a seller's default, the commission declines to
impose the additional cost associated with meeting bilateral credit requirements
on the capacity auction sellers. The commission agrees with TXU that the probability
of a seller being unable to meet its contractual obligation is extremely low
and therefore imposing the additional cost of a surety or performance bond,
or some other form of guarantee, would not be justified. The commission finds
that capacity auction products are generally 98% firm and backed by multiple
generation units. The commission agrees with TXU's statement that even a catastrophic
credit event is unlikely to have a long-run effect on the seller's ability
to deliver the output from its assets. The commission finds that the long-run
risk of these assets being unable to deliver power is not great enough to
justify the cost to sellers and the potential problems associated with implementation
of bilateral credit. The commission does recognize that there is a slightly
greater risk associated with entitlements that are supported by a smaller
number of generating units. The commission still finds this amount of risk
not great enough to require bilateral credit requirements. The commission
encourages participation in the Texas capacity auctions, and in an effort
to eliminate as much risk as possible, the commission adopts GMEC's proposal
that failure to supply the purchased generation will result in the seller's
liability for any charges assessed against the entitlement holder. The commission
adopts this recommendation with TXU's proposed change that clarifies that
this is a contractual issue. Language reflecting these decisions has been
incorporated into the rule.
Subsection (m)(4) Scheduling discrepancies:
AEP recommended that this provision be deleted from the rule as it is handled
by Schedule CA. TXU recommended clarifying language that details the relationship
between the general requirements of subsection (m)(4) and the more specific
requirements of proposed subsection (f)(3)(A)(iv)(V) and (f)(4)(A)(v).
The commission does not agree with AEP that the language in subsection
(m)(4) needs to be deleted. No persuasive argument was made that the current
language needs to be deleted. For clarification purposes, the commission adopts
TXU's proposed language.
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 amendment is adopted under the Public Utility Regulatory
Act, Texas Utilities Code Annotated §14.002 (Vernon 1998, Supplement
2002) (PURA) which provides the commission with the authority to make and
enforce rules reasonably required in the exercise of its powers and jurisdiction.
The commission also proposes this rule pursuant to PURA §39.153, which
grants the commission authority to establish rules that define the scope of
the capacity entitlements to be auctioned, and the procedures for the auctions.
Cross Reference to Statutes: Public Utility Regulatory Act §§14.002,
31.002, 39.153, 39.201, and 39.262.
§25.381.Capacity Auctions.
(a)
Applicability. This section applies to all affiliated power
generation companies (PGCs) as defined in this section in Texas. This section
does not apply to electric utilities subject to the Public Utility Regulatory
Act (PURA) §39.102(c) until the end of the utility's rate freeze. It
is recognized that certain commission orders issued during 2001 have effectively
delayed competition in the service territories of Southwestern Electric Power
Company (SWEPCO) and Entergy Gulf States, Inc. (EGSI). This section shall
apply to auctions conducted after 2001 by SWEPCO and/or EGSI only when competition
is implemented in their respective service territories.
(b)
Purpose. The purpose of this section is to promote competitiveness
in the wholesale market through increased availability of generation and increased
liquidity by requiring electric utilities and their affiliated PGCs to sell
at auction entitlements to at least 15% of the affiliated PGC's Texas jurisdictional
installed generation capacity, describing the form of products required to
be auctioned, prescribing the auction process, and prescribing a true-up procedure,
in accordance with PURA §39.262(d)(2).
(c)
Definitions. The following words and terms, when used in
this section, shall have the following meanings, unless the context indicates
otherwise:
(1)
Affiliated power generation company (PGC)--Any affiliated
power generation company that is unbundled from the electric utility in accordance
with PURA §39.051.
(2)
Assigned units--The PGC-specific generating units that
form the block of capacity from which an entitlement is sold.
(3)
Auction start date--The date on which an auction begins.
(4)
Business day--Any day on which the affiliated PGC's corporate
offices are open for business and that is not a banking holiday.
(5)
Capacity auction product--One of the following: "baseload",
"gas-intermediate", "gas-cyclic", or "gas-peaking". Each capacity auction
product is further described in subsections (f) and (g) of this section.
(6)
Close of business--5:00 p.m., central prevailing time.
(7)
Congestion zone--An area of the transmission network that
is bounded by commercially significant transmission constraints or otherwise
identified as a zone that is subject to transmission constraints, as defined
by an independent organization.
(8)
Credit rating--A credit rating on an entity's senior unsecured
debt, the entity's corporate credit rating, or the entity's issuer rating.
(9)
Daily gas price--The index posting for the date of flow
in the Financial Times energy publication "Gas Daily" under the heading "Daily
Price Survey" for East-Houston-Katy, Houston Ship Channel. For EGSI gas entitlements
in the eastern congestion zone, the daily gas price will utilize the "Gas
Daily" index posting for Henry Hub. For EGSI gas entitlements in the western
congestion zone, the daily gas price will be an average of the "Gas Daily"
index posting for East-Houston-Katy, Houston Ship Channel.
(10)
Day-ahead--The day preceding the operating day.
(11)
Entitlement or capacity entitlement--The right to purchase
and receive, under the applicable capacity auction master agreement, a block
of 25 megawatts (MW) of electrical capacity and energy from the assigned units
for a specific capacity auction product for one calendar month.
(12)
Forced outage--An unplanned component failure or other
condition that requires the unit be removed from service before the end of
the next weekend.
(13)
Holder--A person or entity that has acquired ownership
of an entitlement under the terms of the applicable capacity auction Master
Agreement.
(14)
Installed generation capacity--All potentially marketable
electric generation capacity owned by an affiliated PGC, including the capacity
of:
(A)
Generating facilities that are connected with a transmission
or distribution system;
(B)
Generating facilities used to generate electricity for
consumption by the person owning or controlling the facility; and
(C)
Generating facilities that will be connected with a transmission
or distribution system and operating within 12 months.
(15)
Master Agreement or Agreement--The applicable Capacity
Auction EEI/NEMA Master Power Purchase & Sale Agreement.
(16)
Starts--Direction by the holder of an entitlement to dispatch
a previously idle entitlement.
(17)
Texas jurisdictional installed generation capacity--The
amount of an affiliated PGC's installed generation capacity properly allocable
to the Texas jurisdiction. Such allocation shall be calculated pursuant to
an existing commission-approved allocation study, or other such commission-approved
methodology, and may be adjusted as approved by the commission to reflect
the effects of divestiture or the installation of new generation facilities.
(d)
General requirements. Subject to the qualifications for
auction entitlements and the auction process described in subsections (e)
and (h) of this section, each affiliated PGC subject to this section shall
sell at auction capacity entitlements equal to at least 15% of the affiliated
PGC's Texas jurisdictional installed generation capacity. Divestiture of a
portion of an affiliated PGC's Texas jurisdictional installed generation capacity
will be counted toward satisfaction of the affiliated PGC's capacity auction
requirement only if the divestiture is made pursuant to a commission order
in a business combination proceeding pursuant to PURA §14.101, and after
the transfer of the assets and operations to a third party.
(e)
Product types and characteristics.
(1)
Available entitlements and amounts. The following products,
defined separately in subsection (f) of this section for Electric Reliability
Council of Texas, Inc. (ERCOT) and in subsection (g) of this section for
non-ERCOT areas, shall be auctioned as capacity entitlements under subsection
(d) of this section. Upon showing of good cause by the affiliated PGC and
approval by the commission, an affiliated PGC may propose to auction entitlements
different from those described in this section, including unit-specific capacity.
Each affiliated PGC shall auction an amount of each applicable product in
proportion to the amount of Texas jurisdictional installed generating capacity
on the affiliated PGC's system that are the respective type of generating
units. An affiliated PGC that owns generation in multiple congestion zones
shall auction entitlements for delivery in each congestion zone. The amount
of each product auctioned in each zone shall be in proportion to the amount
of the respective type of generating units located in that zone, but the total
shall not be less than 15% of the affiliated PGC's Texas jurisdictional installed
generation capacity. The available entitlements for the months of March, April,
May, October, and November of each year may be reduced in proportion to the
average annual planned outage rate for the group of generating units associated
with each type of entitlement. Entitlements shall be for system capacity.
(2)
Forced outages. For any given congestion zone:
(A)
For all entitlements except those described in subparagraph
(B) of this paragraph, if all units providing capacity to an entitlement product
experience a forced outage or an emergency condition prevents or restricts
the ability of an affiliated PGC to dispatch a particular entitlement product,
the entitlements of that product may be reduced in proportion to the percentage
reduction in capacity of the units assigned to that entitlement; provided
that such reductions in availability of any single entitlement do not exceed
2.0% of the total monthly energy available from the entitlement.
(B)
For entitlements that are supported by two or fewer generating
units, if one or more of the units providing capacity to an entitlement product
experiences a forced outage or an emergency condition that prevents or restricts
the ability of an affiliated PGC to dispatch a particular entitlement product,
the entitlements of that product may be reduced in proportion to the percentage
reduction in capacity of the units assigned to that entitlement; provided
that such reductions in availability of any single entitlement do not exceed
the most recent three-year rolling average of the forced outage rate for the
unit(s) supporting the entitlement. The three-year rolling average of the
forced outage rate applicable to entitlements under this subparagraph shall
be included in the notice of capacity available for auction, under subsection
(h)(2)(B)(ii)(II) of this section.
(C)
Notification of any such reductions will take place as
soon as possible, but in any event, at least one hour prior to the hour-ahead
scheduling period applicable to when the reduction is to take place.
(3)
Planned outage. The total MW reduction for planned outages
is determined by calculating the average MW of monthly planned outage for
the generating plants associated with a product over the previous three calendar
years, multiplied by 12. The resulting planned outage hours are then rounded
down to the nearest whole entitlement (25 MW block). These "outage entitlements"
can then be removed from any of the five specified outage months (March, April,
May, October, and November) in any combination.
(4)
Generation units offered. If an affiliated PGC changes
the assignment of a power generation unit to one of the four available product
entitlements (baseload, gas-intermediate, gas-cyclic, or gas-peaking), then
the affiliated PGC shall file with the commission the proposed changes in
its assignment of each of its power generation units to one of the four available
product entitlements and the resulting amount of each type of entitlement
to be auctioned. As part of this filing, the affiliated PGC shall provide
planned outage histories for the years 1998, 1999, and 2000 for each generating
unit to be used to calculate the average annual planned outage rate for each
group of generating units. Interested parties shall have 30 days in which
to provide comments on the affiliated PGC's proposed changed assignments.
If no comments are received, the affiliated PGC's proposed assignment shall
be deemed appropriate. If any party objects to the affiliated PGC's proposed
assignments, then the commission shall determine the appropriate assignment
considering the manner in which the affiliated PGC expects to use such generation
units.
(5)
Obligations of affiliated PGC. The affiliated PGC shall
dispatch entitlements only as directed by the holder of the entitlement in
accordance with the applicable product description. The affiliated PGC may
not refuse to dispatch the entitlement and may not curtail the dispatch of
an entitlement unless expressly authorized by this section or by the applicable
Master Agreement, or unless directed to do so by the independent organization
in order to alleviate a system emergency. The affiliated PGC shall specify
in its notice provided pursuant to subsection (h)(2)(B) of this section the
point on the transmission system where energy from each entitlement is delivered
to the entitlement holder.
(6)
Entitlement holder receives no possessory interest or obligations.
(A)
No possessory interest. The entitlements sold at auction
shall include no possessory interest in the unit or units from which the power
is produced.
(B)
No possessory obligations. The entitlements sold at auction
shall include no obligation of a possessory owner of an interest in the unit
or units from which the power is produced.
(C)
Scheduling. The entitlement holder shall have the right
to designate the dispatch of the entitlement, subject to other provisions
of this subsection and the scheduling limitations provided for in the applicable
Agreement.
(7)
Credit requirements.
(A)
Standards. Entities submitting bids and all entitlement
holders shall satisfy one of the following credit standards:
(i)
The entity holds an investment grade credit rating (BBB-
or Baa3 from Standard and Poor's or Moody's respectively or an equivalent);
(ii)
The entity provides an escrowed deposit equal to the capacity
price for the shorter of the duration of the entitlement or three months plus
the amount that would be paid to exercise the entitlement for the shorter
of the duration of the entitlement or three months at the assumed dispatch
provided in either subsection (h)(6)(A)(iii) or subsection (h)(6)(C)(vi) of
this section;
(iii)
The entity provides a letter of credit or surety bond
equal to the capacity price for the shorter of the duration of the entitlement
or three months plus the amount that would be paid to exercise the entitlement
for the shorter of the duration of the entitlement or three-months at the
assumed dispatch provided in either subsection (h)(6)(A)(iii) or subsection
(h)(6)(C)(vi) of this section, irrevocable for the duration of the entitlement;
(iv)
The entity provides a guaranty from another entity with
an investment grade credit rating; or
(v)
The entity makes other suitable arrangements with the affiliated
PGC, provided that the affiliated PGC makes such arrangements available on
a non-discriminatory basis.
(B)
Unsecured credit. To be eligible for unsecured credit,
entities submitting bids shall satisfy the criteria in either clause (i),
(ii), or (iii) of this subparagraph, with the amount of unsecured credit to
be provided to such entities to be determined as follows:
(i)
For bidders with an investment grade credit rating. The
amount of credit available to a bidder relying on an investment grade credit
rating of itself or its guarantor will be determined according to procedures
set out below. If the bidding entity or its guarantor has an investment grade
credit rating and minimum equity of $100 million, the amount of credit available
will be determined using the lesser of $125 million, or the applicable percentage
of the bidder's stockholder equity set out in the following table, except
that the amount of credit will be reduced to the extent appropriate to take
into account any outstanding commitments that a bidder has for existing capacity
auction entitlements.
Figure: 16 TAC §25.381(e)(7)(B)(i)
(ii)
If the bidder is a municipality or cooperative not publicly
rated. If the bidder is a municipality or electric cooperative that is not
publicly rated but has a minimum equity (patronage capital) of $25 million,
a minimum times-interest-earned ratio (TIER) of 1.05, a minimum debt service
coverage (DSC) ratio of 1.00, and a minimum equity-to-assets ratio of 0.15,
then the amount of credit will be the lesser of $125 million or 5.0% of the
bidder's unencumbered assets, except that the amount of credit will be reduced
to the extent appropriate to take into account any outstanding commitments
that a bidder has for existing capacity auction entitlements.
(iii)
If the bidder is a privately-held entity not publicly
rated. If the bidder is a privately-held entity that is not publicly rated,
but has a minimum equity of $100 million, a minimum tangible net worth of
$100 million, a minimum current ratio of 1.0, a maximum debt-to-capital ratio
of 0.60, and a minimum ratio of earnings before interest, taxes, depreciation,
and amortization (EBITDA) to interest and current maturities of long term
debt (CMLTD) of 2.0, then the amount of credit will be the lesser of $125
million or 1.80% of the bidder's stockholder equity, except that the amount
of credit will be reduced to the extent appropriate to take into account any
outstanding commitments that a bidder has for existing capacity auction entitlements.
(C)
All cash and other instruments used as credit security
shall be unencumbered by pledges for collateral.
(D)
If a bidder or entitlement holder chooses to use a surety
bond to satisfy its credit requirements, then the form of such surety bond
will be negotiated in good faith between the bidder or entitlement holder
and the affiliated PGC and reasonably acceptable by an issuer of surety bonds.
(E)
In the event the holder of the entitlement initially relied
on its investment grade credit rating but subsequently loses it during the
entitlement period, the holder of the entitlement shall provide alternative
financial evidence within three business days.
(F)
The holder of the entitlement shall notify the affiliated
PGC of any material changes that impact its compliance with the financial
requirements it relied on in meeting the credit standards in this section.
(G)
In the event the holder or seller of the entitlement fails
to meet or continue to meet its security requirement, or an Event of Default
results in the termination of the Agreement, the entitlement shall revert
to the affiliated PGC and shall be auctioned in the next auction for which
notice can be provided of the sale of the entitlement pursuant to subsection
(h)(2)(B) of this section.
(H)
If an entitlement holder's creditworthiness or financial
security materially and adversely changes after the auction is completed,
as a result of an event specified in the Agreement, the affiliated PGC shall
provide the entitlement holder with written notice requesting additional credit
support or performance assurance in a commercially reasonable manner, as set
forth in the Agreement. The seller's credit requirements shall clearly identify
objective criteria that would trigger a request for additional security and
the methods and time frame in which an entitlement holder must satisfy such
a request. The affiliated PGC may suspend delivery of any capacity or energy
for which the affiliated PGC has not already received payment until the performance
assurance is received, in accordance with the Agreement.
(I)
If at any time after the auction is completed, there shall
occur a downgrade event with respect to the credit standing of the seller,
then the entitlement holder may require the seller to provide a credit assurance
in an amount determined by the entitlement holder in a commercially reasonable
manner. In the event the seller fails to provide a commercially reasonable
performance assurance or guarantee within three business days of the receipt
of notice, then an event of default shall be deemed to have occurred, and
the entitlement holder will be entitled to suspend performance under the Agreement
and withhold payments for energy not yet delivered, and may ultimately terminate
the Agreement after the suspension period as prescribed in the Agreement.
(f)
Product descriptions for capacity auctions in ERCOT. The
provisions in this subsection apply to capacity auctions in ERCOT. Subsection
(g) of this section contains provisions applicable to capacity auctions in
non-ERCOT areas.
(1)
Definitions.
(A)
The following words and terms, when used in this subsection
shall have the following meanings, unless the context indicates otherwise.
(i)
Balancing energy service down deployed--The number of megawatt-hours
(MWh) of balancing energy service down deployed by ERCOT from an entitlement.
(ii)
Balancing energy service up deployed--The number of MWh
of balancing energy service up deployed by ERCOT from an entitlement.
(iii)
Daily capacity commitment--The amount of capacity scheduled
by an entitlement holder that an affiliated PGC must make available from an
entitlement for the provision of energy or permitted ancillary services for
an operating day from an entitlement.
(iv)
Day-ahead schedule--A schedule submitted by an entitlement
holder to an affiliated PGC of the entitlement holder's scheduled usage of
the entitlement for the following operating day.
(v)
Default qualifying scheduling entity (QSE)--The QSE that
is designated by the entitlement holder to ERCOT as its default QSE.
(vi)
Energy scheduled--The final schedule for energy, for each
settlement interval, that an entitlement holder submits to an affiliated PGC,
subject to the limits on timing and amounts of schedules contained in the
capacity auction product descriptions.
(vii)
Energy deployed down--The sum of regulation energy down
energy deployed and balancing energy service down energy deployed.
(viii)
Energy deployed up--The sum of regulation energy up
energy deployed, responsive energy deployed, non-spinning energy deployed,
and balancing energy service up energy deployed.
(ix)
Grouped entitlements--All of the entitlements from an
affiliated PGC that an entitlement holder holds for a particular entitlement
month.
(x)
Grouped ancillary services--The amount of each type of
ancillary service available from each entitlement grouped by:
(I)
Type of ancillary service;
(II)
Type of capacity auction product; and
(III)
Congestion zone for those ancillary services that are,
or may be, dispatched by congestion zone.
(xi)
Hour-ahead schedule--A schedule other than a day-ahead
schedule submitted by an entitlement holder to an affiliated PGC no later
than one hour before the end of an adjustment period of the entitlement holder's
scheduled use of the entitlement for the operating hour corresponding to that
adjustment period.
(xii)
Non-spinning energy deployed--Energy deployed by ERCOT
from the non-spinning reserve service as determined under the procedures in
paragraph (2)(B) of this subsection.
(xiii)
Product--Electric capacity, energy, capacity auction
products or other product(s) related thereto as specified in a transaction
by reference to a product listed in the Agreement or as otherwise specified
by the parties in a transaction.
(xiv)
Regulation energy down deployed--Energy deployed down
by ERCOT from the regulation energy service as determined under the procedures
of paragraph (2)(B) of this subsection.
(xv)
Regulation energy up deployed--Energy deployed up by ERCOT
from the regulation service as determined under the procedures of paragraph
(2)(B) of this subsection.
(xvi)
Responsive energy deployed--Energy deployed by ERCOT
from the responsive reserve service as determined under the procedures of
paragraph (2)(B) of this subsection.
(xvii)
Two-day-ahead schedule--A schedule submitted by the
entitlement holder to the affiliated PGC of the entitlement holder's scheduled
usage of the entitlement for the operating day two days in the future.
(B)
The following terms have the respective meanings given
to them in the ERCOT protocols as amended from time to time:
(i)
Ancillary services;
(ii)
Balancing energy service;
(iii)
Congestion zone;
(iv)
Non-spinning reserve service;
(v)
Operating day;
(vi)
Operating hour;
(vii)
Regulation service;
(viii)
Responsive reserve service;
(ix)
Settlement interval; and
(x)
Zonal market clearing price.
(2)
General provisions.
(A)
Responsibility transfers.
(i)
The entitlement holder may not use an entitlement for the
provision of balancing energy service until a responsibility transfer (RT)
between the entitlement holder's QSE and the affiliated PGC's QSE is established
and operated in accordance with the ERCOT protocols for the deployment of
balancing energy service. The entitlement holder shall establish a separate
RT with the affiliated PGC for each congestion zone from which the entitlement
holder desires to provide balancing energy service.
(ii)
When ERCOT has developed the details and specifications
of RTs between QSEs, including without limitation, mechanics, settlement,
and communication, then, at the request of the entitlement holder, the parties
shall negotiate in good faith to transfer responsibility between their respective
QSEs to:
(I)
Allow the entitlement holder to provide balancing energy
service from the entitlement; and
(II)
Allocate the cost of establishing that capability.
(iii)
The entitlement holder's QSE shall act as the controller
of RTs used for balancing energy service from an entitlement. The entitlement
holder's QSE shall use RTs to provide instructions regarding balancing energy
service to the affiliated PGC's QSE. These instructions shall comply with
all the limitations in the applicable capacity auction product description.
(iv)
Both the entitlement holder's QSE and the affiliated PGC's
QSE shall enter an inter-QSE trade in accordance with the ERCOT protocols
to represent an RT before any operating hour in which the entitlement holder
deploys balancing energy service from an entitlement.
(v)
The affiliated PGC's QSE is only responsible for complying
with RTs sent by the entitlement holder's QSE and is not responsible for ERCOT
instructions sent to the entitlement holder.
(vi)
The affiliated PGC and the entitlement holder shall rely
upon any integration of the RT over each settlement interval performed by
ERCOT. If ERCOT does not perform that integration, then the integration shall
be performed in a manner mutually agreed to by both parties.
(vii)
The entitlement holder is deemed not to have provided
any balancing energy service from an entitlement if the affiliated PGC loses
or does not receive the balancing energy service signal from ERCOT. The affiliated
PGC will promptly notify the entitlement holder if it does not receive or
loses the balancing energy service signal from ERCOT.
(B)
Deployment of energy from ancillary services. Subject to
the limitations and conditions set out in this subsection, and except when
the affiliated PGC is excused from hierarchical dispatch by ERCOT of ancillary
services under clause (i) or (v) of this subparagraph, ERCOT shall be deemed
to have dispatched ancillary services from the entitlements in the entitlement
group in a hierarchical order according to the requirements of this subsection.
Otherwise, ancillary services shall be dispatched for each entitlement in
an entitlement group independently.
(i)
Notice of grouped entitlements. Not later than five days
before the beginning of an entitlement month, the entitlement holder shall
notify the affiliated PGC of all entitlements from the affiliated PGC that
are held by the entitlement holder for that entitlement month. The list shall
contain sufficient detail for the affiliated PGC to identify the entitlements
held by the entitlement holder for that month, including without limitation
any unique entitlement number assigned by the affiliated PGC to the entitlement
and listed on the letter confirmation for the entitlement. If the affiliated
PGC does not timely receive this notice, then the affiliated PGC is excused
from its obligation to dispatch ancillary services on a hierarchical basis
under this section.
(ii)
Amount of ancillary services scheduled from entitlements.
(I)
The affiliated PGC shall track the amount of each ancillary
service for each operating hour and the amount of each ancillary service scheduled
by the entitlement holder for each operating hour, both for individual entitlements
and for each grouped entitlement.
(II)
For ancillary services other than the balancing energy
service, which is determined by an RT, the amount of ancillary service scheduled
from each entitlement and for each grouped entitlement for an operating hour
is the amount stated in the final timely schedule submitted by the entitlement
holder to the affiliated PGC for that operating hour for each entitlement
or the entitlement group.
(iii)
Deployed ancillary services.
(I)
For balancing energy service, the amount of energy that
ERCOT is deemed to have deployed is determined by the integration described
in subparagraph (A) of this paragraph.
(II)
For all ancillary services other than balancing energy
service, the affiliated PGC shall track the deployment of ancillary services
from the entitlement group by each grouped ancillary service for each hour
in the entitlement month, except for hours in which the affiliated PGC is
excused from dispatching ancillary services on a hierarchical basis under
clause (i) or (v) of this subparagraph. The total amount of each grouped ancillary
service deployed in an hour shall be calculated by the product of:
(-a-)
The ratio of the amount of the grouped ancillary service
scheduled by the entitlement holder from its grouped entitlements to the total
amount of that specific ancillary service scheduled from resources in the
affiliated PGC's QSE;
(-b-)
The amount of energy deployed out of that grouped ancillary
service in a particular congestion zone or in ERCOT as a whole, whichever
is applicable.
(III)
For all ancillary services other than balancing energy
service, the amount of each ancillary service that ERCOT is deemed to have
deployed from each entitlement, for hours in which the affiliated PGC is excused
from dispatching ancillary services on a hierarchical basis under clause (i)
or (v) of this subparagraph, shall be calculated by the product of:
(-a-)
The ratio of the amount of that ancillary service scheduled
by the entitlement holder from the entitlement to the total amount of that
specific ancillary service scheduled from resources in the affiliated PGC's
QSE;
(-b-)
The amount of energy deployed by ERCOT out of that ancillary
service in a particular congestion zone or in ERCOT as a whole, whichever
is applicable.
(iv)
Hierarchical deployment of grouped ancillary services.
(I)
For determination of the contract price for each entitlement
in a grouped entitlement, ERCOT is deemed to have first deployed grouped ancillary
services that are deployed by congestion zone pursuant to subclause (III)
of this clause with the amount for each entitlement spread proportionally
among the entitlement holder's entitlements of that type in that congestion
zone.
(II)
After deploying grouped ancillary services by congestion
zone pursuant to subclause (I) of this clause, ERCOT is deemed to have deployed
the remainder of each grouped ancillary service pursuant to subclause (III)
of this clause, with the amount for each type of entitlement spread proportionally
among the entitlement holder's entitlements of that type in ERCOT.
(III)
Deployed energy shall be assigned to the entitlement
holder's entitlements that scheduled those ancillary services on a hierarchical
basis as follows:
(-a-)
For incremental deployments:
(-1-)
First: Baseload entitlements, with the highest priority
given to the Baseload entitlements with the lowest energy price;
(-2-)
Second: Gas-intermediate entitlements;
(-3-)
Third: Gas-cyclic entitlements; and
(-4-)
Fourth: Gas-peaking entitlements.
(-b-)
For decremental deployments:
(-1-)
First: Gas-peaking entitlements;
(-2-)
Second: Gas-cyclic entitlements;
(-3-)
Third: Gas-intermediate entitlements; and
(-4-)
Fourth: Baseload entitlements, with the highest priority
given to the Baseload entitlements with the highest energy price.
(v)
Exception to dispatching on hierarchical basis. The affiliated
PGC is not required to dispatch ancillary services from the entitlement group
on a hierarchical basis if the affiliated PGC does not have the information
necessary to dispatch ancillary services from the entitlement group in a hierarchical
fashion. Necessary information includes, but is not limited to, the signal
from ERCOT deploying balancing energy service or the signal from ERCOT deploying
other ancillary services.
(3)
Baseload product.
(A)
Baseload scheduling.
(i)
Schedule types. The entitlement holder shall submit a day-ahead
schedule for the entitlement. The entitlement holder shall submit a two-day-ahead
schedule for the entitlement if notified to do so by ERCOT.
(ii)
Timing of scheduling. All of the times for scheduling
referred to in this subparagraph are based on the times in the ERCOT protocols.
If the times in the ERCOT protocols are changed, then the times in this subparagraph
will be considered to have changed to equitably accommodate the changes in
the ERCOT protocols.
(I)
The entitlement holder shall submit day-ahead or two-day-ahead
schedules for the entitlement to the affiliated PGC no later than 8:00 a.m.
The entitlement holder shall submit hour-ahead schedules for ancillary services
from the entitlement to the affiliated PGC no later than one hour before the
deadline for the affiliated PGC's QSE to submit hour-ahead schedules to ERCOT.
(II)
On days that ERCOT allows QSEs to change their day-ahead
or two-day-ahead schedules to ERCOT by 1:00 p.m. for congestion or capacity
insufficiency, the entitlement holder may submit a revised day-ahead or two-day-ahead
schedule for energy from the entitlement to the affiliated PGC no later than
noon.
(III)
The entitlement holder may submit to the affiliated PGC
a revised day-ahead or two-day-ahead schedule for the non-spinning reserve
ancillary services from the entitlement no later than 1:45 p.m. The entitlement
holder cannot change the amount of energy scheduled in a revised schedule
for the non-spinning reserve ancillary services.
(IV)
No hour-ahead schedules are permitted for energy from
baseload entitlements. Hour-ahead schedules are permitted for ancillary services
from baseload entitlements.
(iii)
Schedule content. Each schedule shall specify, for each
settlement interval, the MW of energy scheduled to be delivered to the entitlement
holder from the entitlement and the MW of each permitted ancillary service
to be scheduled from the entitlement, subject to the scheduling limits in
clause (iv) of this subparagraph.
(iv)
Scheduling limits.
(I)
Minimum energy. The entitlement holder may not schedule
energy at less than 20 MW from the entitlement at any time during the month.
(II)
Ancillary services. The entitlement holder may use a baseload
entitlement to provide responsive reserve service at a level of one MW, and
non-spinning reserve service, up to a combined total of three MW. The baseload
entitlement may not be used for any other ancillary service. Non-spinning
reserve service may be provided from the entitlement in 30 minutes, and responsive
reserve service may be provided from the entitlement in ten minutes.
(III)
Maximum changes. Subject to the minimum energy rate specified
in subclause (I) of this clause, the rate at which the entitlement holder
schedules energy in each hour generally cannot change more than plus or minus
two MW. The following additional restrictions apply.
(-a-)
If the entitlement holder schedules or reserves any ancillary
services in an hour, then the level of energy scheduled shall be the same
in each settlement interval of the hour.
(-b-)
The maximum change in ancillary services scheduled from
the first settlement interval in one hour to the first settlement interval
of the next hour is plus or minus three MW.
(-c-)
The maximum change in energy scheduled from the first
settlement interval in one hour to the first settlement interval in the next
hour is plus or minus two MW.
(-d-)
The maximum change in energy scheduled from one settlement
interval to the next is plus or minus one MW.
(IV)
Starts. The entitlement holder shall schedule energy from
a baseload entitlement for every settlement interval and may not direct any
starts of the entitlement.
(V)
Default schedule. If the entitlement holder does not submit
a timely day-ahead or two-day ahead schedule, as applicable, then the schedule
for the applicable operating day is deemed to be 20 MW of energy and zero
MW of ancillary services to be delivered to the entitlement holder's designated
default QSE in every settlement interval of the applicable operating day.
(B)
Contract price for baseload. The items included in the
contract price between the entitlement holder and the affiliated PGC for the
entitlement shall include:
(i)
Capacity payment. The capacity payment from the entitlement
holder to the affiliated PGC is the capacity price in dollars per MW specified
in the letter confirmation for the entitlement times 25 MW.
(ii)
Energy payment. The fuel cost owed to the affiliated PGC
by the entitlement holder for the dispatched baseload power will be the average
cost of coal, lignite, and nuclear fuel (in dollars per MWh), as applicable
to the appropriate congestion zone in which the underlying generation units
are located, based on the affiliated PGC's final excess cost over market (ECOM)
model as determined pursuant to PURA §39.201. Affiliated PGCs of the
electric utilities without an ECOM determination in their proceeding conducted
pursuant to PURA §39.201 shall propose, for commission review, an average
cost of fuel in a similar manner. The energy payment from the entitlement
holder to the affiliated PGC is the fuel cost in dollars per MWh for the entitlement
times the greater of:
(I)
The sum of the total energy scheduled from the entitlement
during the entitlement month plus energy deployed up from the entitlement
during the entitlement month; or
(II)
An amount of MWh equal to 20 MW times the number of hours
in the entitlement month.
(iii)
Ancillary services payment. For baseload entitlements,
the ancillary services payment to be paid by the entitlement holder to the
affiliated PGC is zero.
(iv)
Energy deployed up reimbursement payment. For energy deployed
up, for all settlement intervals in the entitlement month, the affiliated
PGC shall pay the entitlement holder the sum of the zonal market clearing
price of energy (MCPE) in dollars per MWh paid by ERCOT for that settlement
interval times the energy deployed up in that settlement interval.
(v)
Energy deployed down reimbursement payment. For energy
deployed down for all settlement intervals in the entitlement month, the entitlement
holder shall pay the affiliated PGC the sum of the MCPE in dollars per MWh
paid to ERCOT for that settlement interval times the energy deployed down
in that settlement interval.
(C)
Timing of payment of contract price. The entitlement holder
shall pay the affiliated PGC the capacity payment portion of the contract
price not less than five days before the beginning of the entitlement month
or 20 days after receiving an invoice for the capacity payment from the affiliated
PGC, whichever is later. The entitlement holder shall pay the remainder of
the contract price to the affiliated PGC after receiving an invoice for that
amount in accordance with the other terms of the applicable Agreement. If
the affiliated PGC owes the entitlement holder any net amount under the contract
price calculation, it will pay that amount to the entitlement holder in accordance
with the other terms of the Agreement.
(4)
Gas-intermediate product.
(A)
Gas-intermediate scheduling.
(i)
Schedule types. The entitlement holder shall submit a day-ahead
schedule for the entitlement and may submit hour-ahead schedules. The entitlement
holder shall submit a two-day-ahead schedule for the entitlement if notified
to do so by ERCOT.
(ii)
Timing of scheduling. All of the times for scheduling
referred to in this subparagraph are based on the times in the ERCOT protocols.
If the times in the ERCOT protocols are changed, then the times in this subparagraph
will be considered to have changed to equitably accommodate the changes in
the ERCOT protocols.
(I)
The entitlement holder shall submit day-ahead or two-day-ahead
schedules for the entitlement to the affiliated PGC no later than 8:00 a.m.
The daily capacity commitment is determined for a gas-intermediate entitlement
by the 8:00 a.m. schedule. The entitlement holder shall submit hour-ahead
schedules for ancillary services for the entitlement to the affiliated PGC
no later than one hour before the deadline for the affiliated PGC's QSE to
submit hour-ahead schedules to ERCOT.
(II)
The entitlement holder may submit to the affiliated PGC
a revised day-ahead or two-day-ahead schedule for energy from the entitlement
no later than 10:00 a.m., subject to the limit on maximum energy in clause
(iv)(I)(-b-) of this subparagraph.
(III)
On days that ERCOT allows QSEs to change their day-ahead
or two-day-ahead schedules to ERCOT by 1:00 p.m. for congestion or capacity
insufficiency, the entitlement holder may submit a revised day-ahead or two-day-ahead
schedule for energy from the entitlement to the affiliated PGC no later than
noon, subject to the limit on maximum energy in clause (iv)(I)(-b-) of this
subparagraph.
(IV)
The entitlement holder may submit to the affiliated PGC
a revised day-ahead or two-day-ahead schedule for ancillary services from
the entitlement no later than 1:45 p.m. The entitlement holder cannot change
the amount of energy scheduled in a revised schedule for ancillary services.
(V)
No hour-ahead schedules are permitted for energy from gas-intermediate
entitlements. Hour-ahead schedules are permitted for ancillary services from
gas-intermediate entitlements.
(iii)
Schedule content. Each schedule shall specify:
(I)
For each settlement interval, the MW of energy scheduled
to be delivered to the entitlement holder from the entitlement; and
(II)
For each hour, the MW scheduled to be reserved for the
entitlement holder's use of each ancillary service from the entitlement. The
entitlement holder shall include any MW bid (but not pricing) for the balancing
energy up and balancing energy down ancillary services on the schedule.
(iv)
Scheduling limits.
(I)
Total. Generally, the rate at which energy is scheduled
cannot change more than plus or minus six MW and the rate at which ancillary
services is reserved or scheduled by the entitlement holder in each hour cannot
change more than plus or minus six MW. The restrictions in items (-a-) and
(-b-) of this subclause apply.
(-a-)
Minimum energy. The entitlement holder may not schedule
energy at less than eight MW from the entitlement at any time during the month,
unless the entitlement holder has elected the gas-intermediate Start Option,
in which case the entitlement holder may reduce energy below eight MW as specified
in subclause (IV)(-a-) of this clause.
(-b-)
Maximum energy. The entitlement holder may not schedule
energy at any level greater than the daily capacity commitment in any settlement
interval.
(II)
Maximum changes. Subject to the limitations specified
in subclause (I) of this clause:
(-a-)
Generally, the rate at which energy is scheduled by the
entitlement holder in each hour cannot change more than plus or minus six
MW and the rate at which ancillary services are scheduled or reserved by the
entitlement holder in each hour cannot change more than plus or minus six
MW. The restrictions in items (-b-) and (-c-) apply.
(-b-)
Energy. Subject to the maximum change specified in item
(-a-) of this subclause:
(-1-)
The maximum change in energy scheduled from the first
settlement interval in one hour to the first settlement interval of the next
hour is plus or minus six MW.
(-2-)
Subject to the limitation in subitem (-1-) of this item,
the maximum change in energy scheduled from one settlement interval to the
next is plus or minus two MW.
(-c-)
Ancillary services. Subject to the maximum change specified
in item (-a-) of this subclause, the maximum change in ancillary services
scheduled from the first settlement interval in one hour to the first settlement
interval of the next hour is plus or minus six MW.
(III)
Ancillary services. Subject to the limitations in subclauses
(I) and (II) of this clause:
(-a-)
The total MW of non-spinning reserve service, regulation
service up, regulation service down, responsive reserve service, and balancing
energy service up and balancing energy service down from the entitlement in
one hour shall not exceed ten MW;
(-b-)
Subject to the limitations in item (-a-) of this subclause,
the total MW of regulation service up, regulation service down, responsive
reserve service, and bids for balancing energy service up and balancing energy
service down from the entitlement in one hour shall not exceed:
(-1-)
Four MW if the entitlement holder schedules any two-MW
changes in the levels of energy within the hour;
(-2-)
Five MW if the entitlement holder schedules any one-MW,
but not two-MW changes in the levels of energy within the hour; or
(-3-)
Six MW if the entitlement holder does not schedule any
changes in the levels of energy within the hour.
(-c-)
In addition to the limitations in items (-a-) and (-b-)
of this subclause, the total MW of non-spinning reserve service, regulation
service up, responsive reserve service, and balancing energy service up from
the entitlement in a settlement interval shall not exceed an amount of MW
equal to the daily capacity commitment for the settlement interval minus the
energy scheduled for that settlement interval.
(-d-)
In addition to the limitations in items (-a-), (-b-),
and (-c-) of this subclause, the total MW of regulation service down and balancing
energy service down from the entitlement in a settlement interval shall not
exceed an amount of MW equal to the energy scheduled for that settlement interval
minus eight MW.
(-e-)
In addition to the limitations in items (-a-), (-b-),
and (-c-) of this subclause, if the energy schedule is at zero as permitted
under subclause (IV)(-a-) of this clause, then the entitlement holder may
not schedule any ancillary services from the gas-intermediate entitlement.
(-f-)
Non-spinning reserve service may be provided from the
entitlement in 30 minutes, and other permitted ancillary services may be provided
from the entitlement in ten minutes.
(IV)
Starts, minimum off time, and minimum run time.
(-a-)
The entitlement holder may reduce the energy schedule
from the gas-intermediate entitlement to zero MW two times during the entitlement
month.
(-b-)
Once the energy schedule is reduced to zero, it shall
remain at zero for not less than 48 hours.
(-c-)
If the entitlement holder increases the energy schedule
from zero, then energy shall be scheduled at a minimum of eight MW, and the
energy schedule may not be reduced to zero again for at least 72 hours after
the energy schedule increased from zero.
(v)
Default schedule. If the entitlement holder does not submit
a timely day-ahead or two-day ahead schedule, as applicable, then the schedule,
for the applicable operating day is deemed to be, in every settlement interval
of the applicable operating day, eight MW for the daily capacity commitment,
eight MW of energy to be delivered to the entitlement holder's designated
default QSE, and zero MW of ancillary services, and that deemed schedule may
not be changed in any hour-ahead schedule. However, if the entitlement holder
has used up its allowable starts for the entitlement month, then the schedule
for the applicable operating day is deemed to be, in every settlement interval
of the applicable operating day, zero MW for the daily capacity commitment.
(B)
Gas-intermediate ancillary services. Subject to the scheduling
limits in subparagraph (A) of this paragraph, the entitlement holder may use
the entitlement in any one hour for one or more of these ancillary services:
regulation service up, regulation service down, responsive reserve service,
non-spinning reserve service, balancing energy service up, and balancing energy
service down. When ERCOT requires mandatory balancing energy down bids, then
the affiliated PGC shall so notify the entitlement holder, and the entitlement
holder shall then submit a balancing energy down bid to ERCOT in the same
percentage that ERCOT requires of the affiliated PGC, subject to the MW limits
for gas-intermediate in the applicable Schedule CA of the applicable Agreement.
(C)
Contract price for gas-intermediate. The items included
in the contract price between the entitlement holder and the affiliated PGC
for the entitlement shall include:
(i)
Capacity payment. The capacity payment from the entitlement
holder to the affiliated PGC is the capacity price in dollars per MW specified
in the letter confirmation for the entitlement times 25 MW.
(ii)
Energy payment.
(I)
The energy payment from the entitlement holder to the affiliated
PGC for each settlement interval in the entitlement month, is the sum of the
minimum energy payment and the excess energy payment.
(-a-)
The minimum energy payment is the product of the number
of hours in the entitlement month at which the energy level is not zero as
permitted under subparagraph (A)(iv)(IV)(-a-) of this paragraph, times eight
MWh, times the minimum fuel price.
(-b-)
The excess energy payment for each settlement interval
is the excess fuel price defined in subclause (II)(-b-) of this clause, times
(energy scheduled minus two MWh plus energy deployed up minus energy deployed
down).
(II)
Fuel price.
(-a-)
The minimum fuel price is a heat rate equal to 9.9 Million
British Thermal Units (MMBtu) per MWh times the daily gas price.
(-b-)
The excess fuel price is a heat rate equal to 9.9 MMBtu
per MWh times the daily gas price.
(iii)
Ancillary services payment.
(I)
The ancillary services cost adjustment payment to be paid
by the entitlement holder to the affiliated PGC is the ancillary services
cost defined in subclause (II) of this clause times the difference, for each
settlement interval of the entitlement, between the daily capacity commitment
and energy scheduled.
(II)
The ancillary services cost is a heat rate adjustment
equal to 1.015 MMBtu per MW times the daily gas price.
(iv)
Energy deployed up reimbursement payment. For energy deployed
up for all settlement intervals in the entitlement month, the affiliated PGC
shall pay the entitlement holder the MCPE in dollars per MWh paid by ERCOT
for a settlement interval times the energy deployed up in a settlement interval.
(v)
Energy deployed down reimbursement payment. For energy
deployed down for all settlement intervals in the entitlement month, the entitlement
holder shall pay the affiliated PGC the MCPE in dollars per MWh paid to ERCOT
for a settlement interval times the energy deployed down in a settlement interval.
(D)
Timing of payment of contract price. The entitlement holder
shall pay the affiliated PGC the capacity payment portion of the contract
price not less than five days before the beginning of the entitlement month
or 20 days after receiving an invoice for the capacity payment from the affiliated
PGC, whichever is later. The entitlement holder shall pay the remainder of
the contract price after receiving an invoice for that amount in accordance
with the Agreement. If the affiliated PGC owes the entitlement holder any
net amount under the contract price calculation, it will pay that amount to
the entitlement holder in accordance with the Agreement.
(5)
Gas-cyclic.
(A)
Gas-cyclic scheduling.
(i)
Schedule types. The entitlement holder shall submit a day-ahead
schedule for the entitlement and may submit hour-ahead schedules for both
energy and ancillary services. The entitlement holder shall submit a two-day-ahead
schedule for the entitlement if notified to do so by ERCOT.
(ii)
Timing of scheduling. All of the times for scheduling
referred to in this subparagraph are based on the times in the ERCOT protocols.
If the times in the ERCOT protocols are changed, then the times in this subparagraph
will be considered to have changed to equitably accommodate the changes in
the ERCOT protocols.
(I)
The entitlement holder shall submit day-ahead or two-day-ahead
schedules for the entitlement to the affiliated PGC no later than 8:00 a.m.
The daily capacity commitment is determined for a gas-cyclic entitlement by
the 8:00 a.m. schedule, unless the entitlement holder notifies the affiliated
PGC, in the schedule, that it is exercising its option to set the daily capacity
commitment in the last schedule submitted before the gas-cyclic start deadline
defined in subclause (V) of this clause. The entitlement holder shall submit
hour-ahead schedules for the entitlement to the affiliated PGC no later than
one hour before the deadline for the affiliated PGC's QSE to submit hour-ahead
schedules to ERCOT.
(II)
The entitlement holder may submit to the affiliated PGC
a revised day-ahead or two-day-ahead schedule for energy from the entitlement
no later than 10:00 a.m.
(III)
On days that ERCOT allows QSEs to change their day-ahead
or two-day ahead schedules to ERCOT by 1:00 p.m. for congestion or capacity
insufficiency, the entitlement holder may submit a revised day-ahead or two-day-ahead
schedule for energy from the entitlement to the affiliated PGC no later than
noon.
(IV)
The entitlement holder may submit to the affiliated PGC
a revised day-ahead or two-day-ahead schedule for ancillary services from
the entitlement no later than 1:45 p.m.
(V)
The gas-cyclic start deadline for declaring the daily capacity
commitment for each settlement interval in an operating hour is 14 hours before
the end of the adjustment period for that operating hour.
(iii)
Schedule content. Each schedule shall specify:
(I)
For each settlement interval, the MW of energy scheduled
to be delivered to the entitlement holder from the entitlement; and
(II)
For each hour, the MW scheduled to be reserved for the
entitlement holder's use of each ancillary service from the entitlement. The
entitlement holder shall include any MW bid (but not pricing) for the balancing
energy up and balancing energy down ancillary services on the schedule.
(iv)
Scheduling limits.
(I)
Total. Generally, the rate at which energy is scheduled
cannot change more than plus or minus six MW and the rate at which ancillary
services is reserved or scheduled by the entitlement holder in each hour cannot
change more than plus or minus six MW. The restrictions in items (-a-) and
(-b-) of this subclause apply.
(-a-)
Minimum energy. The entitlement holder may not schedule
energy at any level between zero MW and five MW from the entitlement at any
time during the month.
(-b-)
Maximum energy. The entitlement holder may not schedule
energy at any level greater than the daily capacity commitment in any settlement
interval after the entitlement holder designates its daily capacity commitment.
(II)
Maximum changes. Subject to the limits specified in subclause
(I) of this clause:
(-a-)
The maximum change in the rate at which energy is scheduled
from the first settlement interval in one hour to the first settlement interval
in the next hour is plus or minus six MW;
(-b-)
Subject to the limitation in item (-a-) of this subclause,
the maximum change in the rate at which energy is scheduled from one settlement
interval to the next is plus or minus two MW; and
(-c-)
Subject to the limitation specified in item (-a-) of
this subclause, the maximum change in ancillary services scheduled from the
first settlement interval in one hour to the first settlement interval of
the next hour is plus or minus six MW.
(III)
Ancillary services. Subject to the limitations in subclauses
(I) and (II) of this clause:
(-a-)
The total MW of non-spinning reserve service, regulation
service up, regulation service down, responsive reserve service, and balancing
energy service up and balancing energy service down from the entitlement in
one hour shall not exceed ten MW;
(-b-)
Subject to the limitations in item (-a-) of this subclause,
the total MW of regulation service up, regulation service down, responsive
reserve service, and bids for balancing energy service up and balancing energy
service down from the entitlement in one hour shall not exceed:
(-1-)
Four MW if the entitlement holder schedules any two-MW
changes in the levels of energy within the hour;
(-2-)
Five MW if the entitlement holder schedules any one-MW,
but not two-MW changes in the levels of energy within the hour; or
(-3-)
Six MW if the entitlement holder does not schedule any
changes in the levels of energy within the hour.
(-c-)
In addition to the limitations in items (-a-) and (-b-)
of this subclause, the total MW of non-spinning reserve service, regulation
service up, responsive reserve service, and balancing energy service up from
the entitlement in a settlement interval shall not exceed an amount of MW
equal to the daily capacity commitment for the settlement interval minus the
energy scheduled for that settlement interval.
(-d-)
In addition to the limitations in items (-a-), (-b-),
and (-c-) of this subclause, the total MW of regulation service down and balancing
energy service down from the entitlement in a settlement interval shall not
exceed an amount of MW equal to the energy scheduled for that settlement interval
minus five MW.
(-e-)
Non-spinning reserve service may be provided from the
entitlement in 30 minutes, and other permitted ancillary services may be provided
from the entitlement in ten minutes.
(IV)
Starts. Subject to the limits specified in subclause (I)
- (III) of this clause, the entitlement holder may not direct more than 20
starts during the month of the entitlement, and the entitlement holder may
not direct more than one start per day. A start occurs every time a schedule
increases the MW of energy from zero MW. Once 20 starts have occurred during
the entitlement, the energy scheduled by the entitlement holder may not be
lower than a rate of five MW unless that level is lowered to zero MW, at which
time the level may not be raised above zero MW for the remainder of the entitlement.
(v)
Default schedule. If the entitlement holder does not submit
a timely day-ahead or two-day ahead schedule, as applicable, then the schedule
for the applicable operating day is deemed to be, in every settlement interval
of the applicable operating day, zero MW for the daily capacity commitment,
zero MW of energy, and zero MW of ancillary services. This deemed schedule
may not be changed in any hour-ahead schedule.
(B)
Gas-cyclic ancillary services. Subject to the scheduling
limits in subparagraph (A) of this paragraph, the entitlement holder may use
the entitlement in any one hour for one or more of these ancillary services:
regulation service up, regulation service down, responsive reserve service,
non-spinning reserve service, balancing energy service up, and balancing energy
service down. When ERCOT requires mandatory balancing energy service down
bids, then the affiliated PGC shall so notify the entitlement holder, and
the entitlement holder shall then submit a balancing energy service down bid
in the same percentage that ERCOT requires of the affiliated PGC, subject
to the MW limits for gas-cyclic in this paragraph.
(C)
Contract price for gas-cyclic. The items to be included
in the contract price between the entitlement holder and the affiliated PGC
for the entitlement shall include:
(i)
Capacity payment. The capacity payment from the entitlement
holder to the affiliated PGC is the capacity price in dollars per MW specified
in the letter confirmation for the entitlement times 25 MW.
(ii)
Energy payment.
(I)
The energy payment for each settlement interval from the
entitlement holder to the affiliated PGC is the fuel price defined in subclause
(II) of this clause times (energy scheduled plus energy deployed up minus
energy deployed down.)
(II)
Fuel price.
(-a-)
The fuel price, for the portion of the daily capacity
commitment that is designated by the entitlement holder by 8:00 a.m. in the
day-ahead or two-day-ahead schedule, is a heat rate equal to 12.100 MMBtu
per MWh times the daily gas price.
(-b-)
The fuel price, for the portion of the daily capacity
commitment that is not released or committed at 8:00 a.m., but is committed
before the gas-cyclic start deadline, is a heat rate equal to 12.100 MMBtu
per MWh times (the sum of the daily gas price plus $.25.)
(iii)
Ancillary services payment.
(I)
The ancillary services payment to be paid by the entitlement
holder to the affiliated PGC is the product of the ancillary services cost
defined in subclause (II) of this clause times the difference, for each settlement
interval of the entitlement, between the daily capacity commitment and energy
scheduled.
(II)
The ancillary services cost is a heat rate adjustment
equal to 1.622 MMBtu per MW times the daily gas price.
(iv)
Energy deployed up reimbursement payment. For energy deployed
up, for all settlement intervals in the entitlement month, the affiliated
PGC shall pay the entitlement holder the MCPE in dollars per MWh paid by ERCOT
for a settlement interval times the energy deployed up in a settlement interval.
(v)
Energy deployed down reimbursement payment. For energy
deployed down for all settlement intervals in the entitlement month, the entitlement
holder shall pay the affiliated PGC the MCPE in dollars per MWh paid to ERCOT
for a settlement interval times the energy deployed down in a settlement interval.
(D)
Timing of payment of contract price. The entitlement holder
shall pay the affiliated PGC the capacity payment portion of the contract
price not less than five days before the beginning of the entitlement month
or 20 days after receiving an invoice for the capacity payment from the affiliated
PGC, whichever is later. The entitlement holder shall pay the remainder of
the contract price after receiving an invoice for that amount in accordance
with the other terms of the Agreement. If the affiliated PGC owes the entitlement
holder any net amount under the contract price calculation, it will pay that
amount to the entitlement holder in accordance with the other terms of the
Agreement.
(6)
Gas-peaking.
(A)
Gas-peaking scheduling.
(i)
Schedule types. The entitlement holder shall submit a day-ahead
schedule for the entitlement and may submit hour-ahead schedules. The entitlement
holder shall submit a two-day-ahead schedule for the entitlement if notified
to do so by ERCOT.
(ii)
Timing of scheduling. All of the times for scheduling
referred to in this subparagraph are based on the times in the ERCOT protocols.
If the times in the ERCOT protocols are changed, then the times in this subparagraph
will be considered to have changed to equitably accommodate the changes in
the ERCOT protocols.
(I)
The entitlement holder shall submit day-ahead or two-day-ahead
schedules for the entitlement to the affiliated PGC no later than 8:00 a.m.
The daily capacity commitment is determined for a gas-peaking entitlement
by the 8:00 a.m. schedule, unless the entitlement holder notifies the affiliated
PGC, in the schedule, that it is exercising its option to set the daily capacity
commitment in the last schedule submitted before the gas-peaking start deadline
defined in subclause (V) of this clause. The entitlement holder shall submit
hour-ahead schedules for the entitlement to the affiliated PGC no later than
one hour before the deadline for the affiliated PGC's QSE to submit hour-ahead
schedules to ERCOT.
(II)
The entitlement holder may submit to the affiliated PGC
a revised day-ahead or two-day-ahead schedule for energy from the entitlement
no later than 10:00 a.m.
(III)
On days that ERCOT allows QSEs to change their day-ahead
or two-day ahead schedules to ERCOT by 1:00 p.m. for congestion or capacity
insufficiency, the entitlement holder may submit a revised day-ahead or two-day-ahead
schedule for energy from the entitlement to the affiliated PGC no later than
noon.
(IV)
The entitlement holder may submit to the affiliated PGC
a revised day-ahead or two-day-ahead schedule for the non-spinning reserve
service from the entitlement no later than 1:45 p.m.
(V)
The gas-peaking start deadline for declaring the daily
capacity commitment for each settlement interval in an operating hour is one
hour before the end of the adjustment period for that operating hour.
(iii)
Schedule content. Each schedule shall specify:
(I)
For each settlement interval, the MW of energy scheduled
to be delivered to the entitlement holder from the entitlement; and
(II)
For each hour, the MW scheduled to be reserved for the
entitlement holder's use of the non-spinning reserve service from the entitlement.
(iv)
Scheduling limits.
(I)
Total.
(-a-)
The rate at which energy is scheduled or ancillary services
reserved or scheduled by the entitlement holder in each settlement interval
during an hour shall be either zero MW or 25 MW and cannot change during the
hour.
(-b-)
Subject to the requirement of item (-a-) of this subclause,
if the entitlement holder schedules any energy from the entitlement in an
hour, the rate at which energy is scheduled shall continue uninterrupted at
a level of 25 MW for not less than four hours.
(-c-)
Subject to the requirements of items (-a-) and (-b-)
of this subclause, when the entitlement holder decreases a schedule for energy
to zero MW from the entitlement in an hour, the rate at which energy is scheduled
or at which ancillary services is scheduled or reserved shall continue uninterrupted
at a level of zero MW for not less than two hours.
(II)
Starts. The number of starts of the entitlement is not
limited.
(v)
Default schedule. If the entitlement holder does not submit
a timely day-ahead or two-day ahead schedule, as applicable, then the schedule,
for the applicable operating day is deemed to be, in every settlement interval
of the applicable operating day, zero MW for the daily capacity commitment,
zero MW of energy, and zero MW of the non-spinning reserve service. This deemed
schedule may not be changed in any revised day-ahead or two-day ahead schedule,
or in any hour-ahead schedule.
(B)
Gas-peaking ancillary services. The entitlement holder
may not use the entitlement for any ancillary service except the non-spinning
reserve service.
(C)
Contract price for gas-peaking. The items to be included
in the contract price between the entitlement holder and the affiliated PGC
for the entitlement shall include:
(i)
Capacity payment. The capacity payment from the entitlement
holder to the affiliated PGC is the capacity price in dollars per MW specified
in the letter confirmation for the entitlement times 25 MW.
(ii)
Energy payment.
(I)
The energy payment for each settlement interval, from the
entitlement holder to the affiliated PGC is the fuel price defined in subclause
(II) of this clause times (energy scheduled plus non-spinning energy deployed
plus non-spinning energy instructed deviation.)
(II)
Fuel price.
(-a-)
The fuel price, for operating days for which the entitlement
holder designated its daily capacity commitment by 8:00 a.m. in the day-ahead
or two-day ahead schedule, is a heat rate equal to 14.100 MMBtu per MWh times
the daily gas price.
(-b-)
The fuel price, for operating days for which the entitlement
holder exercises its option to designate its daily capacity commitment after
8:00 a.m. and before the gas-peaking start deadline, is a heat rate equal
to 14.100 MMBtu per MWh times the sum of the daily gas price plus $.25.
(iii)
Ancillary services payment. The ancillary services payment
to be paid by the entitlement holder to the affiliated PGC is the product
of $1.00 per MW times the total number of MW of non-spinning reserve service
scheduled during each hour of the entitlement month.
(iv)
Ancillary services reimbursement payment. The ancillary
services reimbursement payment from the affiliated PGC to the entitlement
holder is the sum of the MCPE for energy in dollars per MWh paid by ERCOT
for each MWh of non-spinning energy deployed and the price that ERCOT pays
for uninstructed deviations for each MWh of non-spinning energy uninstructed
deviation.
(D)
Timing of payment of contract price. The entitlement holder
shall pay the affiliated PGC the capacity payment portion of the contract
price not less than five days before the beginning of the entitlement month
or 20 days after receiving an invoice for the capacity payment from the affiliated
PGC, whichever is later. The entitlement holder shall pay the remainder of
the contract price after receiving an invoice for that amount in accordance
with the other terms of the Agreement. If the affiliated PGC owes the entitlement
holder any net amount under the contract price calculation, it will pay that
amount to the entitlement holder in accordance with the other terms of the
Agreement.
(g)
Product descriptions for capacity in non-ERCOT areas. The
provisions in this subsection apply to capacity auctions in non-ERCOT areas.
Subsection (f) of this section contains provisions applicable to capacity
auctions in ERCOT.
(1)
Definitions. The following words and terms when used in
this subsection shall have the following meanings unless the context indicates
otherwise:
(A)
Daily capacity commitment - The amount of capacity scheduled
by the entitlement holder that a seller shall make available for the provision
of energy from an entitlement.
(B)
Day ahead schedule - A schedule submitted by the entitlement
holder to a seller of the entitlement holder's scheduled usage of the entitlement
for the following operating day.
(C)
Energy scheduled - For each settlement interval, the final
schedule for energy that the entitlement holder submits to a seller, subject
to the limits on timing and amounts of schedules contained in this subsection.
(D)
Grouped entitlements - All of the entitlements from a seller
that the entitlement holder holds for a particular entitlement month.
(E)
Hour-ahead schedule - A schedule other than a day-ahead
schedule submitted by the entitlement holder to a seller of the entitlement
holder's scheduled usage of the entitlement for the following operating hour.
(2)
Baseload product.
(A)
Description. For each baseload capacity entitlement, the
scheduled power shall be provided to the entitlement holder during the month
of the entitlement seven days per week and 24 hours per day, in accordance
with the scheduling requirements and limitations provided in subparagraph
(E) of this paragraph.
(B)
Block size. Each baseload capacity entitlement shall be
25 MW in size.
(C)
Fuel price. The fuel cost owed to the affiliated PGC by
the entitlement holder for the dispatched baseload power will be the average
cost of coal, lignite, and nuclear fuel, in dollars per MWh, based on the
company's final ECOM model as determined in the proceeding pursuant to PURA §39.201
as projected for the relevant time period. Electric utilities without an ECOM
determination in their proceeding conducted pursuant to PURA §39.201
shall propose for commission review an average cost of fuel in a similar manner.
(D)
Starts per month. The entitlement holder of a baseload
capacity entitlement shall take power from the entitlement seven days per
week and 24 hours per day and is therefore not permitted to direct the affiliated
PGC to make any starts of baseload capacity entitlements.
(E)
Baseload scheduling.
(i)
Schedule types. The entitlement holder shall submit a day-ahead
schedule for the entitlement.
(ii)
Timing of scheduling.
(I)
The entitlement holder shall submit day-ahead schedules
for the entitlement to the seller no later than 8:00 a.m. The daily capacity
commitment is determined for a baseload entitlement by the 8:00 a.m. schedule.
(II)
The entitlement holder may submit to the seller a revised
day-ahead schedule for energy from the entitlement no later than noon, subject
to the limit on maximum energy in clause (iv)(II) of this subparagraph.
(III)
No hour-ahead schedules are permitted for energy from
baseload entitlements.
(iii)
Schedule content. Each schedule shall specify, for each
scheduling interval, subject to the scheduling limits in clause (iv) of this
subparagraph, the energy scheduled to be delivered to the entitlement holder
from the entitlement.
(iv)
Scheduling limits.
(I)
Minimum energy. The entitlement holder may not schedule
energy at less than 20 MW from the entitlement at any time during the month.
(II)
Maximum energy. The entitlement holder may not schedule
energy at any level greater than the daily capacity commitment in any scheduling
interval.
(III)
Maximum changes. Subject to the minimum energy rate specified
in subclause (I) of this clause:
(-a-)
Total. Generally, the rate at which energy is scheduled
by the entitlement holder in each hour cannot change more than plus or minus
two MW.
(-b-)
Energy. Subject to the maximum change specified in item
(-a-) of this subclause, the maximum change in energy scheduled from one scheduling
interval to the next scheduling interval cannot exceed plus or minus two MW.
(v)
Default schedule. If the entitlement holder does not submit
a timely day-ahead schedule, as applicable, then the schedule for the applicable
operating day shall be deemed to be, in every settlement interval of the applicable
operating day, a total of 20 MW for the daily capacity commitment.
(F)
Contract price for baseload. The items to be included in
the contract price between the entitlement holder and the affiliated PGC for
the entitlement shall include:
(i)
Capacity payment. The capacity payment from the entitlement
holder to the affiliated PGC is the capacity price in dollars per MW specified
in the letter confirmation for the entitlement times 25 MW.
(ii)
Energy payment. The fuel price is as specified on the
letter confirmation for the entitlement. The energy payment from the entitlement
holder to the affiliated PGC is the fuel price in dollars per MWh specified
in the letter confirmation for the entitlement times the greater of:
(I)
The total energy scheduled from the entitlement during
the entitlement month; or
(II)
An amount of MWh equal to 20 MW times the number of hours
in the entitlement month.
(G)
Timing of payment of contract price. The entitlement holder
shall pay the affiliated PGC the capacity payment portion of the contract
price not less than five days before the beginning of the entitlement month
or 20 days after receiving an invoice for the capacity payment from the affiliated
PGC, whichever is later. The entitlement holder shall pay the remainder of
the contract price to the affiliated PGC after receiving an invoice for that
amount in accordance with the other terms of the Agreement. If the affiliated
PGC owes the entitlement holder any net amount under the contract price calculation,
it will pay that amount to the entitlement holder in accordance with the other
terms of the Agreement.
(3)
Gas-intermediate product.
(A)
Description. For each gas-intermediate capacity entitlement,
not less than 30% of the entitlement shall be provided to the entitlement
holder at any time when any of the entitlement is being scheduled by the entitlement
holder , with the remainder of the block scheduled as day-ahead shaped power
in accordance with the scheduling requirements and limitations provided in
subparagraph (E) of this paragraph.
(B)
Block size. Each gas-intermediate capacity entitlement
shall be 25 MW in size.
(C)
Fuel price.
(i)
Except as specified otherwise in clause (ii) of this subparagraph,
the fuel cost owed to the affiliated PGC by the entitlement holder for the
gas-intermediate capacity dispatched will be 10.850 MMBtu per MWh heat rate
times the minimum MWh that shall be taken for gas-intermediate capacity as
required in subparagraph (A) of this paragraph times the first-of-the-month
index posted in the publication "Inside FERC" for the Houston Ship Channel
for the month of the entitlement. For power dispatched above the minimum MWh
required, the additional fuel price owed to the affiliated PGC will be 10.850
MMBtu per MWh times the MWh of gas-intermediate power dispatched pursuant
to the entitlement above the minimum requirement times the daily gas price.
(ii)
EGSI.
(I)
For EGSI gas-intermediate capacity in the eastern congestion
zone, the fuel cost owed to its affiliated PGC by the capacity entitlement
holder for the gas-intermediate capacity dispatched will be 10.850 MMBtu per
MWh heat rate times the minimum MWh that shall be taken for gas-intermediate
capacity as required in subparagraph (A) of this paragraph times the first-of-the-month
index posted in the publication "Inside FERC" for Henry Hub for the month
of the entitlement. For power dispatched above the minimum MWh required, the
additional fuel price owed to the affiliated PGC will be 10.850 MMBtu per
MWh times the MWh of gas-intermediate power dispatched pursuant to the entitlement
above the minimum requirement times the Henry Hub daily gas price.
(II)
For EGSI gas-intermediate capacity in the western congestion
zone, the fuel cost owed to its affiliated PGC by the capacity entitlement
holder for the gas-intermediate capacity dispatched will be 10.850 MMBtu per
MWh heat rate times the minimum MWh that shall be taken for gas-intermediate
capacity as required in subparagraph (A) of this paragraph times the average
of the first-of-the-month index posted in the publication "Inside FERC" for
Henry Hub for the month of the entitlement and the first-of-the-month index
posted in the publication "Inside FERC" for the Houston Ship Channel for the
month of the entitlement. For power dispatched above the minimum MWh required,
the additional fuel price owed to the affiliated PGC will be 10.850 MMBtu
per MWh times the MWh of gas-intermediate power dispatched pursuant to the
entitlement above the minimum requirement times the average of the Henry Hub
daily gas price and the Houston Ship Channel daily gas price.
(D)
Starts per month. The entitlement holder of gas-intermediate
capacity shall take a minimum of 30% of the power from the entitlement in
each interval and is therefore not permitted to direct the affiliated PGC
to make any starts of gas intermediate capacity entitlements.
(E)
Gas-intermediate scheduling.
(i)
Schedule types. The entitlement holder shall submit a day-ahead
schedule for the entitlement.
(ii)
Timing of scheduling.
(I)
The entitlement holder shall submit day-ahead schedules
for the entitlement to the seller no later than 8:00 a.m. The daily capacity
commitment is determined for a gas-intermediate entitlement by the 8:00 a.m.
schedule.
(II)
The entitlement holder may submit to seller a revised
day-ahead schedule for energy from the entitlement no later than noon, subject
to the limit on maximum energy in clause (iv)(II) of this subparagraph.
(III)
No hour-ahead schedules are permitted for energy from
gas-intermediate entitlements.
(iii)
Schedule content. Each schedule shall specify, for each
scheduling interval, the energy scheduled to be delivered to the entitlement
holder from the entitlement.
(iv)
Scheduling limits.
(I)
Minimum energy. The entitlement holder may not schedule
energy at less than eight MW from the entitlement at any time during the month.
(II)
Maximum energy. The entitlement holder may not schedule
energy at a level greater than the daily capacity commitment in any scheduling
interval.
(III)
Maximum changes. Subject to the minimum energy rate specified
in subclause (I) of this clause and the maximum energy rate specified in subclause
(II) of this clause, the energy scheduled by the entitlement holder in each
hour cannot change more than plus or minus six MW.
(v)
Default schedule. If the entitlement holder does not submit
a timely day-ahead schedule, as applicable, then the schedule for the applicable
operating day shall be deemed to be, in every settlement interval of the applicable
operating day, a total of eight MW for the daily capacity commitment. This
deemed schedule may not be changed in any hour-ahead schedule.
(F)
Contract price for gas-intermediate. The items to be included
in the contract price between the entitlement holder and the affiliated PGC
for the entitlement shall include:
(i)
Capacity payment. The capacity payment from the entitlement
holder to the affiliated PGC is the capacity price in dollars per MW specified
in the letter confirmation for the entitlement times 25 MW.
(ii)
Energy payment.
(I)
The energy payment from the entitlement holder to the affiliated
PGC is the sum, for each settlement interval in the entitlement month, of
the minimum energy payment and the excess energy payment.
(-a-)
The minimum energy payment is the product of eight MWh
times the minimum fuel price.
(-b-)
The excess energy payment is the product, for each settlement
interval, of the excess fuel price defined in subclause (II)(-b-) of this
clause times energy scheduled.
(II)
Fuel price.
(-a-)
The minimum fuel price is the product of a heat rate
equal to 10.850 MMBtu per MWh times the daily gas price.
(-b-)
The excess fuel price is the product of a heat rate equal
to 10.850 MMBtu per MWh times the daily gas price.
(G)
Timing of payment of contract price. The entitlement holder
shall pay the affiliated PGC the capacity payment portion of the contract
price not less than five days before the beginning of the entitlement month
or 20 days after receiving an invoice for the capacity payment from the affiliated
PGC, whichever is later. The entitlement holder shall pay the remainder of
the contract price after receiving an invoice for that amount in accordance
with the terms of the Agreement. If the affiliated PGC owes the entitlement
holder any net amount under the contract price calculation, it will pay that
amount to the entitlement holder in accordance with the terms of the Agreement.
(4)
Gas-cyclic product.
(A)
Description. The gas-cyclic entitlement shall be flexible
day-ahead shaped power.
(B)
Block size. Each gas-cyclic capacity entitlement shall
be 25 MW in size.
(C)
Fuel price.
(i)
Except as specified otherwise in clause (ii) of this subparagraph,
the fuel price owed to the affiliated PGC by the capacity entitlement holder
for gas-cyclic capacity dispatched will be 12.100 MMBtu per MWh times the
MWh of the gas-cyclic power dispatched under the entitlement times the daily
gas price.
(ii)
EGSI.
(I)
For EGSI gas-cyclic capacity in the eastern congestion
zone, the fuel cost owed to its affiliated PGC by the capacity entitlement
holder for the gas-cyclic capacity dispatched will be 12.100 MMBtu per MWh
times the MWh of gas-cyclic power dispatched under the entitlement times the
Henry Hub daily gas price.
(II)
For EGSI gas-cyclic capacity in the western congestion
zone, the fuel cost owed to its affiliated PGC by the capacity entitlement
holder for the gas-cyclic capacity dispatched will be 12.100 MMBtu per MWh
times the MWh of gas-cyclic power dispatched under the entitlement times the
average of the Henry Hub daily gas price and the Houston Ship Channel daily
gas price.
(D)
Starts per month and associated costs. The entitlement
holder of gas-cyclic capacity shall be entitled to direct the selling affiliated
PGC to make up to the amount of starts per month of each entitlement of gas-cyclic
capacity allowed pursuant to subparagraph (E)(v) of this paragraph.
(E)
Gas-cyclic scheduling.
(i)
Schedule types. The entitlement holder shall submit a day-ahead
schedule for the entitlement.
(ii)
Timing of scheduling.
(I)
The entitlement holder shall submit day-ahead schedules
for the entitlement to seller no later than 8:00 a.m. The daily capacity commitment
is determined for a gas-cyclic entitlement by the 8:00 a.m. schedule, unless
the entitlement holder notifies seller, in the schedule, that it is exercising
its option to set the daily capacity commitment in the last schedule submitted
before the gas-cyclic start deadline pursuant to subclause (IV) of this clause.
(II)
The entitlement holder may submit to seller a revised
day-ahead schedule for energy from the entitlement no later than noon, subject
to the limit on maximum energy in clause (iv)(II) of this subparagraph.
(III)
No hour-ahead schedules are permitted for energy from
gas-cyclic entitlements.
(IV)
The gas-cyclic start deadline for declaring the daily
capacity commitment for each settlement interval in an operating hour is 15
hours before the start of the operating hour.
(iii)
Schedule content. Each schedule shall specify, for each
scheduling interval, the energy scheduled to be delivered to the entitlement
holder from the entitlement.
(iv)
Scheduling limits.
(I)
Minimum energy. The entitlement holder may not schedule
energy at any level between zero MW and five MW from the entitlement at any
time during the month.
(II)
Maximum energy. The entitlement holder may not schedule
energy at any level greater than the daily capacity commitment in any scheduling
interval.
(III)
Maximum changes. Subject to the minimum energy rate specified
in subclause (I) of this clause and the maximum energy rate specified in subclause
(II) of this clause, the energy scheduled by the entitlement holder in each
hour cannot change more than plus or minus six MW.
(v)
Starts. The entitlement holder shall not direct more than
20 starts during the month of the entitlement, and the entitlement holder
shall not direct more than one start per day. A start occurs every time a
schedule increases the MW of energy from zero MW. Once the maximum number
of starts have occurred during the entitlement, the energy scheduled by the
entitlement holder may not be lower than a rate of five MW unless that level
is lowered to zero MW, at which time the level may not be raised above zero
MW for the remainder of the month.
(vi)
Default schedule. If the entitlement holder does not submit
a timely day-ahead schedule as applicable, then the schedule for the applicable
operating day is deemed to be, in every settlement interval of the applicable
operating day, zero MW for the daily capacity commitment and zero MW of energy.
This deemed schedule may not be changed.
(F)
Contract price for gas-cyclic. The items to be included
in the contract price between the entitlement holder and the affiliated PGC
for the entitlement shall include:
(i)
Capacity payment. The capacity payment from the entitlement
holder to the affiliated PGC is the capacity price in dollars per MW specified
in the letter confirmation for the entitlement times 25 MW.
(ii)
Energy payment.
(I)
The energy payment for each settlement interval from the
entitlement holder to the affiliated PGC is the product, of the fuel price
defined in subclause (II) of this clause times energy scheduled.
(II)
Fuel price.
(-a-)
The fuel price, for the portion of the daily capacity
commitment that is designated by the entitlement holder by 8:00 a.m. in the
day-ahead schedule, is the product of a heat rate equal to 12.100 MMBtu per
MWh times the daily gas price.
(-b-)
The fuel price for the portion of the daily capacity
commitment that is not released or committed at 8:00 a.m., but committed before
the gas-cyclic start deadline, is the product of a heat rate equal to 12.100
MMBtu per MWh times (the sum of the daily gas price plus $0.25.)
(G)
Timing of payment of contract price. The entitlement holder
shall pay the affiliated PGC the capacity payment portion of the contract
price not less than five days before the beginning of the entitlement month
or 20 days after receiving an invoice for the capacity payment from the affiliated
PGC, whichever is later. The entitlement holder shall pay the remainder of
the contract price after receiving an invoice for that amount in accordance
with the terms of the Agreement. If the affiliated PGC owes the entitlement
holder any net amount under the contract price calculation, it will pay that
amount to the entitlement holder in accordance with the terms of the Agreement.
(5)
Gas-peaking product.
(A)
Description. The gas-peaking entitlement shall be intra-day
power.
(B)
Block size. Each gas-peaking capacity entitlement shall
be 25 MW in size.
(C)
Fuel price.
(i)
Except as specified in clause (ii) of this subparagraph,
the fuel price owed to the affiliated PGC by the entitlement holder for gas-peaking
capacity dispatched will be 14.100 MMBtu per MWh times the MWh of the gas-peaking
power dispatched under the entitlement times the daily gas price.
(ii)
EGSI.
(I)
For EGSI gas-peaking capacity in the eastern congestion
zone, the fuel cost owed to its affiliated PGC by the capacity entitlement
holder for the gas-peaking capacity dispatched will be 14.100 MMBtu per MWh
times the MWh of gas-peaking power dispatched under the entitlement times
the Henry Hub daily gas price.
(II)
For EGSI gas-peaking capacity in the western congestion
zone, the fuel cost owed to its affiliated PGC by the capacity entitlement
holder for the gas-peaking capacity dispatched will be 14.100 MMBtu per MWh
times the MWh of gas-peaking power dispatched under the entitlement times
the average of the Henry Hub daily gas price and the Houston Ship Channel
daily gas price.
(D)
Starts per month and associated costs. The entitlement
holder of gas-peaking capacity shall be entitled to direct the selling affiliated
PGC to make unlimited starts per month of each entitlement of gas-peaking
capacity.
(E)
Gas-peaking scheduling.
(i)
Schedule types. The entitlement holder shall submit a day-ahead
schedule for the entitlement and may submit hour-ahead schedules.
(ii)
Timing of scheduling.
(I)
The entitlement holder shall submit day-ahead schedules
for the entitlement to the seller no later than 8:00 a.m. The daily capacity
commitment is determined for a gas-peaking entitlement by the 8:00 a.m. schedule,
unless the entitlement holder notifies the seller, in the schedule, that it
is exercising its option to set the daily capacity commitment in the last
schedule submitted before the gas-peaking start deadline defined in subclause
(III) of this clause. The entitlement holder shall submit hour-ahead schedules
for the entitlement to the seller no later than one hour before the start
of the operating hour.
(II)
The entitlement holder may submit to the seller a revised
day-ahead schedule for energy from the entitlement no later than noon.
(III)
The gas-peaking start deadline for declaring the daily
capacity commitment for each operating hour is two hours before the beginning
of the operating hour.
(iii)
Schedule content. Each schedule shall specify, for each
scheduling interval, the energy scheduled to be delivered to the entitlement
holder from the entitlement.
(iv)
Scheduling limits.
(I)
The rate at which energy is scheduled by the entitlement
holder in each scheduling interval during one hour shall be either zero MW
or 25 MW and cannot change during the hour.
(II)
Subject to the requirement of subclause (I) of this clause,
if the entitlement holder schedules any energy from the entitlement in one
hour, the rate at which energy is scheduled shall continue uninterrupted at
a level of 25 MW for not less than four hours.
(III)
Subject to the requirements of subclause (I) and (II)
of this clause, when the entitlement holder decreases a schedule for energy
to zero MW from the entitlement in one hour, the energy scheduled shall continue
uninterrupted at a level of zero MW for not less than two hours.
(v)
Default Schedule. If the entitlement holder does not submit
a timely day-ahead schedule then the schedule for the applicable operating
day shall be deemed to be, in every settlement interval of the applicable
operating day, zero MW for the daily capacity commitment and zero MW of energy.
This deemed schedule may not be changed in any revised day-ahead schedule,
or in any hour-ahead schedule.
(F)
Contract price for gas-peaking. The items to be included
in the contract price between the entitlement holder and the affiliated PGC
for the entitlement shall include:
(i)
Capacity payment. The capacity payment from the entitlement
holder to the affiliated PGC is the capacity price in dollars per MW specified
in the letter confirmation for the entitlement times 25 MW.
(ii)
Energy payment.
(I)
The energy payment for each settlement interval from the
entitlement holder to the affiliated PGC is the product of the fuel price
defined in subclause (II) of this clause times energy scheduled.
(II)
Fuel price.
(-a-)
The fuel price, for operating days for which the entitlement
holder designated its daily capacity commitment by 8:00 a.m. in the day-ahead
schedule, is the product of a heat rate equal to 14.100 MMBtu per MWh times
the daily gas price.
(-b-)
The fuel price, for operating days for which the entitlement
holder exercised its option to designate its daily capacity commitment after
8:00 a.m. and before the gas-peaking start deadline, is the product of a heat
rate equal to 14.100 MMBtu per MWh times (the sum of the daily gas price plus
$.25).
(G)
Timing of payment of contract price. The entitlement holder
shall pay the affiliated PGC the capacity payment portion of the contract
price not less than five days before the beginning of the entitlement month
or 20 days after receiving an invoice for the capacity payment from the affiliated
PGC, whichever is later. The entitlement holder shall pay the remainder of
the contract price after receiving an invoice for that amount in accordance
with the terms of the Agreement. If the affiliated PGC owes the entitlement
holder any net amount under the contract price calculation, it will pay that
amount to the entitlement holder in accordance with the terms of the Agreement.
(6)
Scheduling discrepancies. If the entitlement holder submits
a schedule to seller for an entitlement that violates any of the scheduling
requirements for that capacity auction product type, the schedule shall be
deemed a non-conforming schedule for a scheduled hour. The schedule for that
non-conforming scheduled hour shall then be deemed to be the same as the schedule
for the nearest preceding hour for which the schedule was not a non-conforming
schedule. The seller shall promptly notify the entitlement holder of a non-conforming
schedule.
(7)
Ancillary services. Until such time that all ancillary
services issues are addressed and resolved within the context of a Federal
Energy Regulatory Commission (FERC) approved regional transmission organization,
entitlements will include rights only to energy and capacity as described
in this subsection and specifically exclude any ancillary services rights.
Such exclusion is consistent with subsection (e)(1) of this section, which
allows products other than those described in this subsection to be offered
with good cause. In the interim, the affiliated PGC shall provide the required
ancillary services to eligible customers at the current FERC-approved rates.
(h)
Auction process.
(1)
Timing issues.
(A)
Frequency of auctions.
(i)
Auction dates. Capacity auctions shall begin on March 10,
July 10, September 10, and November 10 of each year. If the date for an auction
start falls on a weekend or banking holiday, then that auction shall begin
on the first business day after the weekend or banking holiday.
(ii)
Simultaneous auctions. Auctions for a product will be
held simultaneously by all affiliated PGCs of entitlements within the respective
North American Electric Reliability Council (NERC) regions in Texas. For example,
ERCOT and non-ERCOT auctions can be held at different times and dates.
(iii)
Termination of the capacity auction process. The obligation
of an affiliated PGC to auction entitlements shall continue until the earlier
of 60 months after the date customer choice is introduced or the date the
commission determines that 40% or more of the electric power consumed by residential
and small commercial customers within the affiliated transmission and distribution
utility's certificated service area before the onset of customer choice is
provided by nonaffiliated retail electric providers. The determination of
the 40% threshold shall be as prescribed by the commission's rule relating
to the price to beat.
(B)
Auction conclusion.
(i)
Receipt of bids. In order for an affiliated PGC that is
auctioning capacity to consider a bid, the bid must be received by that affiliated
PGC by close of the round for which the bid is to be submitted.
(ii)
Concluding each individual auction. The affiliated PGC
shall provide notice of the winning bid(s) to auction participants and the
commission by the close of business on the first day after the auction closes
that is not a weekend or banking holiday.
(iii)
Confidentiality and posting of bids. The affiliated PGC
shall designate non-marketing personnel to evaluate the bids, and persons
reviewing the bids shall not disclose the bids to any person engaged in marketing
activities for the affiliated PGC or use any competitively sensitive information
received in the bidding process. Upon announcement of the winning bids, the
affiliated PGC shall provide the commission and all auction participants information
on the quantity of each product requested by bidders during each round of
an auction, but shall not divulge the identity of any particular bidders.
Upon specific request by the commission, and under standard protective order
procedures, the utility shall provide the identity of the bidders to the commission.
(iv)
The affiliated PGC shall be deemed to have met the 15%
requirement if it offered products in a product category (for example, gas-intermediate)
and successfully sold, at least, all of the entitlements offered in one particular
month, in that product category. If there is no month in which all of the
products in a product category are sold, the affiliated PGC shall comply with
the provisions of paragraph (7)(C) of this subsection.
(2)
Auction administration.
(A)
Each auction shall be administered by the affiliated PGC
selling the entitlement. An affiliated PGC or group of affiliated PGCs may
retain the services of a qualified third-party to perform the auction administration
functions.
(B)
Notice of capacity available for auction.
(i)
Method of notice. At least 60 days before each auction
start date, each affiliated PGC offering capacity entitlements at auction
shall file with the commission notice of the pending auction. Within 20 days
of the filing of the notice, interested parties may provide comments on the
affiliated PGC's proposed notice. If no comments are received, the affiliated
PGC's proposed notice shall be deemed appropriate. If any party objects to
the affiliated PGC's proposed notice, then the commission shall administratively
approve, reject, or approve the notice with modifications.
(ii)
Contents of notice.
(I)
The auction notice shall include the auction start date,
the date and time by which bids must be received for the first round, and
the types, quantity (number of blocks), congestion zone, and term of each
entitlement available in that auction. The notice shall also include the following
range of bid increments for each product type to be used to adjust the price
of entitlements between rounds of the auction:
(-a-)
Baseload - $.05 to $.75;
(-b-)
Gas-intermediate - $.02 to $.30;
(-c-)
Gas-cyclic - $.02 to $.30;
(-d-)
Gas-peaking - $.02 to $.30.
(II)
The affiliated PGC shall also specify which power generation
units will be used to meet the entitlement for each type of entitlement to
be auctioned. If baseload entitlements are being auctioned, the utility shall
also specify the fuel cost prescribed in subsections (f)(3)(B)(ii) and (g)(2)(F)(ii)
of this section at the time of the auction. If an entitlement to be auctioned
is subject to the forced outage provision in subsection (e)(2)(B) of this
section, then the notice must include the applicable three-year rolling average
of the forced outage rate.
(iii)
The affiliated PGCs shall publish their respective notices
and application forms on their web sites no later than 45 calendar days before
the start of each auction. Each entity that intends to bid in an affiliated
PGC's auction shall complete the forms, which include the first page of the
cover sheet to the Agreement, and submit them to the affiliated PGC at least
20 business days before the auction starts, to allow enough time for evaluation
and approval of credit. Potential bidders may submit the required documents
after that time, but at the risk of not having credit and document approval
in time for them to participate in the auction.
(iv)
Credit approval for entities bidding on capacity auction
products in ERCOT or in non-ERCOT areas of Texas will be performed pursuant
to subsection (e)(7) of this section.
(v)
The affiliated PGC shall notify an approved bidder of its
available credit and send the approved bidder a completed capacity auction-specific
version of the applicable Agreement, executed by the affiliated PGC, within
ten business days after the bidder has submitted the required information.
The approved bidder should attempt to execute and return the executed Agreement
to the affiliated PGC no later than five business days before the auction
starts. The executed Agreement shall be received by the affiliated PGC no
later than two business days before the auction starts. The affiliated PGC
shall provide a password or passwords to the approved bidder to allow access
to the auction web site and to allow it to bid no later than one business
day before the auction starts. An approved bidder may not request or receive
additional credit after the auction starts.
(vi)
Specific information on how to place bids and navigate
the auction sites will be provided by the affiliated PGCs to their qualified
bidders prior to the beginning of the capacity auction.
(3)
Term of auctioned capacity.
(A)
Initial auction. For the initial auction in September 2001,
each entitlement was one month in duration, with:
(i)
Approximately 20% of the entitlements auctioned as two
one-year strips with the strips auctioned jointly (the 12 months of 2002 and
2003),
(ii)
Approximately 30% of the entitlements as one-year strips
(the 12 months of 2002), and
(iii)
Approximately 20% of the entitlements as discrete months
for each of the 12 months of 2002 (January through December of 2002)
(iv)
Approximately 30% of the entitlements as discrete months
for the first four months of 2002 (January through April of 2002).
(v)
Reductions in the amounts of entitlements available during
the months of March, April, May, October, and November of each calendar year
shall be accounted for in the entitlements offered as discrete months.
(B)
Schedule of subsequent auctions.
(i)
The auction in March of a year will auction approximately
30% of the entitlements as the discrete months of May through August of that
year.
(ii)
The auction in July of a year will auction approximately
30% of the entitlements as the discrete months of September through December
of that year.
(iii)
The auction in September of a year will auction:
(I)
Approximately 30% of the entitlements as the one-year strips
for the next year; and
(II)
Approximately 20% of the entitlements as discrete months
for each of the 12 calendar months of the next year.
(iv)
The auction in November of a year will auction approximately
30% of the entitlements as the discrete months of January through April of
the next year.
(v)
Reductions in the amounts of entitlements available during
the months of March, April, May, October, and November of each calendar year
shall be accounted for in the entitlements offered as discrete months.
(vi)
In June of 2003, an evaluation will be made by the commission
as to the need for another set of two-year strips (the 24 months of 2004 through
2005). If such term is deemed to be necessary, the next set of two-year strips
will be auctioned in September of 2003. If such term is not deemed to be necessary,
then subsequent auctions will auction 50% of entitlements over one-year strips
and 50% of the entitlements as discrete months.
(C)
Modification of term. If the auction is for a one-year
or two-year strip term and the affiliated retail electric provider (REP) expects
to reach the 40% load loss threshold in paragraph (1)(A)(iii) of this subsection,
the affiliated PGC may request a shorter term strip by providing evidence
of the loss of customer load. Similarly, prior to an auction for the next
four available months, an affiliated PGC may request to not auction months
in which it projects reaching the 40% threshold. Such filings shall be made
90 days before the auction start date. An affiliated PGC that will satisfy
its auction requirements through divestiture, as described in subsection (d)
of this section may petition the commission to set an appropriate term for
entitlements. The affiliated PGC may not adjust the amount or length of an
entitlement to be auctioned except as authorized by the commission.
(4)
Quantity to be auctioned.
(A)
Block size and number of blocks. The block size of the
auctioned capacity entitlement is 25 MW. The affiliated PGC shall divide the
amount determined for each product referenced in subsection (e)(1) of this
section by 25 to determine the number of blocks of each type to be auctioned.
(B)
Divisibility. If the amount to be auctioned for an affiliated
PGC for a particular product is not evenly divisible by 25, any remainder
shall be added to the product most highly valued in the immediately preceding
auction for products of the same duration and shall increase by one the number
of entitlements of that product.
(C)
Total amount. The sum of the blocks of capacity auctioned
shall total no less than 15% of the affiliated PGC's Texas jurisdictional
installed generation capacity.
(5)
Bidders. For each auction, potential bidders shall pre-qualify
by demonstrating compliance with the credit requirements in subsection (e)(7)
of this section in advance of submission of a bid.
(6)
Bidding procedures. For purposes of this section, the term
"set of entitlements" shall refer to all of a seller's products of the same
type and period. For example, a quantity of baseload products sold as a one-year
strip for 2002 would be a set of baseload-annual 2002 entitlements, while
a quantity of baseload products sold as the discrete month of July 2002 would
be a set of baseload-July 2002 entitlements.
(A)
Method of auction for affiliated PGCs within ERCOT. Each
auction shall be a simultaneous, multiple round, auction that includes procedures
that allow switching by bidders between affiliated PGCs and product types.
(i)
Auction duration. Once a product auction commences it will
continue through each business day until that auction concludes.
(ii)
Round duration. Each auction's first round will begin
promptly at 8:00 a.m. and each round will last for 30 minutes with 30 minutes
between rounds. For example, the first round of bidding will start at 8:00
a.m. and end at 8:30 a.m., the second round will start at 9:00 a.m. and end
at 9:30 a.m., etc. No round may start later than 4:00 p.m. All times are in
central prevailing time.
(iii)
Credit calculation. An entitlement bidder's credit limit
shall be adjusted during the auction based on the value of the entitlements
bid upon, and will be determined by using an assumed fuel price stated by
the entitlement seller, and the capacity price for the lesser of three months
or the duration of the entitlement plus the amount that would be paid to exercise
the entitlement for the lesser of three months or the duration of the entitlement
at the assumed dispatch for each product as follows:
Figure: 16 TAC §25.381(h)(6)(A)(iii)
(B)
Mechanism for auction for affiliated PGCs within ERCOT.
Each affiliated PGC shall conduct the auction over the Internet on a secure
web page and shall assign a password and bidder's number to each entity that
has satisfied the credit requirements in this section.
(C)
Method of auction for affiliated PGCs in non-ERCOT areas.
Each auction shall be a simultaneous, multiple round, open bid auction.
(i)
First round. For the first round of the auction, the affiliated
PGC will post the opening bid price determined in accordance with paragraph
(7) of this subsection for each set of entitlements available for purchase
at the auction. Each bidder will specify the number of entitlements it wishes
to purchase of each set of entitlements at the opening bid price(s). If the
total demand for a set of entitlements is less than the available quantity
of the set of entitlements, the price for each of the entitlements in the
set will be the opening bid price and each bidder in the round will receive
all of the entitlements in the set they demanded. Any remaining entitlements
of the set will be held for future auction as noticed by the affiliated PGC
in accordance with its notice given pursuant to paragraph (7) of this subsection.
(ii)
Subsequent rounds. If the total demand for a set of entitlements
in any round is more than or equal to the available quantity, the affiliated
PGC will adjust the price upward within the range for each specific product
type as noticed according to paragraph (2)(B)(ii)(I) of this subsection. Bidders
shall then submit bids for the quantities they wish to purchase of each set
of entitlements at the new price. Subsequent rounds shall continue until demand
is less than supply for each set of entitlements. The auction then closes
and the market clearing price for each set of entitlements is set at the last
price for which demand equaled or exceeded supply. Bidders shall then be awarded
the entitlements they demanded in the final round, plus a pro-rata share of
any entitlements they demanded in the next to last round as described in clause
(iii) of this paragraph.
(iii)
Pro-rata entitlement allocation. The pro-rata allocation
of entitlements will be implemented by determining a bid differential between
the next-to-last round bid and the number of awarded entitlements based on
the last round and awarding the remaining entitlement to the bidder with the
largest differential. The awarded entitlement will then be subtracted from
that bidder's differential and the process will iterate until all entitlements
have been awarded. In the event that the differential between two or more
bidders is the same, the tie will be broken based on the timestamp of each
bidder's last bid submitted in the next-to-last round. For example, 14 baseload
one-year strip entitlements are available and bidders A, B, C, and D are bidding.
In the last round, demand was only 11 entitlements and bidder D did not bid.
Figure 1: 16 TAC §25.381(h)(6)(C)(iii)
Figure 2: 16 TAC §25.381(h)(6)(C)(iii)
Figure 3: 16 TAC §25.381(h)(6)(C)(iii)
Figure 4: 16 TAC §25.381(h)(6)(C)(iii)
(iv)
Auction duration. Once a product auction commences it
will continue through each business day until that auction concludes.
(v)
Round duration. Each auction's first round will begin promptly
at 8:00 a.m. and each round will last for 30 minutes with 30 minutes between
rounds. For example, the first round of bidding will start at 8:00 a.m. and
end at 8:30 a.m., the second round will start at 9:00 a.m. and end at 9:30
a.m., etc. No round may start later than 4:00 p.m. All times are in central
prevailing time.
(vi)
Credit calculation. An entitlement holder's credit limit
shall be adjusted during the auction based on the value of the entitlements
awarded to the holder, which will be determined by using an assumed fuel price
stated by the entitlement seller, and the capacity price for the lesser of
three months or the duration of the entitlement plus the amount that would
be paid to exercise the entitlement for the lesser of three months or the
duration of the entitlement at the assumed dispatch for each product as follows:
Figure: 16 TAC §25.381(h)(6)(C)(vi)
(D)
Activity rules for affiliated PGCs in non-ERCOT areas.
(i)
A bidder must bid in the first round for a particular entitlement
to participate in subsequent rounds.
(ii)
A bidder may not bid a greater quantity than it bid in
a previous round for a particular entitlement.
(E)
Mechanism for auction for affiliated PGCs in non-ERCOT
areas. Each affiliated PGC shall conduct the auction over the Internet on
a secure web page and shall assign a password and bidder's number to each
entity that has satisfied the credit requirements in this section.
(7)
Establishment of opening bid price.
(A)
If an affiliated PGC intends to change the minimum opening
bid prices that would otherwise be applicable under subparagraph (B) of this
paragraph, it shall file with the commission, not less than 90 days before
the auction start date on which the change is proposed to be applicable, a
methodology for determining an opening bid price for each type of entitlement,
if needed, based on the affiliated PGC's expected variable cost of operation,
but excluding any return on equity. The opening price may not include any
cost included in the fuel price to be paid by entitlement holders, nor any
cost being recovered by its affiliated transmission and distribution utility
through non-bypassable delivery charges, but may recover variable costs not
included in the fuel prices, such as fuel service costs and start up fees.
Parties shall have 30 days after filing to challenge the methodology. If no
challenges are received, the affiliated PGC's proposed methodology shall be
deemed appropriate. If any party objects to the affiliated PGC's proposed
methodology, then the commission shall determine the appropriate methodology.
(B)
Minimum opening bids for entitlements shall be the same
as the minimum opening bids used in the most recent auction that included
those entitlements, except that sellers with plants that have been affected
by congestion zone changes since the most recent auction may use minimum opening
bids that are different than the minimum opening bids in the most recent auction,
provided that the seller maintains the same weighted-average, by MW, of the
most recent auction's minimum bids, for all of its plants of the same product
type in all congestion zones, to compute the new minimum opening bids for
each product type. Nothing in this subparagraph shall prevent the commission
from ordering a different methodology for a seller, if the seller proves that
good cause exists for the change.
(C)
In the notice provided pursuant to paragraph (2)(B)(i)
of this subsection, the affiliated PGC may make available an opening bid price
calculated pursuant to the commission-approved methodology for each type of
entitlement to be offered for sale at auction. The affiliated PGC shall not
be obligated to accept any bid for a product less than the opening bid price,
but shall notify the commission that the opening bid price was not met. The
affiliated PGC shall be deemed to have met the 15% requirement if it offered
products in a product category (for example, gas-intermediate) and successfully
sold, at least, all of the entitlements offered in one particular month, in
that product category. If there is an auction where there is no month in which
all of the entitlements of a particular product are sold, then the affiliated
PGC shall, in its notice pursuant to paragraph (2)(B)(i) of this subsection,
make a proposal to the commission in order to comply with the 15% requirement.
The affiliated PGC's proposal may include revisions to the product category,
product price, or offer alternative products for auction.
(8)
Results of the auction. The results of the auction shall
be simultaneously announced to all bidders by posting on the affiliated PGC's
auction web site with posting of the market clearing price for each set of
entitlements.
(i)
Resale of entitlement.
(1)
Compliance with provisions. An entitlement may be assigned,
sold or transferred by the entitlement holder only by following the provisions
of this section. Any purported assignment, sale, or transfer of an entitlement
that does not follow the provisions of this section is void and ineffective
against the affiliated PGC.
(2)
Eligible entities. An entitlement holder may assign, sell,
or transfer an entitlement to any person or entity other than an affiliated
REP, but the entitlement holder may dispatch the output of the entitlement
to an affiliated REP.
(3)
Obligations. An entitlement that is assigned, sold, or
transferred under this section remains subject to the provisions of the Agreement
under which it originated, and the assignee of that entitlement succeeds to
all of the rights and obligations of the assignor with respect to that entitlement.
(4)
Liability. Neither the assignor nor any previous entitlement
holder that has remained liable for payments due to the affiliated PGC in
connection with the entitlement as a result of a previous assignment, sale,
or transfer is released from liability to the affiliated PGC for payments
due in connection with the entitlement unless:
(A)
At least 14 days before the effective date of the assignment,
sale, or transfer, assignee has provided security to the affiliated PGC that
is equal to or greater than the security originally given to the affiliated
PGC for the entitlement; and
(B)
At least ten days before the effective date of the assignment,
sale, or transfer, the affiliated PGC has notified both assignor and assignee
in writing that the security has been approved and accepted by the affiliated
PGC.
(5)
Requests to approve security. The affiliated PGC shall
respond to written requests to approve security to be offered by a prospective
assignee within 14 days after receipt of that request. Approval shall not
be unreasonably withheld.
(6)
Effective date. No assignment, transfer, or sale of the
entitlement by a party is binding on the non-assigning party until the non-assigning
party receives written notice of the assignment, sale, or transfer and a copy
of the executed assignment, sale, or transfer document, and the assignment,
sale, or transfer is not effective unless such notice is received at least
three days before the beginning of the entitlement month.
(j)
True-up process.
(1)
Process. For 2002 and 2003, the affiliated PGC shall reconcile,
and either credit or bill to the transmission and distribution utility, any
difference between the price of power obtained through the capacity auctions
under this section and the power cost projections that were employed for the
same time period in the ECOM model to estimate stranded costs for the affiliated
PGC in the PURA §39.201 proceeding.
(2)
PGCs without stranded costs. An affiliated PGC that does
not have stranded costs described by PURA §39.254 is not required to
comply with paragraph (1) of this subsection.
(3)
Any order by the commission that finally resolves an affiliated
PGC's stranded costs, prior to true-up, supersedes this subsection.
(k)
True-up process for electric utilities with divestiture.
If an affiliated PGC meets its capacity auction requirements through a divestiture
as allowed by subsection (d) of this section, the proceeds of the divestiture
shall be used for purposes of the true-up calculation.
(l)
Modification of auction procedures or products. Upon a
finding by the commission that the auction procedures or products require
modification to better value the products or to better suit the needs of the
competitive market, the commission may, by order, modify the procedures or
products detailed in this section.
(m)
Contract terms.
(1)
Standard agreement. Parties shall utilize the Agreement
in the form prepared by the Edison Electric Institute (Version 2.1). The Cover
Sheet to the Agreement shall provide for credit terms that are based upon
objective credit standards determined by the commission. There may be different
versions of the Agreement applicable to sales of capacity auction products
in different regions in Texas. For example, ERCOT and the non-ERCOT areas
may have different versions of the Agreement.
(2)
Applicability. The terms and conditions set forth in any
Agreement apply only to the entitlements obtained in the capacity auctions
under this section.
(3)
Electronic scheduling. The Agreement shall require that,
if the affiliated PGC provides an electronic scheduling interface for the
dispatch of entitlements, then the entitlement holder shall schedule the dispatch
of its entitlements using that electronic interface.
(4)
Scheduling discrepancies. If an entitlement holder submits
a non-conforming schedule to the affiliated PGC for an entitlement that violates
any of the scheduling requirements for that capacity auction product type
for a scheduled hour, then the schedule for that hour is deemed to be the
same as the schedule for the hour most closely preceding that scheduled hour
that was not a non-conforming schedule. The affiliated PGC shall promptly
notify the entitlement holder of a non-conforming schedule. However, the requirements
of this paragraph are subject to the default scheduling requirements for baseload
and gas-intermediate products delineated in subsections (f)(3)(A)(iv)(V) and
(f)(4)(A)(v) of this section for ERCOT areas, and subsections (g)(2)(E)(v)
and (g)(3)(E)(v) of this section for non-ERCOT areas.
(5)
Alternative dispute resolution. Alternative dispute resolution
shall be a condition precedent to any right of any legal action regarding
a dispute arising under, or in connection with, the standard agreement adopted
by the commission. The parties may mutually agree to dispute resolution procedures.
If the parties are unable to agree upon such procedures within five days after
such dispute arises, the parties shall use the alternative dispute resolution
procedures contained in the ERCOT protocols.
(6)
Seller's failure to fulfill obligation. If an entitlement
holder is assessed for imbalanced schedules, failure to procure ancillary
services, or any other charges from ERCOT due to the failure of the affiliated
PGC to fulfill the auctioned obligation, the affiliated PGC shall be responsible
for these costs incurred by the entitlement holder.
(n)
This section, as adopted, becomes effective on August 1,
2002.
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 June 19, 2002.
TRD-200203840
Rhonda G. Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: August 1, 2002
Proposal publication date: January 18, 2002
For further information, please call: (512) 936-7308
Subchapter F. REGULATION OF TELECOMMUNICATIONS SERVICE
16 TAC §26.125
The Public Utility Commission of Texas (commission) adopts
an amendment to §26.125, relating to Automatic Dial Announcing Devices
(ADADs) with no changes to the proposed text as published in the March 22,
2002
Texas Register
(27 TexReg 2162). The
amendment clarifies the permit application and renewal process for ADAD permit
holders and annual required information and reduces the fee for applications
and renewals. The commission also revises the
Texas
Permit Application
form and
Texas Permit Renewal
form and adopts a
Notification of Complaint
form. The amendment and forms were adopted under Project Number 23528.
The commission received comments on the proposed amendment and forms from
the Office of Public Utility Council (OPC). OPC sought clarification of the
reduction in fees and wondered if a cost analysis had been performed.
The commission reviewed administrative costs for the application and renewal
process and reduced fees to more accurately reflect those costs. Additionally,
the commission seeks to establish a more comprehensive database and wishes
to impose no financial impediment to the application and renewal process.
OPC expressed concern that live operators were exempt from subsection (b)(3)(B)
regarding automated dialing or hold announcements. OPC stated the Federal
Trade Commission has recognized that some telemarketers play a recorded message
rather than a brief hold announcement message when a live operator is not
available and that the automated message delivers the same message delivered
by a live operator.
The commission clarifies that live operators are not automatically exempt,
if used as described above.
To better understand and monitor this segment of the telecommunications
market and protect the public, the commission wishes to utilize a form for
the renewal process with questions identical to those on the application form.
This amendment and forms are adopted under the Public Utility
Regulatory Act, Texas Utilities Code Annotated §14.002 (Vernon 1998,
Supplement 2002) (PURA) which provides the commission with the authority to
make and enforce rules reasonably required in the exercise of its powers and
jurisdiction and specifically PURA §55.129, which provides that an ADAD
operator must obtain a permit from the commission and renew that permit annually.
Cross Reference to Statutes: Public Utility Regulatory Act §14.002;
Chapter 15, Subchapter B; Chapter 17, Subchapter B; and Chapter 55, Subchapter
F.
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 June 20, 2002.
TRD-200203870
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: July 10, 2002
Proposal publication date: March 22, 2002
For further information, please call: (512) 936-7216
16 TAC §26.130
The Public Utility Commission of Texas (commission) adopts
an amendment to §26.130 (relating to Selection of Telecommunications
Utilities) with changes to the proposed text as published in the February
15, 2002
Texas Register
(27 TexReg 1062).
This rulemaking is required by the commission's Order in Project Number 23375,
The amendment:
(1) updates references to FCC regulations;
(2) adds electronically signed letter of agency (LOA) as a verification
method;
(3) requires that customers be provided the option of using another authorization
method in lieu of an electronically signed authorization;
(4) requires that a telecommunications utility submit a change order within
no more than 60 days after obtaining verification from the customer;
(5) adds FCC provisions to the minimum requirements for third party verification;
(6) adds FCC requirements related to the notification of an alleged unauthorized
change;
(7) adds FCC requirements related to customer notice involving transferring
customers; and
(8) adds a requirement to provide FCC slamming reports containing only
Texas-specific data.
The amendment also includes requirements based on additional provisions
adopted by the FCC (CC Docket No. 94-129, Third Report and Order on Second
Reconsideration, FCC 00-255) (Third Report and Order) after adoption of the
current §26.130. The reporting requirement in §26.130(m) is based
on an FCC reporting requirement and establishes the same reporting format
and period used by the FCC.
The commission received comments on the proposed amendment from MCI Telecommunications,
Inc. (MCI), AT&T Communications of Texas, L.P. (AT&T), Texas Statewide
Telephone Cooperative, Inc. (TSTCI), Southwestern Bell Telephone, L.P., doing
business as Southwestern Bell Telephone Company (SWBT), Verizon Southwest
(Verizon), and the Office of the Attorney General of Texas (OAG). The commission
also received reply comments from MCI, AT&T, SWBT, Verizon, OAG, and Consumers
Union.
A public hearing on the proposed amendment was held at the commission offices
on April 17, 2002, at 9:30 a.m. Representatives from MCI, AT&T, SWBT,
OAG, TSTCI, Verizon, Sprint Communications Company L.P., and John Staurulakis
Incorporated participated in the public hearing.
General Comments
TSTCI expressed its appreciation of the commission's efforts to amend its
rules to mirror the FCC's rules and supported the proposed amendment as published.
TSTCI indicated that the new rule is a very positive development for Texas
telecommunications consumers and providers. OAG commended the commission for
making its slamming rule even more generally protective of customers and provided
specific support for several proposed changes to the current rule related
to naming the telecommunications utilities affected, removing all unpaid charges,
submitting change orders within 60 days after verification, and requiring
that the LOA be located on a separate screen or webpage. Consumers Union supported
the amended rule as published and the comments of the OAG. Consumers Union
further commented that slamming continues to be a problem in our state and
that the commission should adopt and enforce a rule that is in the best interest
of Texas consumers, rather than limit itself to the terms of the federal rule.
AT&T commended the commission for some laudable attempts to harmonize
the Texas rules with the FCC's rules and expressed appreciation for including
a number of its recommendations in the commission's proposed amendment. However,
AT&T pointed out that certain inconsistencies with the FCC's rules still
exist and proposed several changes to the proposed amendment designed to produce
rules that would be consistent with the FCC's rules - reasonable, efficient,
and strike the right balance between benefits and burdens. Similarly, SWBT
stated that the commission incorporated several suggestions in the proposed
amendment bringing the rule more in line with federal rules, but indicated
that further changes were required to provide more consistency. MCI stated
its appreciation for the consideration given to its previous suggested revisions
but reiterated several concerns with the proposed amendment.
The commission appreciates the inputs to this rulemaking process from all
of the parties at the workshop in November 2001, after publication of the
proposed amendment, and at the public hearing in April 2002. The commission
included several recommendations in developing the proposed amendment and
adopts additional recommendations as indicated later in this preamble. The
adopted amendment is based on the following considerations: ensuring customer
protection while fostering competition in providing telecommunications services;
minimizing administrative requirements and cost; ensuring compliance with
all requirements of the Public Utility Regulatory Act (PURA); and enhancing
consistency with current applicable FCC rules.
As the commission indicated in Project Number 23375, the consistency provision
in PURA §55.308 does not require that the commission rules duplicate
those of the FCC. The FCC allows flexibility to the states with regard to
remedies and has stated that they will not interfere with the state's ability
to adopt more stringent regulations, that they must work hand-in-hand with
the states to combat slamming, and that states have valuable insight into
slamming problems in their respective locales.
Subsection (b), Definitions
AT&T, SWBT, MCI, and Verizon recommended revising the definition of
"customer" in proposed subsection (b)(2) to more closely mirror the FCC's
definition of "subscriber" to recognize that the customer may authorize someone
to act on his/her behalf. The parties indicated that the current Texas rule
limits the definition of a person who may authorize a change in residential
carrier selection to either the account holder or the account holder's spouse,
that the proposed expansion of the definition would promote customer choice
and competition without increasing slamming, and that their proposal is consistent
with the FCC definition and rationale.
AT&T stated that it appears that the commission's definition for "customer"
in this rule was taken from PURA §64.002(4), which explicitly relates
to Chapter 64, Customer Protection, only, and most specifically to the anti-cramming
measures that the Legislature placed in that chapter. AT&T disagreed that
the definition in Chapter 64 is also appropriate in the slamming context.
AT&T pointed out that Chapter 64 was added during the 1999 legislative
session, and Chapter 55, Subchapter K (regarding Selection of Telecommunications
Utilities) was also amended during that session, yet the Legislature did not
adopt a definition of "customer" for slamming.
The commission does not agree with expanding the definition of "customer."
The commission considered this issue during the previous amendment to this
rule in Project Number 21419,
Amendments to §26.130
Regarding Customer's Right to Choice (Slamming) (PURA Section 17.004(a)(5)
- SB 86)
. The definition in subsection (b)(2) already includes a spouse,
is consistent with the definition used by the commission since it was granted
jurisdiction over slamming in 1997, and is consistent with the definition
used for cramming in §26.32, Protection Against Unauthorized Billing
Charges ("Cramming"). The commission believes that expanding the current definition
would result in reduced carrier safeguards and lead to an increase in slamming.
Expansion of the definition would not promote greater customer choice because
it would result in additional switches in a customer's service caused by unauthorized
persons.
MCI recommended adding language used in the FCC definition to the definition
of "executing telecommunications utility" in proposed subsection (b)(3).
The commission agrees with MCI and adds the language to proposed subsection
(b)(3).
Subsection (c), Changes in preferred telecommunications
utility
AT&T opposed the requirement in proposed subsection (c)(1) that makes
it mandatory for a submitting telecommunications utility to submit a change
order within 60 days after obtaining verification from the customer. AT&T
commented that a utility may not submit an order because service cannot otherwise
be provided (
e.g.
, no facilities in the area
at the time, customer fails to submit the required deposit, etc.). AT&T
stated that because it appears that the commission's proposed requirement
is based on a similar requirement in the FCC's rules, at a minimum the Texas
requirement should also be limited to written or electronic verifications,
as the FCC's rule is so limited. AT&T further indicated that there is
no need for such a restriction on authorizations verified by third party verification
(TPV) or other forms of verification and that this requirement should not
be applied to business customers. AT&T proposed that, at a minimum, the
proposed rule should be modified to reflect that an initial, or blanket, authorization
may be extended by the customer to cover a period beyond the 60 days contemplated
by the rule.
MCI agreed with AT&T's comments and recommended that the requirement
to submit a change order within 60 days be limited to written or electronic
verifications and to residential customers.
OAG supported proposed subsection (c)(1). In its reply comments, SWBT agreed
with the commission and OAG that carriers should submit change orders within
60 days. SWBT stated that having a definite and limited time period will protect
consumers by preventing problems with "stale" orders that may no longer be
active and urged the commission to keep the 60-day period intact.
The commission agrees with OAG and SWBT and makes no changes to proposed
subsection (c)(1). The commission recognizes that the FCC's 60-day limitation
is included only in the section for letters of agency. However, the underlying
purpose of this requirement, timely submission of change orders, applies regardless
of the verification method used by a carrier to confirm a switch in service
provider.
AT&T supported the commission's proposed subsection (c)(1)(C)(ii) to
allow recorded verifications to be provided via a wave sound file. AT&T
also recommended that the rule permit the use of CD ROMs or other similar
technically compatible devices. AT&T stated that if the commission has
the technical capability to access the data, then the rule should permit flexibility
in the carrier's use of recording medium. Verizon indicated that it did not
oppose AT&T's proposal as long as the recording medium does not burden
the carrier receiving the TPV. Carriers receiving the TPV should not be forced
to purchase additional equipment as a result of the recording medium used
in the TPV process.
The commission finds merit in AT&T's recommendation to allow other
devices to record third party verifications. The commission shares Verizon's
concern about requiring carriers to purchase additional equipment. The commission
does not wish to require specific devices or hinder the use of advanced technological
recording devices used to record TPVs. However, TPV recordings submitted to
the commission as part of a complaint investigation must be in a recorded
medium that is compatible with the commission's equipment. Accordingly, the
commission revises proposed subsection (c)(1)(C)(ii) to allow other recording
devices that are compatible with the commission's equipment.
AT&T opposed the requirement in proposed subsection (c)(1)(C)(iv) and
in proposed subsection (d)(3)(B), to elicit the names of the telecommunications
utilities affected by the change. This was not previously a TPV requirement
and AT&T saw no reason to add it now. AT&T stated it believes that
the process of changing carriers should be easy and convenient for customers.
Customers should not be subjected to a rejection of their attempt to switch
carriers merely because they do not recall the name of the carrier at the
time the TPV call is made. Further, the requirement to elicit this information
does nothing to improve the verification process since neither the submitting
carrier nor the TPV agent has access to information that would indicate whether
or not the customer has correctly identified the "current telecommunications
utility." It should be sufficient that the customer indicates an affirmative
decision to choose the new carrier and not have to also indicate a decision
to reject the previous carrier.
MCI stated that a customer or customer's spouse may not be aware of the
name of the current provider and recommended qualifying proposed subsection
(c)(1)(C)(iv) to require the naming of the telecommunications utilities affected
"if available." Verizon did not agree with MCI's recommended qualification
and instead proposed the requirement be eliminated. Verizon also stated that
the FCC does not require that a customer provide the name of the current provider.
OAG supported the requirement in proposed subsection (c)(1)(C)(iv) that the
third party verifier elicit the names of the telecommunications utilities
affected.
The commission adopts proposed subsection (c)(1)(C)(iv) without changes.
The requirement to identify the customer's current carrier provides an additional
protection against unauthorized switches in service. The commission points
out that this is also an FCC third party verification requirement in 47 Code
of Federal Regulations (C.F.R.) §64.1120(c)(3)(iii).
AT&T opposed the provision in proposed subsection (c)(1)(C)(vii) requiring
the sales representative to drop off the TPV call once the three-way connection
has been established. AT&T commented that the FCC adopted a similar rule
in its Third Report and Order. However, petitions for reconsideration have
been filed with the FCC noting the lack of record support for the rule, the
FCC's failure to consider comments opposed to the rule, and the significant
free- speech issues raised by the rule. AT&T stated that the sales representative
often can play an important part in the call by answering any questions about
the service that might arise during the verification process. In AT&T's
view, rather than outlawing all speech by the sales representative, a more
reasoned and reasonable approach would be to limit the sales representative's
participation to answering questions in a neutral manner or other narrowly
tailored limits.
The commission disagrees with AT&T's suggestion and adopts proposed
subsection (c)(1)(C)(vii) without changes. The requirement is necessary to
ensure the third party verification process is neutral and independent in
obtaining clear and conspicuous consent from the customer. This is also, as
AT&T recognized, a current FCC requirement in 47 C.F.R. §64.1120(c)(3)(ii).
Subsection (d), Letters of Agency (LOA)
For the same reasons described in the comments on proposed subsection (c)(1)(C)(iv)
above, AT&T and Verizon opposed the requirement in proposed subsection
(d)(3)(A)(ii) to verify the customer's current utility. Similarly, AT&T
suggested modifying the "sample" LOA language under proposed subsection (d)(3)(B)
to make it clear that the customer is authorizing a change from the current
utility, without the requirement that the current utility be named.
The commission adopts proposed subsection (d)(3)(A)(ii) and (d)(3)(B) without
changes. As indicated previously, the requirement to identify the customer's
current carrier provides an additional protection against unauthorized switches
in service. The FCC does not include this requirement for LOA verification,
but it does for third party verification. The commission can find no reason
why this requirement should apply to one verification method but not the other.
The commission believes that the customer protection benefit of this provision
should apply to both verification methods.
AT&T opposed the requirement in proposed subsection (d)(3)(A)(v) that
the LOA must contain a separate statement that the customer may consult with
the carrier as to whether a fee applies to the change. AT&T stated that
the rule already requires that the customer be informed that a charge may
apply and that even the most unsophisticated customer should be expected to
know that they may inquire of the utility whether a change charge will be
imposed. AT&T further stated that its LOA is already straining with the
amount of text that must be provided to a customer, and this particular requirement
seems especially unnecessary.
The commission adopts proposed subsection (d)(3)(A)(v) without changes.
The commission views the required statement as informative to the customer
and does not consider it burdensome to carriers. Furthermore, this statement
is an FCC LOA verification requirement in 47 C.F.R. §64.1130(e)(5).
Subsection (e), Notification of alleged unauthorized
change
AT&T, SWBT, and MCI opposed the requirement in proposed subsection
(e)(3) that the alleged unauthorized telecommunications utility remove all
unpaid charges pending a determination of whether an unauthorized change occurred.
The parties recommended limiting the removal of charges to the first 30 days
after the alleged slam and pointed out that this limitation is consistent
with the federal rules on slamming in 47 C.F.R. §64.1160(b). They further
commented that this limitation encourages consumers to become more vigilant
in detecting slamming by giving them incentive to review their telephone bills
carefully. AT&T cited backbilling and uncollectible problems as a result
of the proposed rule. SWBT commented that the FCC reconsidered the time period
for absolution of charges in 2000 and declined to extend the absolution period
beyond 30 days.
In its comments, OAG supported the requirement in proposed subsection (e)(3)
to remove all unpaid charges. In its reply comments, OAG reaffirmed its support
for the published rule and indicated that limitations on removal of charges
would not be ultimately protective of customers and that should the allegation
prove incorrect, the carrier would, of course, be entitled to payment of all
legally incurred obligations.
The commission adopts proposed subsection (e)(3) without changes. The rule
is consistent with the policy of removing any profit from slamming by preventing
an alleged unauthorized carrier from requiring any payment from a customer
after an alleged slam is reported. If it is subsequently determined that there
was no slam, the alleged unauthorized carrier is entitled to full payment
of all charges. If there was a slam, the customer is absolved of charges for
the first 30 days, the authorized carrier is entitled to all charges after
the first 30 days based on its rates, and the unauthorized carrier must make
refunds to the customer and the authorized carrier in accordance with subsection
(f).
Proposed subsection (e)(4) states that the alleged unauthorized telecommunications
utility may challenge a complainant's allegation of an unauthorized change
by notifying the complainant to file a complaint with the Public Utility Commission
of Texas within 30 days and that if the complainant does not file a complaint
within 30 days, the unpaid charges may be reinstated. AT&T commented that
on the surface this provision looks beneficial to utilities; however, AT&T
has been unable to assess how practical it would be to both track its compliance
with the requirement to inform the customer and to track whether the customer
subsequently files a complaint with the commission within 30 days. Consequently,
at this point AT&T indicated it could not agree that this provision would
provide a practical benefit to utilities. AT&T stated that, more importantly,
it is concerned that proposed subsection (e)(4) might be viewed by the commission
as some sort of mitigation of the objectionable requirement to remove all
unpaid charges in proposed subsection (e)(3). AT&T further commented that
if a timely complaint is filed, proposed subsection (e)(4) does not limit
the removal of unpaid charges during the pendency of a complaint, so it does
not address the concern raised by AT&T that proposed subsection (e)(3)
would permit a customer to continue to receive service without paying for
an extended period of time. Consequently, AT&T recommended proposed subsection
(e)(3) be modified to reflect that only 30 days of unpaid charges should be
removed.
MCI commented that proposed subsection (e)(4) is a beneficial addition
if clarified as recommended by AT&T MCI suggested revising proposed subsection
(e)(4) to add clarifying language and the requirement for the commission to
provide the unauthorized carrier a copy of the complaint during the same 30-day
period.
The commission adopts proposed subsection (e)(4) without changes. The commission
believes the rule is clear and that MCI's suggested clarifying language is
unnecessary. Nevertheless, the commission is sensitive to AT&T's and MCI's
concerns and is committed to ensuring slamming complaints are forwarded to
carriers promptly and resolved in a timely manner.
Proposed subsection (e)(5) requires that the alleged unauthorized telecommunications
utility take all actions within its control to facilitate the customer's prompt
return to the original telecommunication utility within three business days
of the customer's request. SWBT commented that in the event of an alleged
dial tone slam, however, an additional requirement is necessary to ensure
that a customer is returned to his authorized utility within three business
days. SWBT suggested adding language to proposed subsection (e)(5) requiring
an alleged unauthorized dial tone provider to respond to the authorized dial
tone provider with a Firm Order Confirmation (FOC) within one business day
if the authorized carrier clearly indicates that the request is the result
of an alleged slam. In addition, if the alleged unauthorized utility cannot
meet the three business day interval, the unauthorized utility should inform
the commission, the customer, and the authorized utility that this customer
will experience a delayed return and inform them as to when the return will
occur. SWBT indicated that this proposed provision is necessary so that customers
can learn of their return date.
AT&T strongly opposed SWBT's proposal indicating it would result in
the micro-managing of local slams and would introduce specialized treatment
(which may be contrary to interconnection agreements) for handling local service
customers merely on the basis of an alleged slam. AT&T commented that
the commission is aware of the difficulty in switching local service customers
and that returning the customer within three business days is ambitious enough.
AT&T also expressed concern that SWBT's recommended change could cause
customers or carriers to allege a slam in order to switch service faster.
AT&T further stated that it would be unfair and inequitable to require
an alleged unauthorized carrier to incur the additional costs of providing
notices. AT&T concluded that the commission's proposed rule is sufficient
and should not be revised.
MCI also disagreed with SWBT indicating that the proposed requirement for
a one-business day turnaround for alleged local slams is unworkable. Verizon
agreed with the intent of SWBT's proposal, but indicated that the commission
should not prescribe the response time for an alleged unauthorized carrier
until the commission completes Project Number 24389,
CLEC-to- CLEC Conversion Guidelines.
The commission adopts proposed subsection (e)(5) without changes. While
the commission agrees with the intent of SWBT's recommendation, it would not
be appropriate at this time to require a one-day turnaround. Nevertheless,
the commission expects all carriers to take all necessary actions to ensure
customers are returned to their preferred carrier promptly after there is
an alleged slam.
SWBT suggested a new subsection (e)(6), which makes the alleged unauthorized
telecommunications utility liable for any charges required to change the customer
from his or her authorized utility to the alleged unauthorized utility, in
addition to charges assessed for returning the customer to his or her properly
authorized telecommunications utility. SWBT indicated that this change ensures
that neither the authorized telecommunications utility nor the customer incurs
any expense as a result of the actions of an unauthorized utility. SWBT further
commented that making the unauthorized telecommunications utility liable for
these charges acts as a further deterrent to slamming and is consistent with
FCC rules.
MCI stated that it does not oppose SWBT's proposal, but does oppose any
charges that permit a carrier to disguise administrative penalties as unauthorized
change charges. At the public hearing, AT&T voiced similar concerns. MCI
recommended that if the commission determines that such charges are proper,
then the charges should be uniform and reasonable and apply to all carriers.
Verizon supported SWBT's recommendation indicating that it puts the cost
on the cost causer, the unauthorized carrier, and not the customer or the
authorized carrier. Verizon further commented that it would serve as a further
deterrent to slamming and complies with the federal rules.
The commission agrees with SWBT's recommendation and adds subsection (e)(6),
accordingly. The commission clarifies that this new provision applies to standard
switching charges and in no way authorizes local exchange companies to levy
any additional charges or penalties as a result of an alleged slam.
Verizon recommended adding a provision in subsection (e) that authorizes
an alleged unauthorized carrier to invoke self-help in situations where it
prefers not to challenge a specific unauthorized change allegation. Under
this proposal any carrier selecting this option would be required to provide
the customer all of the remedies of a valid slam and to advise the customer
to file a complaint with the commission if not satisfied with the remedies
offered. Verizon pointed out that the FCC has approved this means to resolve
slamming complaints because it expedites delivery of relief and eases administrative
burdens on governmental agencies.
The commission agrees with the self-help option described by Verizon and
encourages carriers to provide prompt relief to customers alleging a slam.
However, the commission does not believe a rule is needed for carriers to
use the approach recommended by Verizon. The commission points out that many
carriers, as a matter of standard practice, do not challenge any slamming
complaint and provide the complainant with appropriate refunds. Neither the
current or adopted rules discourage carriers from using this approach. The
commission's approach is consistent with the FCC, which also encourages self-help,
but did not deem it necessary to have a rule prescribing it.
Subsection (f), Unauthorized changes
AT&T recommended that a change similar to the one proposed for subsection
(e)(3) be made to subsection (f)(1)(F) to clarify that unpaid charges need
to be removed for only the first 30 days after a slamming allegation is made.
In addition, AT&T recommended that subsection (f)(1) be clarified to indicate
that the prescribed actions only apply in cases where a violation is found.
MCI and Verizon agreed that the required actions in proposed subsection (f)(1)
apply only if the commission finds a violation.
SWBT and Verizon proposed changing proposed subsection (f)(1) and (2) to
comport with the absolution procedures set forth in 47 C.F.R. §64.1160
and §64.1170. The parties indicated that this change will ensure that
the Texas absolution process is consistent with the FCC process and eliminate
customer and utility confusion that could result from having different procedures
in place in different jurisdictions.
OAG supported the decision of the commission to maintain its procedure
in which the unauthorized carrier makes a direct refund to the customer. OAG
pointed out that absolute consistency with the federal rules is not required
and that the State did a better job of protecting the consumer than the federal
rules. OAG stated that the commission's procedure is more directly responsive
to the consumer's needs and more efficient since it does not unnecessarily
involve the authorized carrier.
The commission adopts proposed subsection (f)(1) and (2) without changes.
As stated in the commission's Order in Project Number 23375, the consistency
provision in PURA §55.308 does not require that the commission rules
duplicate those of the FCC. The FCC allows flexibility to the states with
regard to remedies as indicated in CC Docket No. 94-129 FCC 00- 135, footnote
105. Also, in paragraph 87 of CC Docket No. 94-129 FCC 00-255, the FCC states
that they will not interfere with the state's ability to adopt more stringent
regulations, that they must work hand-in-hand with the states to combat slamming,
and that states have valuable insight into slamming problems in their respective
locales.
Subsection (f)(1) requires the unauthorized carrier to make a direct refund
to the customer based on all charges for the first 30 days after a slam and
a re-rating of charges after the first 30 days. The unauthorized carrier is
also required to pay the authorized carrier any amount paid to it by the customer
that would have been paid to the authorized carrier if the slam had not occurred.
The FCC rules require the unauthorized carrier to pay the authorized carrier
150% of the amount paid by the customer and the authorized carrier to refund
the customer 50% of the amount paid by the customer. While the commission's
approach does not duplicate the FCC's procedures, it is consistent with the
FCC's objectives and purpose.
The FCC requires the unauthorized carrier to pay the authorized carrier
and then the authorized carrier makes the refund to the customer. If, however,
the authorized carrier does not receive payment from the unauthorized carrier,
the authorized carrier must inform the customer of this and the customer's
right to pursue a claim against the unauthorized carrier. This refunding process
was based on the original FCC approach, which required the authorized carrier
to resolve slamming complaints. Under the new approach where either the FCC
or the states that opt-in will resolve the complaints, it is more efficient
and effective to have the unauthorized carrier make a direct refund to the
customer.
AT&T recommended a new provision for proposed subsection (f) that would
prohibit carriers from attempting to levy additional charges or "penalties"
on an alleged unauthorized carrier. AT&T stated that it has encountered
attempts to add such provisions in Texas as well as in other jurisdictions
and that attempts to add such provisions in Texas and other jurisdictions
have been previously rejected. AT&T requested the addition of appropriate
language so that it does not have to devote the time and resources to constantly
guard against such proposals and contest them in tariff filings.
SWBT and Verizon opposed AT&T's proposal stating that the proposed
language is not consistent with federal and state slamming rules, which provide
that the customer has a right to be made whole at the allegation of a slam.
SWBT further noted that the alleged unauthorized carrier may re-bill the customer
if the customer does not file a complaint or if the FCC or commission determine
that an unauthorized switch did not occur. Verizon stated that the executing
carrier should not be required to bear the burden of recovering the switchback
charge and that, instead, the alleged unauthorized carrier is in the best
position to incur the charge.
The commission does not agree with AT&T's recommended additional provision.
The commission points out that there is nothing in these adopted rules that
permits executing carriers to levy any penalty for alleged slamming.
Subsection (g), Notice of customer rights
SWBT proposed changing the notification requirement in proposed subsection
(g) to reflect SWBT's recommended changes to proposed subsection (f)(1) and
(2), above.
The commission makes no changes to subsection (g) since SWBT's recommended
changes to proposed subsection (f)(1) and (2) were not adopted.
Subsection (h), Compliance and enforcement
AT&T recommended that subsection (h)(1) be clarified to indicate that
the telecommunications utility has no obligation to provide copies of records
after the 24-month record retention period (as required under proposed subsection
(c)(1)) has expired. AT&T commented that based on the commission's orders
in Project Number 20934,
Office of Customer Protection
(OCP) Investigation of Axces, Inc. for Continued Violations of P.U.C. SUBST.
R. 26.130, Selection of Telecommunications Utilities, Pursuant to Procedural
Rules 22.246, Administrative Penalties
, it seems almost inescapable
that a carrier would be unable to meet its burden in the case of an alleged
"regulatory slam." At a minimum, AT&T stated that a telecommunications
utility should not be subject to sanctions under proposed subsection (h)(1)
for failure to maintain records after the record retention period in proposed
subsection (c)(1) has expired.
Additionally, AT&T proposed that a new subsection (h)(5) be added to
specifically prohibit any enforcement action against the telecommunications
utility after 24 months has elapsed from the date of an alleged slam. AT&T
commented that a telecommunications utility should not be penalized for the
customer's delay and lack of diligence, particularly since every bill the
customer received during that 24-month period would have listed the customer's
preferred telecommunications utility, as required by subsection (i). AT&T
stated that a complaint received after the 24-month record retention period
should simply be treated as a request to change to a different carrier (presumably
back to the customer's previous carrier), and the allegedly unauthorized carrier
should be required to facilitate the return to the previous carrier, but it
should not be treated as an unauthorized telecommunications utility under
the rule and should not be subject to any penalties or refund requirement.
Verizon agreed with AT&T's recommendations and further proposed that
the commission adopt the federal two-year statute of limitations on slamming
complaints so that the record retention requirement is coextensive with the
customer's right to maintain a slamming complaint.
OAG opposed AT&T's recommendations. OAG commented that the records
retention requirement should not serve as a shield to the customer's right
to complain and recover or the commission's right to take action if any party
has maintained records or is otherwise able to prove through other means that
a violation occurred more than two years prior to the present date. OAG further
stated that to allow carriers to restrict enforcement action and consumer
recovery on the basis of their own records retention policies is an unconscionable
restriction on consumer rights.
The commission adopts proposed subsection (h) without changes. The commission
agrees with OAG that record retention requirements should not limit the consumer's
or the commission's rights. While filing a complaint two years or more after
a slam is very rare, the commission has never limited the time period for
a complaint and to do so now would dilute current customer protection.
Subsection (i), Notice of identity of a customer's
telecommunications utility
Proposed subsection (i)(4) would change the bill notice provision to refer
to the "Customer Protection Division" instead of the "Office of Customer Protection".
AT&T commented that, although this appears to be a minor change, it would
result in additional cost to telecommunications utilities to make this change
in their billing system. AT&T proposed that all references to CPD or OCP
simply be deleted so that carriers do not have to change their billing systems
each time the commission reorganizes or renames its divisions. AT&T further
indicated that this approach was adopted in the cramming rule, §26.32(g)(4),
so that the notice required in that section does not specifically refer to
any division of the commission. AT&T recommended that a similar change
be adopted here.
The commission agrees with AT&T's recommendation and revises proposed
subsection (i)(4) accordingly.
Subsection (j), Preferred telecommunications utility
freezes
SWBT recommended revising proposed subsection (j)(8), (4)(D), (6)(G)(iv),
(12), (13), and (14) to permit a local exchange company (LEC) to charge the
customer for imposing or lifting a freeze. SWBT pointed out that the FCC allows
these charges, but the Texas rule does not. SWBT commented that LECs should
be permitted to recover costs for providing freeze protection service to customers
since LECs incur significant costs associated with administering freeze protection
services - services that both customers and telecommunications utilities recognize
to be a valuable deterrent against unauthorized changes. SWBT further pointed
out that both the Texas and FCC slamming rules make offering freeze protection
services discretionary with the LEC and that allowing LECs to recover costs
associated with these services will encourage LECs to continue to offer these
services and assist in the deterrence of slamming.
AT&T opposed SWBT's recommendation. AT&T commented that allowing
LECs to charge for freezes would undermine the benefits of freezes, that the
prohibition on charges for freezes does not appear to have deterred LECs from
offering freezes, and that imposing charges would deter some customers from
requesting freeze protection. AT&T also expressed concern that SWBT would
be able to charge any rate it chose and indicated that if the commission were
to allow freeze charges, existing customers should be grandfathered from any
charges and the LEC rates should be cost-based.
Consumers Union and OAG recommended that SWBT's proposal be rejected. The
parties stated the proposal would erode customer protection and that consumers
should not be required to pay a premium in order to protect their legal right
to be served by the company of their own choosing.
The commission considered the issue of allowing charges for freezes when
it adopted the current rule in Project Number 21419. The commission remains
convinced that a freeze is a basic customer protection that should be made
available to customers at no charge. The commission believes that this prohibition
is not in conflict with FCC rules, which allow a charge, but do not require
it. Therefore, the commission adopts proposed subsection (j) without changes.
AT&T proposed a new provision to proposed subsection (j), which would
allow a customer to change carriers by directly contacting the LEC during
a three-way call to lift a freeze. AT&T commented that under the current
rule, to accomplish a change when there is a freeze on the line, the customer
must make two separate calls to the LEC. First, the customer contacts the
new preferred carrier and selects the appropriate services. However, if there
is a freeze on the line, the customer and preferred carrier must make a three-way
call to notify the LEC to lift the freeze so the customer may change the preferred
interexchange carrier (PIC) selection. AT&T stated that under subsection
(c)(2) of the proposed rules the customer can change the PIC selection by
contacting the LEC, but some LECs have refused to accept such a change order
from the customer as part of the three-way call. As a result, the customer
must make another call to the LEC to make the change or must go through some
other form of verification. AT&T indicated that there is no need for this
two- step process.
Verizon disagreed with AT&T's proposal. Verizon pointed out under the
proposal, submitting carriers could circumvent the TPV process and may lead
to "finger-pointing" in the event of an unauthorized change. Verizon also
indicated that this proposal was specifically rejected by the FCC.
The commission does not adopt AT&T's proposal to require a LEC to accept
the customer's oral request to change a preferred carrier as part of a three-way
call to lift a freeze. The FCC requires three-way calling only for the purpose
of lifting freezes. There are separate, explicit FCC rules for verification
of carrier changes and for verification of freezes that clearly distinguish
the role of each carrier. The FCC has stated that the three-way call merely
lifts the freeze and that the submitting carrier must follow the federal commission's
verification rules before submitting a carrier change.
Subsection (k), Transferring customers from one
telecommunications utility to another
Verizon recommended that proposed subsection (k) be modified to track with
the corresponding federal rule, 47 C.F.R. §64.1200(e)(3). Verizon believes
that consistency in state and federal rules reduces administrative burdens
on utilities and eliminates customer confusion.
The commission believes proposed subsection (k) is consistent with the
FCC rule and adopts it without changes. The commission's rule prescribing
notice requirements related to the transfer of customers, preceded the FCC's
rule. Proposed subsection (k) added FCC requirements that were not already
in the current rule.
Subsection (l), Complaints to the commission
Consistent with AT&T's proposed revisions to subsection (h) discussed
above, AT&T also proposed that subsection (l) be revised to limit the
obligations of utilities when a complaint is filed after the record retention
period in the rules has expired. AT&T claimed that it is not unreasonable
for consumers to be obligated to bring a complaint of slamming within two
years of the time that they were first provided service by a new utility.
As previously discussed, the commission does not agree with AT&T's
proposal.
SWBT proposed increasing the time for a telecommunications utility to respond
to the Customer Protection Division (CPD) on a complaint from 21 to 30 days.
SWBT indicated that this period is consistent with 47 C.F.R. §64.1150(d),
which allows 30 days for a telecommunications utility's response to an alleged
slamming violation. SWBT maintained that the additional time is needed to
allow a utility to adequately research a complaint and compile a response
that will contain the necessary information about the change request and the
verification for that customer's change request. MCI agreed with SWBT's recommendation.
OAG and Consumers Union stated that proposals to extend the time for responding
to complaints should be rejected. They pointed out that extending the timeline
is contrary to the clear directive of the legislators and the commissioners
to streamline the consumer complaint process and that the focus should be
on reducing everyone's response time.
At the public hearing Sprint, MCI, and AT&T expressed concerns about
shortening the response time for complaints, responding to a batch of complaints
simultaneously, and receiving complaints lacking adequate information to investigate.
The commission does not agree with the recommendation to increase the time
required to respond to a complaint. Instead, the commission is focused on
reducing response time without sacrificing complaint investigation quality.
AT&T expressed concern at the public hearing that proposed subsection
(l)(1) replaced a list of specific items that should be in a complaint with
language indicating that a complaint should include appropriate information.
AT&T stated that specific information about the complaint is essential
and that for business complaints additional information is necessary such
as the name of the business, main billing number, and contact person and number.
Commission staff explained that the intent of the proposed change to subsection
(l)(1) was to indicate that some complaints forwarded to the telecommunications
utility may not contain all of the listed information. CPD would continue
to request all of the information listed in current subsection (l)(1). However,
if the complainant failed to provide all of the items required in current
subsection (l)(1),
i.e.
, a copy of the bill,
but provided sufficient information to investigate the complaint, then the
complaint would be forwarded to the telecommunications utility. To address
the concerns about proposed subsection (l)(1), OAG recommended changing the
focus slightly by having the rule say: "CPD shall request the following information."
AT&T concurred with OAG's recommendation.
The commission revises proposed subsection (l)(1) to adopt the language
recommended by OAG.
Penalty Matrix
AT&T recommended that the proposed rule be amended to include a penalty
matrix to indicate the range of administrative penalties that would be proposed
in the event of a violation of the rule. AT&T stated that the criteria
for assessing an administrative penalty under PURA §15.023(c) make it
clear that not all incidents of slamming should be subject to the same penalty.
AT&T commented that the commission's recent Order Remanding for Further
Consideration in Project Number 20934 indicates that the commission recognizes
that not all slamming violations are automatically deserving the maximum penalty
of $5,000 per day, and that the amount of the penalty should vary with the
seriousness of the violation, including whether the violation is "administrative
in nature." AT&T strongly encouraged the commission to develop a matrix
of recommended penalties based on the seriousness of the alleged violation,
to do so with the input of all stakeholders, and to formally adopt such a
matrix. AT&T stated that this would provide predictability for carriers
and staff, and should result in more efficient settlement of notices of apparent
violation.
MCI supported AT&T's request to include a penalty matrix indicating
that it will serve to ensure consistency and even-handedness in the commission's
enforcement and imposition of administrative penalties.
Consumers Union advocated that the penalty matrix be rejected, pointing
out that inclusion is beyond the scope of this rulemaking and would require
republication. Furthermore, the commission already has flexibility to propose
penalties based on the nature and severity of the rules violation. For example,
slamming enforcement cases generally result in settlements where the commission
has the flexibility to consider various factors, such as culpability and the
carrier's pattern of behavior, before reaching an agreement on the settlement
amount. The commission's own review and analysis of each enforcement action
should not be replaced with a standardized penalty matrix. Consumers Union
indicated that a penalty matrix is likely to become a "price list" for telecommunication
utilities, so they know the potential financial implication of cutting corners
on strict adherence to the rules.
OAG indicated that this rulemaking was not properly noticed for the adoption
of a penalty matrix. OAG commented that while there may be some potential
benefit to a matrix, there are drawbacks as well in creating a system where
potential violators can calculate, in advance, the exact cost of regulatory
violations and plan a business strategy around them. OAG further stated that
all of these factors and their implications for all aspects of the commission's
rules, not just slamming, should be considered in a properly noticed rulemaking
on the subject of a penalty matrix.
The commission agrees that including a penalty matrix would be beyond the
scope of this rulemaking and has not yet decided whether a penalty matrix
should be developed. The commission acknowledges the view of some carriers
that a penalty matrix would promote consistent and fair enforcement. However,
the commission also recognizes the potential disadvantages of a penalty matrix
such as a loss of flexibility, perception of diminished resolve to combat
slamming, and reduced efforts by carriers to prevent unauthorized switches
in service.
Since the commission was granted jurisdiction over slamming in September
1997, it has taken a strong stance against slamming in this state and Texas
has been recognized as one of the leading states in combating slamming. In
keeping with a "zero tolerance for slamming" policy, the strict liability
requirement on carriers to obtain customer consent, and consideration of all
of the pertinent factors in P.U.C. Procedural Rule §22.246(c), Administrative
Penalties, commission staff has consistently recommended a penalty of $5,000
per violation in its administrative penalty notices for slamming violations.
Upon receiving a notice, in accordance with §22.246, alleged violators
are given three options: pay the penalty, request a hearing, or request a
settlement conference to discuss the occurrence of the violation and/or the
amount of the penalty. In every case, the alleged violator has responded to
a notice by requesting a settlement conference. At the settlement conference
the carrier is able to present any information to address the nature of the
violation and the appropriateness of the penalty amount. With the exception
of Project Number 20934 and Docket Number 24673,
Notice of Intent to Assess an Administrative Penalty and Revoke Registration
of Axces, Inc. for Repeated and Reckless Violations of PUC SUBST. R. §26.130,
Selection of Telecommunications Utilities
, commission staff has reached
settlement agreements with carriers who were issued a notice for slamming
violations and the commission has approved these agreements. The final settlement
amount was based on a consideration of the information provided by the carrier
and often was less than $5,000 per violation. There has never been an automatic
$5,000 penalty for every slamming violation. The commission believes that
its approach has been consistent, fair, and reasonable.
In the Order Remanding for Further Consideration in Project Number 20934,
the commission stated it does not favor automatically imposing a $5,000 administrative
penalty for each violation, noting that certain violations are administrative
in nature and may warrant an administrative penalty of less than $5,000.
The commission reaffirms its policy of "zero tolerance for slamming." Slamming
harms not only the customers that are slammed, but also the carriers who have
implemented effective policies and procedures to ensure customer consent before
switching service. The commission states that administrative penalties shall
be consistent with that policy and must not be viewed as a cost of doing business,
but instead serve as a deterrent.
In summary, the commission believes that its anti-slamming policy and enforcement
approach have served the public interest well without denying carriers their
due process. Nevertheless, the commission will reexamine its process to determine
if development of a penalty matrix or any other changes will enhance the current
process.
All comments, including any not specifically referenced herein, were fully
considered by the commission. In adopting this amendment, the commission makes
other minor modifications for the purpose of clarifying its intent.
This amendment is adopted under the Public Utility Regulatory
Act, Texas Utilities Code Annotated §14.002 (Vernon 1998, Supplement
2002) (PURA), which provides the Public Utility Commission with the authority
to make and enforce rules reasonably required in the exercise of its powers
and jurisdiction; and specifically PURA §55.302 which grants the commission
authority to adopt and enforce rules to implement the provisions of PURA Chapter
55, Subchapter K, Selection of Telecommunications Utilities.
Cross Index to Statutes: Public Utility Regulatory Act §§14.002
and 55.301 - 55.308.
§26.130.Selection of Telecommunications Utilities.
(a)
Purpose and Application.
(1)
Purpose. The provisions of this section are intended to
ensure that all customers in this state are protected from an unauthorized
change in a customer's local or long- distance telecommunications utility.
(2)
Application. This section, including any references in
this section to requirements in 47 Code of Federal Regulations (C.F.R.) §64.1120
and §64.1130 (changing long distance service), applies to all "telecommunications
utilities," as that term is defined in §26.5 of this title (relating
to Definitions). This section does not apply to an unauthorized charge unrelated
to a change in preferred telecommunications utility which is addressed in §26.32
of this title (relating to Protection Against Unauthorized Billing Charges
("Cramming")).
(b)
Definitions. The following words and terms when used in
this section shall have the following meanings unless the context indicates
otherwise:
(1)
Authorized telecommunications utility - Any telecommunications
utility that submits a change request that is in accordance with the requirements
of this section.
(2)
Customer - Any person, and that person's spouse, in whose
name telephone service is billed, including individuals, governmental units
at all levels of government, corporate entities, and any other entity with
legal capacity to be billed for telephone service.
(3)
Executing telecommunications utility - Any telecommunications
utility that effects a request that a customer's preferred telecommunications
utility be changed. A telecommunications utility may be treated as an executing
telecommunications utility; however, if it is responsible for any unreasonable
delays in the execution of telecommunications utility changes or for the execution
of unauthorized telecommunications utility changes, including fraudulent authorizations.
(4)
Submitting telecommunications utility - Any telecommunications
utility that requests on behalf of a customer that the customer's preferred
telecommunications utility be changed.
(5)
Unauthorized telecommunications utility - Any telecommunications
utility that submits a change request that is not in accordance with the requirements
of this section.
(c)
Changes in preferred telecommunications utility.
(1)
Changes by a telecommunications utility. Before a change
order is processed, the submitting telecommunications utility must obtain
verification from the customer that such change is desired for each affected
telephone line(s) and ensure that such verification is obtained in accordance
with 47 C.F.R. §64.1120. In the case of a change by written solicitation,
the submitting telecommunications utility must obtain verification as specified
in 47 C.F.R. §64.1130, and subsection (d) of this section, relating to
Letters of Agency. The submitting telecommunications utility shall submit
a change order within 60 days after obtaining verification from the customer.
The submitting telecommunications utility must maintain records of all changes,
including verifications, for a period of 24 months and shall provide such
records to the customer, if the customer challenges the change, and to the
Public Utility Commission (commission) staff upon request. A change order
must be verified by one of the following methods:
(A)
Written or electronically signed authorization from the
customer in a form that meets the requirements of subsection (d) of this section.
A customer shall be provided the option of using another authorization method
in lieu of an electronically signed authorization.
(B)
Electronic authorization placed from the telephone number
which is the subject of the change order except in exchanges where automatic
recording of the automatic number identification (ANI) from the local switching
system is not technically possible. The submitting telecommunications utility
must:
(i)
ensure that the electronic authorization confirms the information
described in subsection (d)(3) of this section; and
(ii)
establish one or more toll-free telephone numbers exclusively
for the purpose of verifying the change so that a customer calling toll-free
number(s) will reach a voice response unit or similar mechanism that records
the required information regarding the change and automatically records the
ANI from the local switching system.
(C)
Oral authorization by the customer for the change that
meets the following requirements:
(i)
The customer's authorization shall be given to an appropriately
qualified and independent third party that confirms appropriate verification
data such as the customer's date of birth or mother's maiden name.
(ii)
The verification must be electronically recorded in its
entirety on audio tape, a wave sound file, or other recording device that
is compatible with the commission's equipment.
(iii)
The recording shall include clear and conspicuous confirmation
that the customer authorized the change in telephone service provider.
(iv)
The third party verification shall elicit, at minimum,
the identity of the customer, confirmation that the person on the call is
authorized to make the change in service, the names of the telecommunications
utilities affected by the change, the telephone number(s) to be switched,
and the type of service involved.
(v)
The third party verification shall be conducted in the
same language used in the sales transaction.
(vi)
Automated systems shall provide customers the option of
speaking with a live person at any time during the call.
(vii)
A telecommunications utility or its sales representative
initiating a three-way call or a call through an automated verification system
shall drop off the call once a three-way connection has been established.
(viii)
The independent third party shall:
(I)
not be owned, managed, or directly controlled by the telecommunications
utility or the telecommunications utility's marketing agent;
(II)
not have financial incentive to confirm change orders;
and
(III)
operate in a location physically separate from the telecommunications
utility or the telecommunications utility's marketing agent.
(2)
Changes by customer request directly to the local exchange
company. If a customer requests a change in preferred telecommunications utility
by contacting the local exchange company directly and the local exchange company
is not the chosen carrier or affiliate of the chosen carrier, the verification
requirements in paragraph (1) of this subsection do not apply. The local exchange
company shall maintain a record of the customer's request for 24 months.
(d)
Letters of Agency (LOA). A written or electronically signed
authorization from a customer for a change of telecommunications utility shall
use a letter of agency (LOA) as specified in this subsection:
(1)
The LOA shall be a separate or easily separable document
or located on a separate screen or webpage containing only the authorizing
language described in paragraph (3) of this subsection for the sole purpose
of authorizing the telecommunications utility to initiate a telecommunications
utility change. The LOA must be signed and dated by the customer requesting
the telecommunications utility change. An LOA submitted with an electronically
signed authorization shall include the consumer disclosures required by the
(2)
The LOA shall not be combined with inducements of any kind
on the same document, screen, or webpage except that the LOA may be combined
with a check as specified in subparagraphs (A) and (B) of this paragraph:
(A)
An LOA combined with a check may contain only the language
set out in paragraph (3) of this subsection, and the necessary information
to make the check a negotiable instrument.
(B)
A check combined with an LOA shall not contain any promotional
language or material but shall contain on the front and back of the check
in easily readable, bold-faced type near the signature line, a notice similar
in content to the following: "By signing this check, I am authorizing (name
of the telecommunications utility) to be my new telephone service provider
for (the type of service that will be provided)."
(3)
LOA language.
(A)
At a minimum, the LOA shall be printed with sufficient
size and readable type to be clearly legible and shall contain clear and unambiguous
language that confirms:
(i)
the customer's billing name and address and each telephone
number to be covered by the preferred telecommunications utility change order;
(ii)
the decision to change preferred carrier from the current
telecommunications utility to the new telecommunications utility and identifies
each;
(iii)
that the customer designates (name of the new telecommunications
utility) to act as the customer's agent for the preferred carrier change;
(iv)
that the customer understands that only one preferred
telecommunications utility may be designated for each type of service (local,
intraLATA, and interLATA) for each telephone number. The LOA shall contain
separate statements regarding those choices, although a separate LOA for each
service is not required; and
(v)
that the customer understands that any preferred carrier
selection the customer chooses may involve a one-time charge to the customer
for changing the customer's preferred telecommunications utility and that
the customer may consult with the carrier as to whether a fee applies to the
change.
(B)
The following LOA form meets the requirements of this subsection.
Other versions may be used, but shall comply with all of the requirements
of this subsection.
Figure: 16 TAC §26.130(d)(3)(B)
(4)
The LOA shall not require that a customer take some action
in order to retain the customer's current telecommunications utility.
(5)
If any portion of an LOA is translated into another language,
then all portions must be translated. The LOA must be translated into the
same language as promotional materials, oral descriptions or instructions
provided with the LOA.
(e)
Notification of alleged unauthorized change.
(1)
When a customer informs an executing telecommunications
utility of an alleged unauthorized telecommunications utility change, the
executing telecommunications utility shall immediately notify both the authorized
and alleged unauthorized telecommunications utility of the incident.
(2)
Any telecommunications utility, executing, authorized,
or alleged unauthorized, that is informed of an alleged unauthorized telecommunications
utility change shall direct the customer to contact the Public Utility Commission
of Texas.
(3)
The alleged unauthorized telecommunications utility shall
remove all unpaid charges pending a determination of whether an unauthorized
change occurred.
(4)
The alleged unauthorized telecommunications utility may
challenge a complainant's allegation of an unauthorized change by notifying
the complainant to file a complaint with the Public Utility Commission of
Texas within 30 days. If the complainant does not file a complaint within
30 days, the unpaid charges may be reinstated.
(5)
The alleged unauthorized telecommunications utility shall
take all actions within its control to facilitate the customer's prompt return
to the original telecommunication utility within three business days of the
customer's request.
(6)
The alleged unauthorized telecommunications utility shall
also be liable to the customer for any charges assessed to change the customer
from the authorized telecommunications utility to the alleged unauthorized
telecommunications utility in addition to charges assessed for returning the
customer to the authorized telecommunications utility.
(f)
Unauthorized changes.
(1)
Responsibilities of the telecommunications utility that
initiated the change. If a customer's telecommunications utility is changed
without verification consistent with this section, the telecommunications
utility that initiated the unauthorized change shall:
(A)
take all actions within its control to facilitate the customer's
prompt return to the original telecommunication utility within three business
days of the customer's request;
(B)
pay all charges associated with returning the customer
to the original telecommunications utility within five business days of the
customer's request;
(C)
provide all billing records to the original telecommunications
utility related to the unauthorized change of services within ten business
days of the customer's request;
(D)
pay the original telecommunications utility any amount
paid to it by the customer that would have been paid to the original telecommunications
utility if the unauthorized change had not occurred, within 30 business days
of the customer's request;
(E)
return to the customer within 30 business days of the customer's
request:
(i)
any amount paid by the customer for charges incurred during
the first 30 days after the date of an unauthorized change; and
(ii)
any amount paid by the customer after the first 30 days
in excess of the charges that would have been charged if the unauthorized
change had not occurred; and
(F)
remove all unpaid charges.
(2)
Responsibilities of the original telecommunications utility.
The original telecommunications utility shall:
(A)
inform the telecommunications utility that initiated the
unauthorized change of the amount that would have been charged for identical
services if the unauthorized change had not occurred, within ten business
days of the receipt of the billing records required under paragraph (1)(C)
of this subsection;
(B)
where possible, provide to the customer all benefits associated
with the service, such as frequent flyer miles that would have been awarded
had the unauthorized change not occurred, on receiving payment for service
provided during the unauthorized change;
(C)
maintain a record of customers that experienced an unauthorized
change in telecommunications utilities that contains:
(i)
the name of the telecommunications utility that initiated
the unauthorized change;
(ii)
the telephone number(s) affected by the unauthorized change;
(iii)
the date the customer asked the telecommunications utility
that made the unauthorized change to return the customer to the original telecommunications
utility; and
(iv)
the date the customer was returned to the original telecommunications
utility; and
(D)
not bill the customer for any charges incurred during the
first 30 days after the unauthorized change, but may bill the customer for
unpaid charges incurred after the first 30 days based on what it would have
charged if the unauthorized change had not occurred.
(g)
Notice of customer rights.
(1)
Each telecommunications utility shall make available to
its customers the notice set out in paragraph (3) of this subsection.
(2)
Each notice provided under paragraph (5)(A) of this subsection
shall contain the name, address and telephone numbers where a customer can
contact the telecommunications utility.
(3)
Customer notice. The notice shall state:
Figure: 16 TAC §26.130(g)(3) (No change.)
(4)
The customer notice requirements in paragraph (3) of this
subsection may be combined with the notice requirements of §26.32(g)(1)
and (2) of this title (relating to Protection Against Unauthorized Billing
Charges ("Cramming")) if all of the information required by each is in the
combined notice.
(5)
Language, distribution and timing of notice.
(A)
Telecommunications utilities shall send the notice to new
customers at the time service is initiated, and upon customer request.
(B)
Each telecommunications utility shall print the notice
in the white pages of its telephone directories, beginning with any directories
published 30 days after the effective date of this section and thereafter.
The notice that appears in the directory is not required to list the information
contained in paragraph (2) of this subsection.
(C)
The notice shall be in both English and Spanish as necessary
to adequately inform the customer. The commission may exempt a telecommunications
utility from the Spanish requirement if the telecommunications utility shows
that 10% or fewer of its customers are exclusively Spanish- speaking, and
that the telecommunications utility will notify all customers through a statement
in both English and Spanish that the information is available in Spanish by
mail from the telecommunications utility or at the utility's offices.
(h)
Compliance and enforcement.
(1)
Records of customer verifications and unauthorized changes.
A telecommunications utility shall provide a copy of records maintained under
the requirements of subsections (c), (d), and (f)(2)(C) of this section to
the commission staff upon request.
(2)
Administrative penalties. If the commission finds that
a telecommunications utility is in violation of this section, the commission
shall order the utility to take corrective action as necessary, and the utility
may be subject to administrative penalties pursuant to the Public Utility
Regulatory Act (PURA) §15.023 and §15.024.
(3)
Certificate revocation. If the commission finds that a
telecommunications utility is repeatedly and recklessly in violation of this
section, and if consistent with the public interest, the commission may suspend,
restrict, deny, or revoke the registration or certificate, including an amended
certificate, of the telecommunications utility, thereby denying the telecommunications
utility the right to provide service in this state.
(4)
Coordination with the office of the attorney general. The
commission shall coordinate its enforcement efforts regarding the prosecution
of fraudulent, misleading, deceptive, and anticompetitive business practices
with the office of the attorney general in order to ensure consistent treatment
of specific alleged violations.
(i)
Notice of identity of a customer's telecommunications utility.
Any bill for telecommunications services must contain the following information
in easily-read, bold type in each bill sent to a customer. Where charges for
multiple lines are included in a single bill, this information must appear
on the first page of the bill if possible or displayed prominently elsewhere
in the bill:
(1)
The name and telephone number of the telecommunications
utility providing local exchange service if the bill is for local exchange
service.
(2)
The name and telephone number of the primary interexchange
carrier if the bill is for interexchange service.
(3)
The name and telephone number of the local exchange and
interexchange providers if the local exchange provider is billing for the
interexchange carrier. The commission may, for good cause, waive this requirement
in exchanges served by incumbent local exchange companies serving 31,000 access
lines or less.
(4)
A statement that customers who believe they have been slammed
may contact the Public Utility Commission of Texas, P.O. Box 13326, Austin,
Texas 78711-3326, (512) 936-7120 or in Texas (toll-free) 1 (888) 782-8477,
fax: (512) 936-7003, e- mail address: customer@puc.state.tx.us. Hearing and
speech-impaired individuals with text telephones (TTY) may contact the commission
at (512) 936- 7136. This statement may be combined with the statement requirements
of §26.32(g)(4) of this title if all of the information required by each
is in the combined statement.
(j)
Preferred telecommunications utility freezes.
(1)
Purpose. A preferred telecommunications utility freeze
("freeze") prevents a change in a customer's preferred telecommunications
utility selection unless the customer gives consent to the local exchange
company that implemented the freeze.
(2)
Nondiscrimination. All local exchange companies that offer
freezes shall offer freezes on a nondiscriminatory basis to all customers
regardless of the customer's telecommunications utility selection except for
local telephone service.
(3)
Type of service. Customer information on freezes shall
clearly distinguish between intraLATA and interLATA telecommunications services.
The local exchange company offering a freeze shall obtain separate authorization
for each service for which a freeze is requested.
(4)
Freeze information. All information provided by a telecommunications
utility about freezes shall have the sole purpose of educating customers and
providing information in a neutral way to allow the customer to make an informed
decision, and shall not market or induce the customer to request a freeze.
The freeze information provided to customers shall include:
(A)
a clear, neutral explanation of what a freeze is and what
services are subject to a freeze;
(B)
instructions on lifting a freeze that make it clear that
these steps are in addition to required verification for a change in preferred
telecommunications utility;
(C)
an explanation that the customer will be unable to make
a change in telecommunications utility selection unless the customer lifts
the freeze; and
(D)
a statement that there is no charge to the customer to
impose or lift a freeze.
(5)
Freeze verification. A local exchange company shall not
implement a freeze unless the customer's request is verified using one of
the following procedures:
(A)
A written and signed or electronically signed authorization
that meets the requirements of paragraph (6) of this subsection.
(B)
An electronic authorization placed from the telephone number
on which a freeze is to be imposed. The electronic authorization shall confirm
appropriate verification data such as the customer's date of birth or mother's
maiden name and the information required in paragraph (6)(G) of this subsection.
The local exchange company shall establish one or more toll-free telephone
numbers exclusively for this purpose. Calls to the number(s) will connect
the customer to a voice response unit or similar mechanism that records the
information including the originating ANI.
(C)
An appropriately qualified independent third party obtains
the customer's oral authorization to submit the freeze and confirms appropriate
verification data such as the customer's date of birth or mother's maiden
name and the information required in paragraph (6)(G) of this subsection.
This shall include clear and conspicuous confirmation that the customer authorized
a freeze. The independent third party shall:
(i)
not be owned, managed, or directly controlled by the local
exchange company or the local exchange company's marketing agent;
(ii)
not have financial incentive to confirm freeze requests;
and
(iii)
operate in a location physically separate from the local
exchange company or its marketing agent.
(D)
Any other method approved by Federal Communications Commission
rule or order granting a waiver.
(6)
Written authorization. A written freeze authorization shall:
(A)
be a separate or easily separable document with the sole
purpose of imposing a freeze;
(B)
be signed and dated by the customer;
(C)
not be combined with inducements of any kind;
(D)
be completely translated into another language if any portion
is translated;
(E)
be translated into the same language as any educational
materials, oral descriptions, or instructions provided with the written freeze
authorization;
(F)
be printed with readable type of sufficient size to be
clearly legible; and
(G)
contain clear and unambiguous language that confirms:
(i)
the customer's name, address, and telephone number(s) to
be covered by the freeze;
(ii)
the decision to impose a freeze on the telephone number(s)
and the particular service with a separate statement for each service to be
frozen;
(iii)
that the customer understands that a change in telecommunications
utility cannot be made unless the customer lifts the freeze; and
(iv)
that the customer understands that there is no charge
for imposing or lifting a freeze.
(7)
Lifting freezes. A local exchange company that executes
a freeze request shall allow customers to lift a freeze by:
(A)
written and signed or electronically signed authorization
stating the customer's intent to lift a freeze;
(B)
oral authorization stating an intent to lift a freeze confirmed
by the local exchange company with appropriate confirmation verification data
such as the customer's date of birth or mother's maiden name;
(C)
a three-way conference call with the local exchange company,
the telecommunications utility that will provide the service, and the customer;
or
(D)
any other method approved by Federal Communications Commission
rule or order granting a waiver.
(8)
No customer charge. The customer shall not be charged for
imposing or lifting a freeze.
(9)
Local service freeze prohibition. A local exchange company
shall not impose a freeze on local telephone service.
(10)
Marketing prohibition. A local exchange company shall
not initiate any marketing of its services during the process of implementing
or lifting a freeze.
(11)
Freeze records retention. A local exchange company shall
maintain records of all freezes and verifications for a period of 24 months
and shall provide these records to customers and to the commission staff upon
request.
(12)
Suggested freeze information language. Telecommunications
utilities that inform customers about freezes may use the following language.
Other versions may be used, but shall comply with all of the requirements
of paragraph (4) of this subsection.
Figure: 16 TAC §26.130(j)(12) (No change.)
(13)
Suggested freeze authorization form. The following form
is recommended for written authorization from a customer requesting a freeze.
Other versions may be used, but shall comply with all of the requirements
of paragraph (6) of this subsection.
Figure: 16 TAC §26.130(j)(13) (No change.)
(14)
Suggested freeze lift form. The following form is recommended
for written authorization to lift a freeze. Other versions may be used, but
shall comply with all of the requirements of paragraph (7) of this subsection.
Figure: 16 TAC §26.130(j)(14) (No change.)
(k)
Transferring customers from one telecommunications utility
to another.
(1)
Any telecommunications utility that will acquire customers
from another telecommunications utility that will no longer provide service
due to acquisition, merger, bankruptcy or any other reason, shall provide
notice to every affected customer. The notice shall be in a billing insert
or separate mailing at least 30 days prior to the transfer of any customer.
If legal or regulatory constraints prevent sending the notice at least 30
days prior to the transfer, the notice shall be sent promptly after all legal
and regulatory conditions are met. The notice shall:
(A)
identify the current and acquiring telecommunications utilities;
(B)
explain why the customer will not be able to remain with
the current telecommunications utility;
(C)
explain that the customer has a choice of selecting a service
provider and may select the acquiring telecommunications utility or any other
telecommunications utility and that the customer may incur a charge if the
customer selects another telecommunications utility;
(D)
explain that if the customer wants another telecommunications
utility, the customer should contact that telecommunication utility or the
local telephone company;
(E)
explain the time frame for the customer to make a selection
and what will happen if the customer makes no selection;
(F)
identify the effective date that customers will be transferred
to the acquiring telecommunications utility;
(G)
provide the rates and conditions of service of the acquiring
telecommunications utility and how the customer will be notified of any changes;
(H)
explain that the customer will not incur any charges associated
with the transfer;
(I)
explain whether the acquiring carrier will be responsible
for handling complaints against the transferring carrier; and
(J)
provide a toll-free telephone number for a customer to
call for additional information.
(2)
The acquiring telecommunications utility shall provide
the Customer Protection Division (CPD) with a copy of the notice when it is
sent to customers.
(l)
Complaints to the commission. A customer may file a complaint
with the commission's Customer Protection Division against a telecommunications
utility for any reasons related to the provisions of this section.
(1)
Customer complaint information. CPD shall request the following
information:
(A)
the customer's name, address, and telephone number;
(B)
a brief description of the facts of the complaint;
(C)
a copy of the customer's and spouse's legal signature;
and
(D)
a copy of the most recent phone bill and any prior phone
bill that shows the switch in carrier.
(2)
Telecommunications utility's response to complaint. After
review of a customer's complaint, CPD shall forward the complaint to the telecommunications
utility. The telecommunications utility shall respond to CPD within 21 calendar
days after CPD forwards the complaint. The telecommunications utility's response
shall include the following:
(A)
all documentation related to the authorization and verification
used to switch the customer's service; and
(B)
all corrective actions taken as required by subsection
(f) of this section, if the switch in service was not verified in accordance
with subsections (c) and (d) of this section.
(3)
CPD investigation. CPD shall review all of the information
related to the complaint and make a determination on whether or not the telecommunications
utility complied with the requirements of this section. CPD shall inform the
complainant and the alleged unauthorized telecommunications utility of the
results of the investigation and identify any additional corrective actions
that may be required. CPD shall also inform the authorized telecommunications
utility if there was an unauthorized change in service.
(m)
Reporting requirement. Each telecommunications utility
shall file a semiannual slamming report with the commission's Central Records
in the assigned project number as required by paragraphs (1) and (2) of this
subsection. A project number will be assigned each calendar year for this
report.
(1)
The report shall use the format and information required
by 47 C.F.R. §64.1180 containing only Texas-specific data.
(2)
Reports shall be submitted on August 31 (covering January
1 through June 30) and February 28 (covering July 1 through December 31).
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 June 19, 2002.
TRD-200203841
Rhonda G. Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: July 9, 2002
Proposal publication date: February 15, 2002
For further information, please call: (512) 936-7308
Chapter 103.
GENERAL RULES
16 TAC §103.3
The Texas Motor Vehicle Board adopts amendments to §103.3,
Amended License, with changes to the text published in the March 1, 2002 issue
of the
Texas Register
(27 TexReg 1420).
The amendments describe the procedure for a new motor vehicle dealer to
seek an amendment or new license when the dealer changes the form of its business
entity. The amendments also describe the conditions under which the new entity
is required to submit a new franchise agreement. Board members expressed concern
that the language as proposed for 16 TAC §103.3(d) would allow an entity
to change the ownership of the dealership, as well as the business form, without
submitting a new franchise agreement. To address this concern, the Board added
further language to clarify that subsection (d) does not apply to a dealer
who changes ownership of the original entity seeking to convert.
Section 103.3 is amended by adding subsections (d) and (e). Section 103.3(d)
permits a franchised motor vehicle dealer who changes or converts its business
entity from one business form to another business form to do business as the
new entity under the terms of the dealer's existing franchise agreement until
the parties mutually elect to replace that agreement. Section 103.3(e) permits
a franchised motor vehicle dealer who converts its legal entity from one business
form to another business form under state or federal law to file an amendment
to its current license to reflect the entity change, rather than file a new
application in the name of a new entity. The franchise agreement that applied
to the first business entity survives the conversion, and will apply to the
successor entity. A franchised dealer who changes its business entity using
a method other than a conversion allowed under state or federal law must file
a new application in the successor entity's name.
The amendments will prevent manufacturers or distributors from using a
dealership's change of corporate form as a mechanism to require that dealer
to sign a new franchise agreement with less favorable terms. Additionally,
dealers seeking to convert their business entities will save time and money
by avoiding the process involved in reapplying for a new license.
Supporters believe the adoption of the amendments will benefit the public
by preventing manufacturers or distributors from using a dealership's change
of corporate form to require dealers to sign new franchise agreements or make
unwelcome changes to their dealerships in order to obtain the new franchise
agreement in the new name. They stated that dealers seeking to convert their
business entities will be able to save time and money by avoiding the process
involved in reapplying for a new license.
Proponents of the rule reported that it was common for dealers to wait
weeks or months for a manufacturer or distributor to process changes to franchise
agreements to allow them to complete the corporate reformation process. They
explained that the purpose of the rule was not to allow converted entities
to avoid obtaining new franchise agreements in the new entity's name, but
to expedite the licensing process. Proponents emphasized that the rule will
allow the business entity change to occur without holding up the licensing
process, or the dealership's ability to conduct business pending the change
in corporate form.
Written comments in support of the amendments were received from the Texas
Automobile Dealers Association (TADA), and William David Coffey III, attorney
at law. The Board also heard oral comment in favor of the proposed amendments
from Karen Coffey of TADA, and William R. Crocker, attorney at law. All comments
received by the Board supported the amendments to 16 TAC §103.3.
The Board is authorized to adopt the proposed amendments and
new rules by §3.06 of the Texas Motor Vehicle Commission Code, Article
4413(36) and (36a), Texas Revised Civil Statutes, which provides the Board
with the authority to adopt rules necessary and convenient to effectuate the
provisions of the Code and to govern practice and procedure before the agency.
§103.3.Amended License.
(a)
To effectuate the Texas Motor Vehicle Commission Code, §4.02(d),
every licensed dealer who proposes to conduct business under a franchise which
is additional to or which differs from the franchise or franchises on which
the license is then based shall file an application to amend the license on
the form prescribed by the commission, attaching a copy of the franchise agreement.
The amended application will be considered as if it were an original application
to operate under the additional franchise as to all matters except those reflected
by the license as issued.
(b)
Every licensed dealer who proposes to sell and/or assign
to another an interest equivalent to 10% or more in one or more franchises
on which the license is then based or an equivalent interest in the business
of the dealership, whether the same is a corporation, partnership, sole proprietorship,
or otherwise, shall file an application to amend the license providing the
requested information as to the proposed assignee. If the interest involved
exceeds 50%, the amended license may be issued in the name of such assignee.
(c)
In the event of a change in management reflected by a change
of the general manager or other person who is in charge of a licensee's business
activities, whether a managing partner, officer, or director of a corporation,
or otherwise, the commission shall be advised by means of an application for
an amended license.
(d)
If a licensed new motor vehicle dealer changes or converts
from one type of business entity to another without changing ownership of
the dealership, the submission of a franchise agreement in the name of the
new entity is not required in conjunction with an application. The franchise
agreement on file with the Board prior to the change or conversion of the
dealer's business entity applies to the successor entity until the parties
agree to replace the franchise agreement.
(e)
If a dealer adopts a plan of conversion under a state or
federal law that allows one legal entity to be converted into another legal
entity, only an application to amend the license is necessary to be filed
with the Board. The franchise agreement on file with the Board continues to
apply to the converted entity. If the entity change is accomplished by any
means other than conversion, a new application is required, subject to subsection
(d) of this section.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of
the Secretary of State on June 21, 2002.
TRD-200203887
Brett Bray
Director
Texas Motor Vehicle Board
Effective date: July 11, 2002
Proposal publication date: March 1, 2002
For further information, please call: (512) 416-4899
16 TAC §105.10
The Texas Motor Vehicle Board of the Texas Department of
Transportation adopts amendments to 16 TAC §105.10(a), (c)(1), (c)(2)
and(c)(3), as published in the March 1, 2002 issue of the
Texas Register
(27 TexReg 1421). Sections 105.10(c)(1), (c)(2), (c)(3)
are adopted without changes. Section 105.10(a) is adopted with changes.
Explanation of Amendments.
Amendments to §105.10(c)(1), (c)(2) and (c)(3) correct typographical
errors. The amendments to §105.10(c)(1) - (c)(3) change "sess price"
to "sales price". Additional amendments to Figure §105.10(c)(2) correctly
show that a rebate must be subtracted from the advertised price.
Section 105.10(a), as adopted by the Motor Vehicle Board, using "the price",
rather than "a price" prohibits dealers from refusing to sell motor vehicles
at the price advertised, and brings the Board's advertising rules into agreement
with the Texas Finance Code and Federal Regulation Z, which prohibit adding
negative equity to the cash price in a retail installment contract. Changes
to the proposal make it clear that requiring dealers to sell vehicles at the
price advertised does not prevent a higher price from being negotiated if
a consumer chooses to purchase options that are not part of the advertised
vehicle. The public benefit anticipated from the amendments will be stronger
protection of the public and dealers from those dealers who engage in false,
deceptive or misleading practices, as well as better understanding by licensees
required to comply with the rules.
Prior to amendments in 2000, §105.10(a) read as follows: "The featured
sale price of a new or used motor vehicle, when advertised, must be
The Motor Vehicle Board then proposed amending §105.10 (a) to read
"the highest price." Recognizing industry concerns, alternative language was
offered in the preamble of the proposal to make it clear that a dealer must
be willing to sell a vehicle at the advertised price to any retail customer,
and that negotiations that might raise or lower the advertised price are permissible.
(27 TexReg 1421, March 1, 2002).
On April 25, 2002, the Motor Vehicle Board adopted amendments to §105.10(a),
with changes to the proposed text. The effect of the changes is that the featured
advertised price must be the price that any retail buyer can buy the advertised
vehicle, and that the featured price of a vehicle does not include any additional
costs that might be incurred if a customer decides to add options. In short,
dealers may raise the price of a vehicle to accommodate the add-ons that consumers
choose. Furthermore, the Board noted that the purpose of the amended rule
is to protect consumers, and that nothing in the rule prevents a consumer
from negotiating a lower price from the advertised price.
Summary of Comments.
No written or oral comments were received concerning the amendments to §105.10(c)(1),
(c)(2) or (c)(3). Written comments in opposition the amendments to §105.10(a)
were received from the Texas Automobile Dealers Association and Mr. William
David Coffey, III, Attorney at Law. At the public hearing on April 25, 2002,
comments in opposition were received from Ms. Karen Coffey of the Texas Automobile
Dealers Association, Mr. Gene Brady of the Greater Houston Motorcycle Dealers
Association, and Mr. William David Coffey, III, Attorney at Law. Commenting
on the proposal was Ms. Leslie Pettijohn, Consumer Credit Commissioner. Introducing
the rule and explaining staff support for the alternative language was Ms.
Carol Kent, Motor Vehicle Division (MVD)Enforcement Director.
Opponents argued that replacing the indefinite article "a" with the definite
article "the" would prevent dealerships and consumers from negotiating a higher
price from the advertised price if the consumer wished to add options to a
vehicle. They stated that the amendment amounted to over-regulation because
current law already prohibits bait and switch advertising.
MVD staff explained that the proposed amendments would make §105.10(a)
consistent with §105.6 that states that "All advertised statement shall
be accurate, clear, and conspicuous." The proposal would not prevent a dealer
and a consumer from negotiating a lower price from the advertised price, or
a higher price from advertised price if the consumer chooses to add options.
However, if the rule allowed dealers to advertise "a price", then dealers
were free not to adhere to their advertisements when negotiating with consumers.
Ms. Pettijohn explained that using "a price" would not prevent dealers from
adding negative equity to the cash price in a retail installment contract,
in violation of the Finance Code.
Reasons for Disagreement with Party Submissions or Proposals.
The Board concluded that because a dealer and consumer are free to negotiate
a higher price if options are added, including the word "highest" in the amendment
was unnecessary. The Board weighed the option of altogether eliminating §105.10(a);
however, that course of action was rejected as not providing the consumers
of the State adequate protection. The Board ultimately adopted language incorporating
"the price" to address consumer concerns, as well as language to make it clear
that requiring dealers to sell vehicles at the price advertised does not prevent
a higher price from being negotiated if a consumer chooses to purchase options
that are not part of the advertised vehicle.
Statutory Authority.
The Board is authorized to adopt the amendments by §3.06 of the Texas
Motor Vehicle Commission Code, Article 4413(36) and (36a), Texas Revised Civil
Statutes, which provides the Board with the authority to adopt rules necessary
and convenient to effectuate the provisions of the Code and to govern practice
and procedure before the agency.
§105.10.Dealer Price Advertising.
(a)
When featuring an advertised sale price of a new or used
motor vehicle, the dealer must be willing to sell the vehicle for such advertised
price to any retail buyer. The advertised sale price shall be the price before
the addition or subtraction of any other negotiated items. The only charges
that may be excluded from the advertised price are:
(1)
any registration, certificate of title, license fees, or
an additional registration fee, if any, charged by a full service deputy as
provided by County Road and Bridge Act, §4.202(g);
(2)
any taxes; and
(3)
any other fees or charges that are allowed or prescribed
by law.
(b)
A qualification may not be used when advertising the price
of a vehicle such as "with trade," "with acceptable trade," "with dealer-arranged
financing," "rebate assigned to dealer," or "with down payment."
(c)
If a price advertisement discloses a rebate cash back or
discount savings claim, the price of the vehicle must be disclosed as well
as the price of the vehicle after deducting the incentive.
(1)
If an advertisement discloses a discount savings claim,
this incentive must be disclosed as a deduction from the manufacturer's suggested
retail price (MSRP). The following is an acceptable format for advertising
a price with a discount savings claim.
Figure: 16 TAC §105.10(c)(1)
(2)
If an advertisement discloses a rebate, this incentive
must be disclosed as a deduction from the advertised price. The following
is an acceptable format for advertising a price with a rebate.
Figure: 16 TAC §105.10(c)(2)
(3)
If an advertisement discloses both a rebate and a discount
savings claim, the incentives must be disclosed as a deduction from the manufacturer's
suggested retail price (MSRP). The following is an acceptable format for advertising
a price with a rebate and a discount savings claim.
Figure: 16 TAC §105.10(c)(3)
(d)
In the event that the manufacturer offers a discount on
a package of options then that discount should be disclosed above or prior
to the manufacturer's suggested retail price (MSRP) with a total price of
the vehicle before option discounts. The following is an acceptable format.
Figure: 16 TAC §105.10(d) (No change.)
(e)
If a rebate is only available to a selected portion of
the public and not the public as a whole, the price should be disclosed as
in subsection (c) of this section first and then the nature of the limitation
and the amount of the limited rebate may be disclosed. The following is an
acceptable format.
Figure: 16 TAC §105.10(e) (No change.)
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 June 21, 2002.
TRD-200203888
Brett Bray
Director
Texas Motor Vehicle Board
Effective date: July 11, 2002
Proposal publication date: March 1, 2002
For further information, please call: (512) 416-4899
Subchapter O. UNBUNDLING AND MARKET POWER
Chapter 26.
SUBSTANTIVE RULES APPLICABLE TO TELECOMMUNICATIONS SERVICE PROVIDERS
Part 6.
TEXAS MOTOR VEHICLE BOARD
Chapter 105.
ADVERTISING
Chapter 111.
GENERAL DISTINGUISHING NUMBERS