Part II.
Public Utility Commission of Texas
Chapter 23.
Substantive Rules
Subchapter B. Records and Reports
16 TAC §23.18
The Public Utility Commission of Texas adopts the repeal
of §23.18, relating to Foreign Utility Company Ownership by Exempt Holding
Companies with no changes to the proposed text as published in the November
20, 1998, issue of the
Texas Register
(23
TexReg 11758). The repeal is necessary to avoid duplicative rule sections.
The commission has adopted §25.271 of this title (relating to Foreign
Utility Company Ownership of Exempt Holding Companies) to replace §23.18.
This repeal is adopted under Project Number 17709.
The commission received no comments on the proposed repeal.
This repeal is adopted under the Public Utility Regulatory Act,
Texas Utilities Code Annotated §14.002 (Vernon 1998) (PURA) which provides
the commission with the authority to make and enforce rules reasonably required
in the exercise of its powers and jurisdiction.
Cross-Index to Statutes: Public Utility Regulatory Act §14.002.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on March
26, 1999.
TRD-9901792
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: April 15, 1999
Proposal publication date: November 20, 1998
For further information, please call: (512) 936-7308
16 TAC §23.67, §23.70
The Public Utility Commission of Texas adopts the repeal
of §23.67 relating to Open-access Comparable Transmission Service, and
§23.70 relating to Terms and Conditions of Open-access Comparable Transmission
Service with no changes to the proposed text as published in the October 9,
1998, issue of the
Texas Register
(23 TexReg
10224). The repeal is necessary to avoid duplicative rule sections. The commission
has adopted §§25.191-25.198 and §§25.200-25.204 of this
title relating to Open-Access Comparable Transmission Service for Electric
Utilities in the Electric Reliability Council of Texas to replace §23.67
and §23.70. This repeal is adopted under Project Number 18703.
The commission received no comments on the proposed repeal.
This repeal is adopted under the Public Utility Regulatory Act,
Texas Utilities Code Annotated §14.002 (Vernon 1998) (PURA) which provides
the commission with the authority to make and enforce rules reasonably required
in the exercise of its powers and jurisdiction.
Cross-Index to Statutes: Public Utility Regulatory Act §14.002.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on March
24, 1999.
TRD-9901751
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: April 13, 1999
Proposal publication date: October 9, 1998
For further information, please call: (512) 936-7308
16 TAC §23.69
The Public Utility Commission of Texas adopts the repeal
of §23.69, relating to Integrated Services Digital Network (ISDN) with
no changes to the proposed text as published in the December 4, 1998, issue
of the
Texas Register
(23 TexReg 12056). The
repeal is necessary to avoid duplicative rule sections. The commission has
adopted §26.142 of this title (relating to Integrated Services Digital
Network (ISDN)) to replace §23.69. This repeal is adopted under Project
Number 17709.
The commission received no comments on the proposed repeal.
This repeal is adopted under the Public Utility Regulatory Act,
Texas Utilities Code Annotated §14.002 (Vernon 1998) (PURA) which provides
the commission with the authority to make and enforce rules reasonably required
in the exercise of its powers and jurisdiction.
Cross Index to Statutes: Public Utility Regulatory Act §14.002.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on March
26, 1999.
TRD-9901796
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: April 15, 1999
Proposal publication date: December 4, 1998
For further information, please call: (512) 936-7308
16 TAC §23.92
The Public Utility Commission of Texas adopts the repeal
of §23.92, relating to Expanded Interconnection with no changes to the
proposed text as published in the December 11, 1998, issue of the
Texas Register
(23 TexReg 12573). The repeal is necessary to avoid
duplicative rule sections. The commission has adopted §26.271 of this
title (relating to Expanded Interconnection) to replace §23.92. This
repeal is adopted under Project Number 17709.
The commission received no comments on the proposed repeal.
This repeal is adopted under the Public Utility Regulatory Act,
Texas Utilities Code Annotated §14.002 (Vernon 1998) (PURA) which provides
the commission with the authority to make and enforce rules reasonably required
in the exercise of its powers and jurisdiction.
Cross Index to Statutes: Public Utility Regulatory Act §14.002.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on March
26, 1999.
TRD-9901794
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: April 15, 1999
Proposal publication date: December 11, 1998
For further information, please call: (512) 936-7308
Subchapter I. Transmission and Distribution
1.
Open-Access Comparable Transmission Service for Electric Utilities in the Electric Reliability Council of Texas
16 TAC §§25.191-25.198, 25.200-25.204
The Public Utility Commission of Texas (commission) adopts
new §§25.191- 25.198 and §§25.200-25.204, relating to
Open-Access Comparable Transmission Service for Electric Utilities in the
Electric Reliability Council of Texas with changes to the proposed text as
published in the October 9, 1998
Texas Register
(23 TexReg 10225). The rule is necessary to facilitate competition in the
sale of electricity at wholesale and to meet a statutory requirement to adopt
rules relating to transmission service.
This new section was adopted under Project Number 18703.
Executive summary
The Texas Public Utility Regulatory Act (PURA) was amended in 1995 in several
ways that were intended to foster competition in the electric industry at
the wholesale level. PURA includes a statement of legislative policy that
"the public interest requires that rules, policies, and principles be formulated
and applied to protect public interest in a more competitive (wholesale) marketplace"
and that the "development of a competitive wholesale electric market ... is
in the public interest." Codified at Texas Utilities Code, §31.001(c).
The amended Act authorizes exempt wholesale generators to operate in the wholesale
market in Texas. Texas Utilities Code, §35.002, §35.031. Finally,
PURA requires electric utilities to provide transmission service to other
utilities, exempt wholesale generators and qualifying facilities and directs
the commission to adopt rules relating to transmission access and pricing.
Texas Utilities Code, §35.004-35.006. The commission adopted transmission
rules in 1996.
The commission initiated an inquiry into the status of the wholesale market
in late 1997 and this rulemaking in early 1998. The purposes of the inquiry
and rulemaking included reviewing the effectiveness of the wholesale market
during the first two years that the transmission access rules had been in
effect. The commission concluded that following the adoption of the transmission
access rule trading of short-term energy, using unplanned transmission service,
was relatively vigorous. Such short-term energy trades represent instances
in which one utility was able to buy power from another at a lower cost than
the cost of producing the power itself, and both parties to such a trade benefit.
Customers also benefit, because the cost of producing power, which customers
ultimately bear, is reduced. One of the other conclusions that the commission
reached in its inquiry into the wholesale market was that there are still
a number of practices in the industry in which utilities are treated differently
from non-utility participants in the market.
The other significant benefit of the transmission access rules was that
wholesale buyers seeking longer-term resources had many more options for buying
power. They were no longer locked into purchasing from a utility with which
they had a direct transmission connection. Several small utilities were able
to take advantage of the new open-access rules, acquire power from new sources,
and dramatically reduce their cost of power.
During the period in which the transmission access rules were first effective,
the economy in Texas was strong, and the demand for electricity grew steadily.
As a result, new generation resources will be needed in Texas beginning in
1999. A number of companies recognized this growth in demand and made plans
to build new generating plants in Texas, particularly in the Electric Reliability
Council of Texas (ERCOT). Many of these companies were not affiliated with
any Texas utility and were planning to build the new generation plants, without
first lining up a buyer for the output from the plants. They were, in effect,
relying on demand in the market, rather than contractual commitments, as assurance
that they would recover their costs of construction and operation. In the
industry, plants of this type have been referred to as merchant plants. These
merchant plants are needed to meet the growing demand for electricity resulting
from the vibrant Texas economy.
Several issues emerged in 1999 concerning the process of planning merchant
generating plants and obtaining connections for them to the transmission network.
The transmission access rule approved in 1996 resulted in uncertainty as to
who would bear the costs of the new transmission facilities required for these
plants, and some of the developers of the merchant plants were concerned that
they might be required to pay for extensive and expensive new transmission
facilities in order to market the power from their plants. The other issue
with respect to the merchant plants was whether they were being treated fairly
by the transmission service provider with which they would interconnect. To
interconnect a new generation plant, a study of the adequacy of the transmission
facilities in the area where the plant will locate is necessary, and a determination
must be made of the new transmission facilities that are required. These studies
involve coordination between the merchant plant developer and the transmission
service provider and a diligent effort on the part of the transmission service
provider to complete the studies to meet the financing and construction needs
of the developer. In a few instances problems arose that suggested that a
transmission service provider had not dealt fairly with the developer of a
merchant plant.
The other issue that arose as a consequence of growth in demand was the
recovery by transmission service providers of the cost of new transmission
facilities. New transmission facilities will be needed to interconnect new
generation plants to the transmission network and provide them reasonable
access to major markets. The growth in demand has also resulted in increased
use of the transmission system and the emergence of bottlenecks or constraints
that did not exist at lower levels of demand. The ERCOT independent system
operator has initiated a process for identifying the transmission constraints
and planning projects to alleviate them. The alleviation of these constraints
will require additional transmission facilities, and the transmission service
providers have sought an expedited process for changing their transmission
rates to reflect the cost of additional facilities devoted to providing transmission
service.
This rulemaking grew out of the commission's inquiry into conditions in
the wholesale market and its recognition of the desirability of reviewing
the transmission access rule after it had been in effect for two years. The
major issues that emerged from this review were (1) greater comparability
in the treatment of utility and non-utility generators, (2) clear cost-responsibility
rules for new generators, (3) fair treatment for new generators in obtaining
interconnection with the transmission system, and (4) facilitating the recovery
of the costs of new transmission facilities. All of these issues are addressed
in these new sections.
Process for modifying the rules
The commission provided extensive opportunities for interested persons
to comment on the status of competition at wholesale and the need for amendments
to the existing transmission rules, both in connection with Project Number
17555, the commission's inquiry into the wholesale market, and this project.
The commission invited written comments and provided opportunities for oral
comments in workshops in Project Numbers 17555 and 18703. The following opportunities
for comment were provided: (1) The commission issued a survey in Project Number
17555 in July 1997, asking electric utilities about their experience relating
to the wholesale market, with responses filed in August and September, 1997.
(2) The commission conducted a workshop in Project Number 17555 in October
1997, at which interested persons commented. (3) The commission staff issued
a draft report on the wholesale market and requested comments from interested
persons, which were filed in March 1998. (4) A workshop with public comment
was held in July 1998 in Project Number 18703. (5) In July 1998 the commission
staff also conducted mediation efforts involving issues relating to the interconnection
of new generating plants in the Rio Grande Valley. Several meetings were held,
which were open to all interested persons. (6) The commission published the
proposed rule in Project Number 18703 in October 1998, and interested persons
filed comments and reply comments in November. (7) The commission conducted
a public meeting to take comments on the rule in December 1998 and deliberated
on the rule at open meetings in January and February 1999.
Sunset review of rules
The Appropriations Act of 1997, HB 1, Article IX, Section 167 (Section
167) requires that each state agency review and consider for readoption each
rule adopted by that agency pursuant to the Government Code, Chapter 2001
(Administrative Procedure Act). Such reviews shall include, at a minimum,
an assessment by the agency as to whether the reason for adopting the rule
continues to exist. The commission held three workshops to conduct a preliminary
review of its rules. As a result of these workshops, the commission is reorganizing
its current substantive rules located in 16 Texas Administrative Code (TAC)
Chapter 23 to (1) satisfy the requirements of Section 167; (2) repeal rules
no longer needed; (3) update existing rules to reflect changes in the industries
regulated by the commission; (4) reflect changes in law and commission organizational
structure and practices; (5) reorganize the rules into new chapters to facilitate
future amendments and provide room for expansion; and (6) reorganize the rules
according to the industry to which they apply. Chapter 25 has been established
for all commission substantive rules applicable to electric service providers.
The commission received comments on the proposed new sections from Tom
Acklen, Mike Alexander, American National Power (ANP), the City of Austin
(Austin), Mercer Black, Brazos Electric Power Cooperative (Brazos), the Public
Utilities Board of the City of Brownsville (Brownsville), Central Power &
Light Co. and West Texas Utilities Co. (collectively, CSW Companies), CITGO
Refining and Chemicals Co. (CITGO), Consumers Union, Consumer-Owned Power
Systems (consisting of a number of electric cooperatives), Corpus Christi
Power & Light and Power Choice Inc. (Power Choice), CSW Energy, Erin Curley,
Chris Dooley, Duke Energy Power Services (Duke), the Electric Reliability
Council of Texas (ERCOT), Independent ERCOT Market Participants (consisting
of several exempt wholesale generators and power marketers) (Independents),
ERCOT Market Participants (consisting of Dynegy Marketing and Trade, Dynegy
Power Services, Inc., and Enron Power Marketing, Inc.) (Wholesale Competitors),
O.B. Edmondson, Gay Erwin, Gulf Coast Power Connect (Power Connect), the City
of Garland and City of Denton Municipal Utilities (Garland), Abram Gordon,
Mike Gordon, the City of Granbury (Granbury), Andrew Gray, Janice Haddock,
Kathy Ikard, JoAnn Harrison, Houston Lighting & Power Company (HL&P),
Tom Huntress, Carolyn Keck, Koch Power Inc. (Koch), Bob Lewis, Litton PRC
(Litton), the Lower Colorado River Authority (LCRA), Jerry Martin, the meteorologists
in charge of the National Weather Service weather stations at Lubbock, Texas
and Shreveport, Louisiana, Mariann Morelock, Donna Nabers, Occidental Chemical
Corporation (OxyChem), the Office of Public Utility Counsel (Public Counsel),
Panda Paris Power, L.P. (Panda), Pedernales Electric Cooperative, Inc. (Pedernales),
Jeffery Perry, Cecil Rutherford, City Public Service Board of San Antonio
(San Antonio), Jack Scott, John Seelke and Richard Moore, Strategic Partnerships
Inc., South Texas Electric Cooperative (STEC), Texas Electric Cooperatives,
Inc. (Electric Cooperatives), Texas-New Mexico Power Company (TNMP), Texas
Industrial Energy Consumers (TIEC), Texas Utilities Electric Company (TU
Electric), U.S. Generating Company (USGen), the City of Weatherford (Weatherford),
and an unidentified commenter.
The commission requested specific comments on the Section 167 requirement
as to whether the reason for adopting or readopting the rules continues to
exist. The CSW Companies commented that the rules support a competitive wholesale
market, and, for this reason, the reasons for adopting the rules continue
to exist. No commenter opposed the readoption of the rules. The commission
finds that the reasons for adopting the rules continue to exist. The commission
is adopting these rules to carry out a statutory mandate to adopt rules relating
to wholesale transmission service, Texas Utilities Code 35.007.The commission
conducted an extensive rulemaking proceeding in 1995 and 1996 when it initially
adopted transmission rules, and most of the conclusions that it reached in
that proceeding still apply. The rule that is being adopted is consistent,
in many respects, with the rule adopted in 1996, and the commission incorporates
by reference the reasoned justification that was the basis for the adoption
of Substantive Rule §23.67 and §23.70. 21 TexReg 1397, 21 TexReg
3343. This rulemaking is important to the accomplishment of the Legislature's
policy objective of achieving wholesale competition, because the transmission
system which is used to deliver wholesale power is also owned by certain competitors
in the wholesale market. Detailed rules concerning access and pricing of transmission
service are necessary to ensure that access is readily available on non-discriminatory
terms. Wholesale competition in the electric utility industry is occurring
in the generation sector, but the provision of wholesale transmission service
currently remains a natural monopoly. Wholesale competition can produce the
expected benefits of lower electricity prices and higher quality service only
when the market allows participation by a maximum number of buyers and sellers
of generation services. Without a requirement for comparable use of the State's
transmission system by all wholesale market participants, which these rules
will provide, the Legislature's stated goal of promoting wholesale competition
will be frustrated.
A public hearing on the proposed sections was held at commission offices
on December 1, 1998 at 9:30 a.m. Mr. Richard Moore and representatives from
HL&P, STEC, Power Connect, TIEC, LCRA, Granbury, Garland and Pedernales,
Independents, and the CSW Companies attended the hearing and provided comments.
To the extent that these comments differ from the submitted written comments,
such comments are summarized herein.
The following parties supported the adoption of the new sections: ANP,
Independents, OxyChem, and Panda. The CSW Companies, HL&P, and TNMP, and
TIEC expressed support for the proposed rules in many respects, but pointed
out areas where they disagreed with the proposed rules or where they believed
that clarifications were needed. CSW Energy also expressed support for the
commission's objectives in proposing the rules, but pointed out provisions
it disagreed with. USGen supported the proposed rules but pointed out areas
where they could be enhanced.
Discussion of Comments on Specific Sections
Section 25.191: Transmission Service Requirements
Nature of transmission service
Garland requested that the language in §25.191(b) and (e)(2) be modified
to consistently refer to a transmission service customer rather than a "customer".
The CSW Companies noted that the reach of the commission's rules is limited
to those wholesale transactions and transmission facilities over which the
commission has jurisdiction. However, the CSW Companies noted that they would
continue to work toward implementing Federal Energy Regulatory Commission
(FERC) transmission tariffs for service within ERCOT that are consistent with
commission's principles for open access transmission service, to the extent
feasible. STEC supported uniform standards and procedures for interconnection
agreements and urged that each transmission provider should be required to
file an interconnection tariff with the commission for approval.
The commission has made the changes suggested by Garland. No revision to
the rules is needed in response to the comments of the CSW Companies. As the
CSW Companies noted in their comments, they have proposed tariffs that are
consistent with the commission rules and the FERC has accepted this arrangement
as consistent with its own rules on open-access transmission service. The
commission agrees with the comments of STEC and is including in the rules
a requirement for the development of a standard interconnection agreement.
Garland and TU Electric noted that "control area," for which a definition
is proposed in this section, is already defined in §25.5(8). San Antonio
stated that the rule should clarify by duration, the monthly, weekly, and
daily planned services. Independents proposed language to define eligible
transmission customers. The LCRA and STEC suggested that the commission clarify
task responsibility and use the term "load entity" or its "agent" or "generator,"
as appropriate. LCRA requested the commission to clarify the definition of
the transmission network. In addition, LCRA stated that facilities that provide
direct interconnection from the generating station to the network should be
defined to include an interrupting device on the high side of the generator
step-up transformer. TIEC submitted language to define direct interconnection
costs. TNMP noted that the current rule employs the concept but does not define
transmission facilities that provide a direct interconnection to the transmission
network. Furthermore, TNMP stated that the current rule should not attempt
to shift facilities that may be used to facilitate transmission access from
the transmission function to the generation function as this would only exacerbate
stranded generation costs.
Garland and TU Electric are correct that the term "control area" is defined
in §25.5(8). For this reason, the commission is deleting the definition
from §25.191. With respect to clarifying the terms of monthly, weekly,
and daily service, the independent system operator (ISO) is able to adopt
procedures that provide greater certainty to the terms of such services, based
on the commercial practices and input from affected persons. Additional clarification
in this rule is not warranted. The term "transmission system" is also defined
in §25.5, and a change to this definition is not necessary. The concept
"transmission facilities that provide a direct interconnection to the transmission
network" is not used in the rules being adopted, so a definition is not needed.
The commission also concludes that it is not necessary to distinguish between
a load-serving entity and other transmission customers. Rates for annual planned
service are based on characteristics of a load-serving entity, but other market
participants have a right to transmission service and to make arrangements
for planned service on behalf of a load-serving entity. The commission concludes
that using a generic term is more consistent with fostering a broad wholesale
competition.
Application
TIEC argued that while the commission does not have jurisdiction over the
transmission rates of non-ERCOT utilities, the commission should require that
all non- ERCOT utilities participate in regional independent system operators
or similar institutions.
This issue is beyond the scope of the rule. The commission favors conditions
that support vigorous wholesale competition in the non-ERCOT areas of Texas
and has sought legislation that would facilitate the introduction of ISOs
or similar organizations in the non-ERCOT areas of Texas.
Obligation to provide transmission service
ANP supported this section and suggested in §25.191(e)(2)(A) substituting
the phrase "for resale" for "at wholesale." USGen agreed with the commission's
view that a transmission owner has the obligation to interconnect new generators
and that the developer of a new generator is responsible only for costs associated
with direct connection.
The Public Utility Regulatory Act (PURA) uses the term "wholesale" in connection
with open-access transmission service. Wholesale is defined as a sale for
resale in the Federal Power Act, but the commission is developing the contours
of wholesale service in contested cases, and it is premature to attempt to
codify a definition in the rule. With respect to USGen's comments, the proposed
rule included an obligation to interconnect with a new generator, and this
requirement is being included in the rule as adopted.
Brazos and Independents supported §25.191(e)(2); according to Brazos,
this section would prohibit an integrated utility which provides service in
a dually certificated area from refusing to transmit wholesale power to another
utility that is certified to serve a retail customer. Adoption of the rule
would eliminate the argument by some integrated utilities that the other utility
seeking to serve a customer must have or construct distribution facilities
in order to receive wholesale power and resell that power at retail to the
customer. Public Counsel submitted reply comments arguing that competition
in multiply-certificated areas has existed for a long time and is permitted
under the Public Utility Regulatory Act, Texas Utilities Code Annotated §14.002
and §14.052 (Vernon 1998) (PURA). Therefore, this provision of the rule
would not initiate retail competition, but would make the existing competition
more efficient and effective. Power Choice submitted an analysis of the constitutional,
statutory and policy rationales that support the commission's proposed rule.
Article 1, §26 of the Texas Constitution prohibits monopolies, and Power
Choice asserted that the commission should do everything in its power to avoid
monopolies and to ameliorate conditions that have led to
de facto
monopolies. Furthermore, in terms of delegation of legislative
power over the delivery of electricity to both retail utilities and to the
ultimate consumer, PURA provides broad authority to the commission to require
a utility to offer service and to define the elements of that service, and
to enhance both wholesale competition and consumer welfare.
Garland, San Antonio, Austin, Consumer-Owned Power Systems, CSW Companies,
HL&P, Pedernales, Brownsville, STEC, Electric Cooperatives, TNMP, and
TU Electric strongly objected to this provision of the rule as mandating retail
wheeling. These parties asserted that that this section is in violation of
PURA, counter-productive (in view of the likelihood that the Legislature will
soon decide the retail wheeling issue), and will contribute to stranded investment.
Garland, and TU Electric argued that Brazos supported this section of the
rule based upon a questionable interpretation; that is, that §25.191(e)(2)(B)
imposed an obligation on transmission providers that operate distribution
facilities, but would not impose any reciprocal obligation on an electric
utility that operates distribution facilities only. The CSW Companies, Electric
Cooperatives, and TNMP expressed concerns about the commission's lack of consideration
of the technical/practical issues related to this section: namely the commission's
failure to address billing, metering, power scheduling, reliability, cost
shifting, unfair competitive advantage and load nomination to name a few.
The existing transmission rule requires utilities to provide transmission
service at the distribution level, if the transmission service customer is
interconnected with the transmission service provider at a distribution voltage
level. The proposed rule would expand this obligation, requiring the transmission
service provider to provide service to the point where a retail customer takes
service, but only if the transmission customer is certified to provide retail
service in the area.
No one has argued that retail customers in multiply certificated areas
do not have the right to switch service to any utility that is certificated
to serve the area where the customer's facility is located. Under current
practice, a switchover is typically accomplished by the incumbent provider
physically disconnecting from the customer and the new provider physically
interconnecting with the customer's facility. This often involves the incumbent
utility removing poles and wires, and the new provider installing new facilities.
This usually involves a significant cost to customers and deters them from
exercising the right to choose. As Power Choice argued, the term "retail wheeling"
does appear in PURA. PURA §35.005(a) gives the commission the power to
require an electric utility to provide transmission at wholesale. PURA §31.002(7)
specifically defines transmission service to include transmission over distribution
facilities. Under the statute, the commission can require a utility to provide
transmission service over both transmission and distribution facilities. Transmission
service that reaches to the level of the customer is still wholesale transmission
service, because another utility is taking transmission service, not a retail
customer. The real legal impediment to retail wheeling is the fact that in
most areas of the state there is a single utility that has the right to provide
retail service. This provision would not authorize or facilitate retail service
by a company other than a utility that has the right to provide such service.
From a legal perspective, the proposed provision does nothing more than
enforce existing rights of customers in a dually certificated area to select
their energy provider. Removal of impediments to these customers' choosing
a different power supplier, in a situation where they have the legal right
to choose, is consistent with the public interest. On the other hand, the
introduction of retail competition has emerged as a significant issue in the
1999 legislative session, and the commission would benefit from any policy
guidance that legislative action on this issue would provide. For this reason,
the commission is adopting this provision with an effective date after the
end of the legislative session, September 1, 1999. Based on the action taken
by the legislature in the current session, the commission could proceed with
the implementation of this provision of the rule, suspend its implementation,
or initiate a proceeding to delete it. Delaying the implementation of this
provision will also permit the technical difficulties raised by the parties
to be addressed.
Austin and TU Electric requested clarification of the term used in §25.191(e),
"other eligible transmission customers." TU Electric suggested the commission
replace this phrase with "eligible transmission service customer" which is
already defined in §25.5(19) of this title (relating to Definitions).
Responding to these comments, Independents noted that in the future, customers
currently being served at retail might be eligible for transmission service.
Therefore, the transmission rules should not have to be amended again to assure
these new transmission customers comparable access to the ERCOT transmission
system.
The commission is defining the nature of wholesale service through a series
of contested cases. To the degree that the definition of wholesale service
changes as a consequence of these cases, this provision will permit the changes
to be self-effectuating, and further commission action to amend this rule
will not be necessary.
Garland, Weatherford, Pedernales, and Brownsville raised a concern that
resale of transmission rights may lead to hoarding of transmission capacity
and exacerbate market power in constrained areas. These parties requested
that the commission add restrictions to prohibit speculative transactions
that may lead to tying up transmission capacity. They submitted rule language
to provide the ISO with authority to prevent speculation on transmission capacity
and ancillary services.
This provision allowing the resale of transmission rights was a part of
the transmission rules adopted by the commission in 1996, and the commission
is not aware of any actual problems that have arisen as a result of the resale
provision. Rather than deleting this provision in response to hypothetical
concerns, the commission will retain it.
In the preamble to the proposed rule, the commission posed the following
question: A transmission service provider is required to provide reactive
power support to maintain adequate voltage support and control. Should this
requirement be changed to encourage new transmission-only electric utilities?
ANP and STEC supported the provision that would require transmission service
providers to supply reactive power. Independents supported the concept of
transmission- only utilities. However, until generation and transmission are
truly unbundled, they asserted that the obligation to provide reactive power
support should remain the responsibility of transmission providers. They also
cautioned the commission to be wary of creating reactive power support as
an ancillary service that cannot be competitively provided. The CSW Companies
argued that the rule should be clarified to state that transmission providers
must supply needed reactive power support from non-generation facilities that
is in excess of that required to be supplied by generators under ISO guidelines.
HL&P supported the concept of voltage support in the rule, on the basis
that transmission providers should ensure that their portion of the transmission
grid is operated safely and reliably. However, HL&P asserted that there
was no need to revise the rule to encourage transmission-only electric utilities.
If new utilities are needed due to inadequate service, the commission could
grant a new certificate of convenience and necessity (CCN). If service is
adequate, current law and rules would result in a denial of a certificate
of convenience and necessity, effectively minimizing duplicative facilities.
Panda raised a concern about market power abuse and the potential for a
transmission service provider to impact a competitor's operating cost and
thus ability to compete. More specifically, if new generators are required
by transmission service providers to operate at a power factor that is less
than unity while the generator owned by the electric utility is operated at
a higher power factor, then the new generator's fuel cost would increase without
marketable increase in output. Panda supported a modification to the rules
to allow generators and transmission service providers to buy and sell reactive
power. In reply comments, Brazos supported the Panda proposal. Power Connect
submitted that the obligation to provide reactive power to maintain system
voltage should be the responsibility of the control-area operator, and not
each owner of a portion of the transmission lines in the control area. Independents
objected to control-area operators, their competitors, having the unfettered
authority to require non-utility generators to provide reactive power. However,
Independents would not object to authorizing the ISO to order any generator
to provide reactive support for planned transactions and emergency situations,
subject to appropriate compensation. Consumer-Owned Power Systems stated that
the commission's rules should be modified to require all generation providers
to be able to provide reactive power support to the grid based upon standards
adopted by the ISO. They noted the local nature of reactive power and argued
that the proposal to require transmission providers to purchase ancillary
services from the market raised additional unresolved issues. TIEC responded
that attempting to unbundle and properly price reactive power would dramatically
increase the complexity of the transmission rates proceedings since there
is no generally accepted method of quantifying the cost of providing reactive
power from generating plants. TIEC added that should the commission unbundle
reactive power, all generators that contribute to reactive power should receive
compensation for this service.
TU Electric acknowledged the complexity of this issue and that voltage
support required coordinated action of generation, transmission and distribution
system operators. TU Electric observed that making reactive power support
exclusively the obligation of transmission providers would not adequately
address the generation-related voltage- support function. A remedy to this
problem would be to follow the FERC's lead and treat active reactive power
support by generation as an ancillary service. TU Electric urged the commission
to recognize that all generation resources (both utility and non-utility alike)
have responsibilities for voltage support that can and should be addressed
in the management of any interconnected electric system. San Antonio commented
that consistent with the nature of transmission service the rule should be
modified to make clear that the obligation to provide reactive power support
should be limited to non- generation related sources.
TU Electric also offered that the current rule did not adequately address
the power factor requirement; the rule failed to address where the measurement
is to be taken, and that points of interconnection at distribution voltages
must have a higher power factor (0.98 lagging) in order to equal a 0.95 lagging
power factor at transmission voltage. LCRA declared that the proposed 95%
power factor at each point of interconnection would effectively increase the
distribution power factor requirement from 95% to 98% and cost LCRA's customers
up to an additional $1.5 million. The CSW Companies suggested in their comments
on §25.198(b) that the rules be revised to require an eligible customer
that is responsible for serving wholesale load to maintain an average power
factor of 95% or greater. LCRA agreed that the ISO should have the authority
to permit reasonable variations from the 95% power factor requirement if circumstances
warrant. LCRA stated that the cost of the capacitors on the low side of the
point of interconnection with the transmission system, and which are located
within the substations, are often the most cost-effective way to meet the
power factor requirement and support the transmission system voltage. According
to LCRA, the cost of such capacitors should be included in transmission rates.
Consumer-Owned Power Systems also disagreed with TU Electric's proposal to
change the power factor on the distribution system to 98% lagging, and offered
that TU Electric did not show that the change would be reasonable.
Garland noted that the question relating to the obligation to provide reactive
power raises a similar issue of "must-run" units, which the commission should
address. Garland requested clarification on how must-run units are identified
and who determines which units are "must-run" units. Moreover, Garland proposed
compensation based on the higher of embedded cost or market price when "must-run"
units are called upon to provide voltage support. STEC, in its comments under
§25.198, urged the commission to provide a uniform definition of "must
run" units. Because of the commission's limited jurisdiction over EWGs, it
should require utilities purchasing power from non-utility generators to include
in their purchase power agreements a condition that the generator will provide
reactive power support if requested by the ISO.
The rule being adopted requires transmission service providers to provide
reactive power, requires distribution utilities to meet power-factor standards
at the point of interconnection with the transmission system, and permits
the ISO to establish reactive- power standards for generating facilities.
Thus, each of the functions of the electrical system will be subject to a
requirement to provide reactive power to support the operation of the transmission
network, but there is not any explicit provision for the recovery of capital
or operating costs for providing reactive power, except to the extent that
the costs are for transmission system equipment and operations. The issue
of reactive power warrants further investigation, but the record in this rulemaking
proceeding does not establish a sound basis for proposing a more comprehensive
treatment of the issue. This issue is also discussed in connection with §25.192
and §25.198.
In proposing the rule the commission did not intend to change its prior
decision concerning the point at which power factor is measured. The comments
on power factor suggest that there are cost and reliability trade-offs in
improving the power factor at the interface between the transmission and distribution
systems. The ISO has initiated a review of the compliance of distribution
companies with the existing rule on this subject. This is an appropriate step
in analyzing this issue, and this review should be taken into account in any
further refinement of the power-factor standard and discussions of compensation
for providing reactive power support.
Based on the comments, it appears that a transmission-only utility could
be formed, but would need to buy reactive power support from a generator that
is capable of providing reactive power. The current rules reflect an environment
in which integrated companies own most of the transmission facilities in ERCOT.
In order to create real opportunities for transmission-only utilities, methods
for pricing reactive power may have to be developed.
Section 25.192: Transmission Service Rates
Austin argued that §25.192(a)(1) and (a)(2) require the calculation
of new transmission rates every year. Austin favored the method used by the
commission to determine the 1998 rates since it would more appropriately capture
the impact of increased customer loads and increased use of the transmission
system. TIEC pointed out that under the proposed rule, §25.192(a) and
§25.200(c)(2), short-term planned transmission service would be priced
to include both a facilities charge and redispatch costs, if applicable. According
to TIEC that is inappropriate because it would allow a transmission provider
to recover more than its actual embedded cost of service, and also because
it violates FERC's transmission pricing policy of charging the greater of
the embedded cost or redispatch cost, but not both.
The commission intended in proposing the rule and intends in adopting the
rule that transmission rates, once approved, would remain in effect until
modified. The proposed §25.193 included an annual update of transmission
rates that was mandatory for investor-owned utilities, but there was not an
annual revision of rates for other utilities. The rule does include provision
for an annual change in transmission charges, because billing determinants
for planned service (megawatts and megawatt-miles) are based on an annual
service period. The commission is adopting a short-term planned service that
is based on 70% of each utility's transmission cost of service (TCOS), and
with the revenues from such service reducing the cost of annual planned service.
Existing planned service includes a facilities charge that is based on 100%
of TCOS
Brazos argued that only load entities or their agents should pay transmission
fees and charges for transmission, not the broader category of transmission
service customers. Independents suggested changing the term "annual transmission
cost" appearing in the third sentence of §25.191(a)(3) to "annual cost
of transmission service" to comport with other uses of the latter term in
the subsection.
The proposed rule, for the most part, used neutral terms such as "transmission
service provider" and "transmission service customer," rather than terms that
might specifically identify a customer as a load-serving entity or other market
participant. These neutral terms would permit a power marketer, for example,
to arrange transmission service on behalf of a load-serving utility. The charges
for annual planned service are based on characteristics of the load to be
served (the peak load and the transmission impacts of transmitting power to
the load), but the commission concludes that it is more consistent with a
competitive market to use the term "transmission service customer." The Independents'
suggestion is consistent with other usage in the rules and has been adopted.
Construction of new facilities
In §25.192 and §25.195, the commission proposed to distinguish
between transmission facilities that provide a direct interconnection between
a generating facility and the transmission network and upgrades to the transmission
network itself. This distinction was proposed in connection with the addition
of new generating plants. Under the proposed rule, the developer of a new
merchant plant would be responsible for the costs of the direct interconnection,
and transmission service providers would bear the costs of transmission system
upgrades, even if the upgrades were attributable to the addition of new generation
facilities to the electrical network. The costs borne by the transmission
provider would be eligible for inclusion in transmission rates, while costs
borne by the developer of a generating facility would not. In their comments,
some of the parties noted that the distinction was not very clear. Some of
the parties either supported the distinction proposed by the commission or
sought to clarify it. Other parties proposed other alternatives for the treatment
of interconnection costs and system upgrades. The principal alternatives were
the following: (1) the commission's proposal; (2) treating all transmission
facilities operating at 60 kilovolts or above as the responsibility of the
transmission service provider, and (3) establishing a dollar-per-megawatt
amount as a threshold for inclusion of interconnection and upgrade costs in
transmission rates; and (4) requiring the developer of a generation facility
to bear the costs of interconnection and a share of the cost of system upgrades.
ANP and Koch supported the concept that generating plants should be responsible
for the cost of direct interconnection to the transmission system, while requiring
transmission service providers to bear the costs of system upgrades relating
to the operation of the generating plants. ANP noted that developers of new
generation projects would want to know the cost of any transmission facilities
they will be required to bear prior to committing capital and commencing construction
of a project. ANP also supported assigning responsibility for transmission
costs to the person that would benefit from a transmission project. The CSW
Companies and HL&P proposed a clarification of what constitutes a direct
interconnection to the transmission system. Independents, LCRA, TIEC, and
TU Electric also expressed the view that this provision must be clarified.
According to the CSW Companies, direct interconnection would be the facilities
necessary to connect a generator's step-up transformer to the first transmission
substation in the transmission grid with two or more transmission lines that
terminate at different points on the transmission grid. In reply comments,
TIEC supported this approach. TIEC argued that radial transmission lines do
not serve a transmission function because power generally flows in only one
direction. According to TIEC, the change in the nature (use) of the radial
lines over time should be reflected in transmission rates as they occur, and
so there is no need to assume that all radial lines are providing comparable
transmission service. HL&P proposed that direct interconnection be defined
in terms of facilities that only serve to move power from a generator to the
transmission system. The Consumer-Owned Power Systems, Independents, and LCRA
argued that any transmission facilities rated at 60 kilovolts of higher should
be eligible for inclusion in transmission rates. If the commission adopts
the rule as proposed, Independents recommended that all existing transmission
lines connecting utility generators to a substation/switchyard should be removed
from TCOS. Brazos, LCRA, and TNMP opposed the exclusion of a generator's direct
interconnection cost to the transmission network from transmission rates.
Brazos pointed out that generation and transmission cooperatives would have
to charge the existing wholesale customers more to recover the costs of the
excluded lines and that would dampen competition. LCRA and TNMP argued that
this proposal would exacerbate generation owners' stranded cost problem. LCRA
questioned whether a power-plant developer would have eminent domain authority
to build a radial transmission line, and whether it would be a "public utility"
requiring a CCN for the connection. LCRA and Panda argued that step-up transformers
and one high-side interrupting device should be treated as generation facilities,
but that any transmission lines connecting a generator to the transmission
grid, whether radial or looped, should be regarded as transmission facilities
and included in transmission rates. STEC commented that a bright line test,
such as including all facilities operated at 60 kilovolt or above used in
interconnecting a generator, in transmission rates would prevent future disputes
between the generator and transmission service provider. TNMP pointed out
that even though currently only one market participant may utilize some transmission
facilities, these facilities could be used to accommodate transmission access
for other market participants in the future.
A number of parties discussed alternatives that would employ a dollar-per-megawatt
threshold in determining whether interconnection or upgrade costs could be
recovered through transmission rates. Garland proposed that a developer of
a generation project be permitted to recover transmission costs for interconnecting
with the transmission system, up to an amount equal to the average embedded
cost of transmission per megawatt, on the basis of comparability with the
rate treatment of existing facilities of integrated utilities. OxyChem noted
that it had proposed earlier in this rulemaking project that the commission
require new generators to bear the direct interconnection costs of their projects
and adopt a threshold amount for system upgrades. If the cost of system upgrades
for a generation project were less than the average embedded cost of transmission
in ERCOT, the transmission provider would bear the upgrade costs. If the costs
of the project exceeded the threshold, the generator would bear the excess
upgrade costs. OxyChem in the comments filed in response to the proposed rule
urged the commission to make it clear that it will use the certification procedure
to ensure that electric customers are not burdened by excessively costly transmission
upgrades. TU Electric suggested that the rule require the generator to bear
the cost of the direct interconnection facilities and any transmission facilities
that must be constructed by the transmission provider to connect the generator's
direct interconnection facilities with the transmission provider's transmission
system. Under the TU Electric approach, the cost of any upgrades elsewhere
on the transmission system that would not be needed but for the connection
of the new generator, would be eligible for inclusion in transmission rates,
subject to a commission approved cost cap expressed in dollars per megawatt.
The costs of system upgrades in excess of this cap would be included in transmission
rates only if they provided a general benefit to the transmission system.
TIEC initially supported a cost threshold that would establish a rebuttable
presumption that system upgrade costs up to the embedded cost of transmission
capacity would be recovered in the TCOS. Recovery of transmission costs in
excess of the allowable threshold could be sought in a rate case.
Consumers Union disagreed with assigning the responsibility for transmission
upgrades to the transmission service provider, arguing, instead, that a merchant
generating plant that caused transmission facilities to be built should bear
the cost of the new facilities. Public Counsel and San Antonio supported the
concept that generating plants should be responsible for the cost of direct
interconnection to the transmission system, but would require generating plants
to also bear a part of the costs of system upgrades necessitated by the new
generating plants. Alternatively, San Antonio proposed that system upgrade
costs equal to the average ERCOT transmission investment should be included
in the transmission service provider's rates. In reply comments, Panda suggested
that the costs of direct interconnection be considered a part of the generation
project, which would not be eligible for recovery through transmission rates,
but that the developer of the generation project could elect to seek recovery
of the costs through transmission rates.
One of the important issues that has emerged in connection with the proposed
construction of new merchant generating plants in ERCOT is who pays for the
new transmission facilities that are required to connect them to the network
and to provide access to broad geographic markets. In §25.192 and §25.195,
the commission proposed to distinguish between (1) transmission facilities
that provide a direct interconnection from a generating facility to the transmission
network and (2) upgrades to the transmission network itself. Under the proposed
rule, the developer of a new merchant plant would be responsible for the costs
of the direct interconnection, and transmission service providers would bear
the costs of transmission system upgrades, even if the upgrades were attributable
to the addition of new generation facilities to the electrical network. The
costs borne by the transmission provider would be eligible for inclusion in
transmission rates, while costs borne by the developer of a generating facility
would not. The principal alternatives supported by the commenters are: (1)
including in TCOS the costs of any transmission facilities at 60 kilovolts
and above, (2) distinguish between transmission facilities that represent
the "highway," which would be recovered in TCOS, and the "driveway," which
would be the responsibility of the generator, (3) establishing a threshold
amount and permitting recovery of any transmission upgrade up to the threshold
in TCOS, and (4) requiring the developer of a generation facility to bear
all of the costs of interconnection and a share of the cost of system upgrades,
in proportion to benefits the developer derives from the system upgrades.
The policy issues raised in the parties' comments include (1) the need
for a clear rule, so that generation projects are not hampered by uncertainty
about the costs that they will bear, (2) comparable treatment of transmission
facilities required for new projects and existing generation, (3) appropriate
economic incentives for suitably siting new generation facilities, and (4)
the need to provide incentives for new transmission facilities. There was
broad support for a clear rule, so that both generation developers and transmission
service providers know what is expected of them. The parties that seek to
apply a benefits test in connection with the inclusion of system upgrade costs
in transmission rates are apparently concerned that uneconomic facilities
will be built and charged to consumers of electricity. They are concerned
that construction of new merchant generating facilities will drive the construction
of new transmission facilities, and that siting decisions for generation will
ignore the costs of transmission upgrades necessary to deliver power from
the new generating facilities to areas where the power is likely to be consumed.
The end result would be a more expensive transmission system than if new generation
facilities were sited in more appropriate locations.
Assigning generation developers responsibility for a part of the cost of
system upgrades is one means of controlling generation siting. If system upgrades
were costs that a generation developer must bear, rather than an external
cost, a developer would make more efficient decisions, from a societal perspective,
with respect to siting of generation. Another means of exerting control is
through the process of licensing new transmission facilities. The licensing
process affords the commission an opportunity to consider the costs and benefits
of new transmission facilities and reject applications for facilities that
do not provide sufficient benefits to customers. (Simply the risks and delay
inherent in the licensing process should create a self discipline that will
deter developers from building new generation in areas that are likely to
be seriously constrained. While the transmission upgrade costs would remain
external costs, congestion and the risk of inadequate delivery capability
would be internal costs and risks for the generation developer.) Having clear
criteria for determining who bears what costs is a key element of the transmission
rule. In a competitive environment, transmission costs should be borne by
transmission providers and generation costs by generation providers. System
upgrades are clearly transmission costs, but the licensing process and the
risks inherent in it should be adequate to preclude the construction of generating
facilities in areas where the costs of alleviating transmission constraints
are significant. The same consideration applies with regard to direct interconnection
costs. By including direct interconnection costs in TCOS, the commission will
encourage the construction of needed, new generation and provide a clear demarcation
between generation and transmission facilities. At the same time, if there
are instances in which a significant transmission facility is required to
provide the interconnection of a new generation project to the network, the
licensing process and the risks inherent in it should be adequate to preclude
the construction of uneconomical projects. For the reasons discussed above,
the rule will treat transmission as any facilities above 60 kilovolts, and
the generation owner's responsibility will be to construct the step-up transformer
and a protective device at transmission level; the remaining facilities at
transmission level will be the responsibility of the transmission service
provider.
Other rate issues
Other issues were raised with respect to §25.192. Brazos expressed
the view that the proposal to make transmission service providers responsible
for transmission upgrades does not assure that the transmission service provider
will be able to recover the costs of new transmission facilities that are
built for short-term or unplanned transactions. Brazos proposed that the transmission
service customer for whom new facilities are built pay the annual fixed costs
of the new investment and the overhead and maintenance costs until the transmission
service provider is able to include the costs in its transmission rates. As
is noted above, a number of commenters suggested the need for clarification
of the term "direct interconnection cost." Brazos and LCRA argued that it
is impossible to identify which of the existing lines are not part of the
network and hence are to be excluded. According to these commenters, a large
amount of the transmission network in ERCOT terminates at generators, but
most of these connections are critical paths in the network. CSW Companies
recommended that the interconnecting transmission facilities that are involved
in a looped connection be included in TCOS because these are integral parts
of the transmission network. According to CSW Companies, the ISO should decide
(subject to commission approval) whether a generator should be connected
with a radial line or a looped connection.
The proposal to require that a transmission service customer for whom new
facilities are built pay the annual fixed costs of the new investment and
the overhead and maintenance costs until the transmission service provider
is able to include the costs in its transmission rates is not being adopted.
The rule requires a transmission service provider to plan and construct new
transmission facilities to provide an interconnection for new generating plants
to the transmission network. Financing these planning and construction activities
is a part of the transmission function and should be carried out by transmission
service providers. The rule includes a provision that permits a transmission
service provider to charge a deposit to cover such costs, in the event that
the generation project is not completed. The risk of planning and building
new transmission facilities to accommodate a generation project that is not
built is one that should be shifted to the developer of the generation project,
but the other costs and risks associated with the planning and construction
of transmission facilities should be borne by the transmission service provider.
Because the commission is not adopting the concept of "direct interconnection,"
no clarification of that phrase is needed.
The CSW Companies, TU Electric and Independents agreed that the cost of
the direct-current (DC) ties should be included in TCOS, since the DC ties
support competition in wholesale power. The CSW Companies and TU Electric,
however, recommended a 100% inclusion of the DC tie costs in transmission
rates. TU Electric asserted that there is no rational basis for treating these
costs any differently than the costs of other ERCOT transmission facilities,
since these facilities facilitate bulk power transfers like any other transmission
facilities in the ERCOT grid. TU Electric also pointed out that allowing less
than 100% of the DC tie cost would result in a ERCOT transmission rate that
is different from the FERC rates that allow for 100% recovery of such costs.
According to TU Electric, less than 100% recovery of DC tie costs would effectively
remove any economic incentive for expansion of these facilities. The CSW Companies
pointed out that revenues from DC ties are credited to ERCOT TCOS, a crediting
that would be inconsistent with excluding the cost of the DC interconnections
from TCOS. The CSW Companies disapproved of the uncertainty that results from
the provision of the rule that leaves it open to a case-specific commission
decision on how much of the DC tie costs would be included in transmission
rates. Austin also asked for standards that would be used in order to have
some degree of certainty regarding cost recovery, but at the same time provide
the commission some flexibility. Public Counsel suggested incorporation of
the commission decision on the subject in Docket Number 15463 (the Central
Power & Light & West Texas Utilities transmission cost of service
case) in the rule. There, the commission concluded that DC tie investment
is includable in cost of service to the extent: (1) all wholesale market participants
have non- discriminatory access to imports over the facility; and (2) only
by the amount of the facility used for import rather than export of power.
San Antonio opposed the inclusion of DC tie costs in the ERCOT TCOS. According
to San Antonio, those entities that actually use the DC ties should pay the
costs of the ties. It is anomalous for ERCOT entities to pay for the ERCOT
reserve margin and the theoretical reliability added by the DC ties as well.
Garland and STEC made similar arguments, Garland noting that there is limited
capacity across the ties, and hence limited use by other parties. It argued
that including the DC tie costs in transmission rates would subsidize those
parties having access to the ties and generation outside ERCOT, at the expense
of transmission service customers in ERCOT. Finally, the CSW Companies recommended
replacing the reference to the DC ties with the Southwest Power Pool (SPP)
with more general language that will accommodate other DC ties that may be
built in the future.
The DC ties provide an interconnection between ERCOT and the SPP, a neighboring
power region that includes Oklahoma, and portions of Texas, New Mexico, Missouri,
Arkansas, and Louisiana. The existing rule permits the costs of the DC ties
that are allocable to ERCOT customers to be included in transmission rates,
to the extent that the ties are subject to non-discriminatory access and are
actually used to import power into ERCOT. In the TCOS proceeding for CPL and
WTU, the commission concluded that the utilities had not met the burden of
demonstrating that these conditions had been met. Since then, however, the
FERC has approved transmission tariffs for these utilities and for TU Electric
and HL&P that provide for access to the DC ties on terms that the FERC
concluded were consistent with the open-access requirements of Order Number
888. The proposed rule would eliminate the criteria relating to open access
(on the basis that it has been met) and use of the ties for imports. The proposed
rule would permit the inclusion in TCOS of the cost of the DC ties that are
owned by a transmission service provider in ERCOT "to the extent that the
commission determines that cost is properly allocable to ERCOT customers."
The principal issues that arose in connection with this issue were consistency
in treatment of transmission costs and designing rates that would foster competition.
The DC ties are unlike the network alternating-current (AC) facilities in
ERCOT. The ERCOT AC facilities provide multiple pathways for power delivery
in support of the reliable service of ERCOT customers as a whole. The DC ties,
on the other hand, function like a radial connection to a load or power source.
The DC ties can be used to import power into ERCOT, and in this mode they
operate like a radial transmission line connecting a generator to the transmission
system. They can also be used to export power from ERCOT; in this mode they
operate like a radial transmission line connecting the transmission system
to a load. In either event, the persons who benefit from the ties are the
persons importing or exporting the power, typically an ERCOT utility and its
customers, and a non-ERCOT partner in the transaction. The ties have broader
capabilities than a radial AC facility, however, because they can be used
to connect to either a load or a resource and they can change the type of
use and the beneficiary of the use, from time to time. The cost-of-service
provisions of the existing rule permit the radial connections to a load to
be included in TCOS, and the commission has not proposed a change in this
provision. The commission is adopting a rule that permits the costs of the
direct interconnection between a new generator and the transmission system
to be included in transmission rates; for consistency's sake, the rules should
also include ERCOT utilities' costs associated with the DC ties in transmission
rates.
Including the costs of the DC ties in intra-ERCOT rates will probably stimulate
trade over the DC ties. This issue is similar to the pricing of unplanned
service. When the commission initially considered the adoption of Substantive
Rule §23.67 of this title, a number of parties argued and the commission
agreed that rates for unplanned service should not include facilities costs.
To the extent that facilities costs are fully recovered through the rates
for planned service, these costs were excluded from the rates for unplanned
service. This means that the rates for unplanned service are lower, which
fosters competition in short-term sales relying on unplanned service.
The owners of the DC ties support a pricing scheme for the ties that would
include the costs of the ties in the intra-ERCOT rates, which would then permit
a transmission customer that is serving an ERCOT load to use the DC ties without
additional transmission costs. (In effect, the customer has already paid his
fair share of the cost of the DC ties in the rates for annual planned transmission
service.) The alternative to such pricing would be for the owners to seek
FERC approval of separate rates for the use of the ties alone. (The FERC has
already approved the concept of rates that roll together the costs of the
DC ties and the ERCOT AC facilities of the owners of the ties.) Separate rates
for the use of the ties would result in higher rates for import and export
service, because the volume of transactions is much smaller than the volume
of intra-ERCOT transactions. Rolling the costs of the DC ties into the intra-ERCOT
rates would be more effective in fostering competition among ERCOT and non-ERCOT
producers. A high import-export rate, in effect, creates a high toll for the
use of the DC ties, thereby discouraging trade over the ties. Accordingly,
the rule being adopted will permit the transmission service providers in ERCOT
to include their costs of the DC ties in the intra- ERCOT transmission rates.
TU Electric proposed to add a new §25.192(b)(1)(D) that would permit
the cost of capacitors to be included in transmission rates if they are installed
in substations to provide voltage support on the transmission system, regardless
of whether they operate at or above 60 kilovolts. TU argued that if low-voltage
capacitors were not included in TCOS, they would not be used even when they
are cheaper.
Several parties raised difficult issues with respect to the provision of
reactive power. The proposed rule would require transmission service providers
to provide reactive power, would require distribution utilities to meet power-factor
standards at the point of interconnection with the transmission system, and
would permit the ISO to establish reactive-power standards for generating
facilities. Thus, each of the functions of the electrical system will be subject
to a requirement to provide reactive power to support the operation of the
transmission network, but there is not any explicit provision for the recovery
of capital or operating costs for providing reactive power, except to the
extent that the costs are for transmission system equipment and operations.
The commission adopted a limited exception to this general rule in the initial
cases establishing transmission rates. It concluded that some capacitors are
physically located in distribution substations and operate at distribution
voltage but support the transmission system. They are installed at distribution
voltages, because they operate more effectively in that configuration, and
provide reactive power support at a lower cost than if they had been installed
directly on the transmission system. The commission permitted these distribution-level
capacitors to be refunctionalized, but the rule was narrowly drawn so that
distribution facilities that are performing a distribution function are not
included in TCOS. Thus, a capacitor that was classified as a distribution
facility was permitted to be included in TCOS only if (1) it is located in
a distribution substation, (2) the load at the substation has a power factor
in excess of 0.95 without the capacitors, and (3) the capacitors are controlled
by an operator or automatically switched in response to transmission voltage.
The commission did not intend to change this rule and is including a provision
to reflect this approach in the rule. Beyond this narrow issue, the rulemaking
has not provided an adequate opportunity to fully explore the issue of cost
recovery for providing reactive power. This is an issue that is appropriate
for further exploration by the commission and interested parties.
The CSW Companies suggested clarifying language that TCOS shall not be
reduced by transmission revenues received from others, based on the decision
of the commission in Docket Number 15840. San Antonio, Garland, Consumer-Owned
Power Systems, and Independents supported the proposal to permit the cash
flow method as an alternative method of determining annual TCOS for municipal
utilities. San Antonio suggested that it is appropriate to include a more
specific statement of the acceptable elements of the cash flow method in the
commission's transmission rate-filing package. For this rule San Antonio suggested
that, in order to avoid confusion, the new provision make clear that cash
flow or other alternatives may be used independently of, rather than in conjunction
with, the rate-of-return method specified by the following section. It suggested
language to be included in the rule to achieve this result.
The commission agrees that it is appropriate to clarify these issues. The
CSW proposal is consistent with the Order in Docket Number 15840, which the
commission did not intend to change with the adoption of the new rules. The
treatment of revenues from pre-existing transmission contracts is more appropriate
to be clarified in the commission's filing guidelines for TCOS cases. The
clarifications proposed by San Antonio and others are consistent with the
proposed rule and the authorization of different methods for determining TCOS
for municipal and cooperative utilities.
The CSW Companies commented that §25.192(b)(3) and (b)(4) refer to
utilities "not otherwise subject to the commission's rate setting authority."
They construed this provision as applying to utilities that are not subject
to the commission's retail rate setting authority, such as Austin Energy and
City Public Service Board of San Antonio, and urged that this point be clarified.
Consumer-Owned Power Systems noted that it is unclear whether the phrase "electric
utilities not otherwise subject to the commission's rulemaking authority"
would apply to distribution cooperatives that have elected to be exempt from
rate regulation. They recommended that the rule explicitly state that it applies
to cooperatives and municipal utilities. Austin commented that §25.192(b)(4)
should be revised to clarify how return dollars are determined for utilities
whose rates are not otherwise subject to the commission's ratesetting authority.
Instead of stating that "
the rate of return
may be the utility's actual debt service and a reasonable coverage ratio,"
the provision should read "
the return dollars
may be determined from the utility's actual debt service and a reasonable
coverage ratio." Austin also suggested that there is an inconsistency between
proposed §25.192(b)(3) and (b) (4), and the proposed §25.193(a)(1).
Section 25.192(b)(3) and (b)(4) describe how the return for utilities that
are not investor-owned can be determined by using either the cash flow or
debt service plus reasonable coverage ratio method. However, the procedure
for modifying transmission rates stated in §25.193(a)(1) lacks a reference
to debt service and a reasonable coverage ratio. Austin suggested that the
methods used under §25.192(b)(3) and (b)(4) (using a municipality approach)
also be incorporated into §25.193(a)(1) for utilities other than investor-owned
utilities (IOUs).
STEC commented that the commission's methodology for setting coverage ratios
should not result in an abrogation of the commission's duty under the statute
to ensure that those rates are just and reasonable. The commission should
not be bound by the action of a city or river authority in the return the
utility is allowed.
It is appropriate to clarify the phrase "not otherwise subject to the commission's
rate setting authority." This phrase was intended to apply to municipal utilities
and cooperatives, and the rule has been modified to say so explicitly. The
commission has made other minor changes to reflect more accurately how rates
are calculated using a cash-flow method; these changes are generally consistent
with the suggestions of the parties that filed comments on this issue. The
commission also agrees with STEC's comment that the authorization of the cash-flow
methodology and the use of coverage ratios in determining return does not
abrogate the commission's duty under the statute to ensure that transmission
rates are just and reasonable.
Brazos commented that the proposed §25.192(b)(3) and (4) allow entities
whose rates are not set by the commission to have different coverage ratios,
which may result in a higher or lower rate of return than that received by
IOUs. Presently, cooperative rates are set by the commission and have historically
had lower coverage ratios, which means that other transmission providers can
pay less for using transmission lines constructed by the cooperatives than
those constructed by other transmission providers. The commission should ensure
the same coverage ratios for all transmission providers.
The commission, in setting rates for transmission utilities in the initial
TCOS cases, considered and rejected a similar argument. The commission adopted
transmission rates for service providers based on their own cost of capital,
rather than on the cost of capital of other utilities. This approach is consistent
with provisions of PURA that require the commission to set rates to give a
utility a reasonable opportunity to recover its reasonable and necessary operating
expenses and a reasonable return on its invested capital and that require
persons taking transmission service compensate the service provider, so that
retail customers are not required to subsidize transmission service. It is
difficult to see how this result could be achieved if the commission were
to disregard the utility's cost of capital in setting rates.
The CSW Companies asked for an explanation for the change in the peak months
used in setting transmission rates. If a change in the peak months is made,
they suggested that June be eliminated, rather than September. TU Electric
agreed that there was no compelling need to make the change proposed in the
rule and expressed concern because all existing transmission rates were calculated
based on the basis of four coincident peaks. TU Electric pointed out that
the revision is inconsistent with the "one-fourth" language in §25.192(h)(3).
Finally, TU Electric requested that if rates are based on three coincident
peaks, rather than four, the rule should expressly provide for a prospective
application only. San Antonio opposed deletion of September peak and recommended
that rates be based on twelve coincident peaks, namely, September through
August. HL&P suggested that the monthly on-peak access fee be changed
accordingly to "one- third of the annual rate."
Based on the parties' comments, the commission has decided to determine
transmission rates and charges using the four-coincident peak method that
is currently used. It had proposed the three-coincident peak method in the
belief that this would expedite the determination of peak loads each year,
but the comments suggest that the current method is appropriate, particularly
because September peaks are typically higher than June peaks. Deleting the
September peaks would thus result in rates and charges that are less representative
of summer peak consumption.
TIEC recommended exclusion of interruptible loads served under tariffs
that permit curtailments due to inadequate transmission capacity. TIEC noted
that not all utilities limit curtailments of interruptible customers to generation
capacity shortages. Several utilities interrupt due to transmission capacity
shortages. Furthermore, adding interruptible load in the calculation of the
distance-sensitive component of transmission rates would be inconsistent with
the ERCOT planning reserve margin criteria, which specifies a 15% reserve
margin relative to firm peak demand. TIEC asserted that the existence of an
economic buy-through provision in an interruptible tariff is not relevant
when calculating the peak loads, because interruptible loads with buy-through
provisions are still required to curtail when there is no capacity to support
continued service. HL&P supported TIEC's clarification that only firm
load be included in a transmission provider's planned transmission service
nomination. Messrs. Seelke and Moore recommended excluding distributed resources
from the definition of peak demand that is used for the determination of the
load ratio shares since distributed resources do not use transmission service.
In the commission's initial TCOS proceedings, it construed the rule as
requiring that peak consumption include any interruptible load that was being
served at the peak. It is clear that utilities with significant peak load
do not build generation facilities to serve their interruptible customers
but serve them from generation reserves. It is not clear that the same is
true for transmission facilities. Some level of transmission investment is
needed to serve an interruptible customer, and it is not clear that there
is a transmission reserve that can be used to serve such customers. The system
peak will continue to include interruptible load that is served at peak. Distributed
resources will not be explicitly excluded from the calculation of transmission
charges. Seventy percent of the transmission costs (the postage-stamp portion)
are charged on the basis of load. Distributed generation will not be disadvantaged
in this portion of the charge, because the transmission charges for any resource
used to meet the demand will pay the same amount. In fact, distributed generation
may be at something of an advantage, because the resource acts like a demand-side
resource. If it reduces the recorded peak load, the transmission charges will
actually be lower. To the extent that distributed generation is considered
in the calculation of megawatt-mile impacts, it is located close to loads,
so that its impact should be small, compared to other generation resources.
Brazos argued that the method of load calculation is not equitable for
load entities that own transmission lines, because some load entities' load
is calculated with no transmission losses included, while others include losses.
TU Electric recommended making it clear in the rule that the known and measurable
adjustments to wholesale customers' load also applies to mid-year changes
in suppliers, a situation that presumably will increase as the wholesale market
matures.
The procedures set out in §25.194 require consistency in the determination
of megawatt-mile impacts. In response to the comments by Brazos, a similar
provision is being included in that section to require consistency in the
determination of peak load. The commission is adding a reference to resources
in the provision addressed in TU Electric's comments to make it clear that
changes in power supply arrangements should be reflected in revised transmission
charges if the changes can be identified and quantified with reasonable certainty.
The commission recognizes that changes in power supply arrangements may take
place at times other than the end of the year and intends that transmission
charges be changed to reflect the new power supply arrangements if the impact
can be determined with reasonable certainty.
Several parties suggested that the pricing of losses be differentiated
for on-peak, off- peak and seasonal use. According to them the current methodology
results in overpayment to control areas for losses, and has constrained the
energy market in ERCOT, especially during hours when the cost of losses exceed
the cost of electricity being sold. Brownsville also recommended a change
in the loss calculation methodology. Austin suggested that since the ISO calculates
losses, it should have the authority to change the methodology without coming
before the commission, because the latter process would delay implementation
of any new methodology. Panda recommended allowance for in-kind compensation
for losses as an alternative to the payment methodology to be developed by
ISO.
The commission's proposed rule included a provision on losses that calls
for "reasonably accurate compensation for the cost of supplying losses incurred
under different system conditions." This provision would leave to the ISO
the details of the method, including the identification of the different time
periods for which losses would be prescribed. The ISO has used committees
with broad market participation to develop responses to commission initiatives
in the past, and the commission is confident that a reasonable proposal for
losses will emerge from such a process. The loss methodology is like a wholesale
rate, however, and the commission believes that it should approve changes
to the methodology, as it proposed. The commission has previously received
recommendations for permitting the self-supply of losses. Discussions with
the ISO indicate that it does not have the technical capability to introduce
a workable system of in-kind losses. For this reason, the commission is not
adopting the Panda suggestion.
TU Electric argued that the ISO fee referred to in §25.192(a) and
(f) should be deleted since the $0.15 per megawatt-hour charge currently imposed
by ERCOT for unplanned transactions is not a regulated service that should
be addressed in the commission's substantive rule. HL&P and Independents
also argued that codification of decisions that should be made by the ERCOT
board would hinder the board's ability to change funding as well as require
the commission to reopen the rule whenever the charge changes. TIEC questioned
the cost basis of the ISO fee of $0.15. TIEC also argued that if ISO costs
are included in TCOS and reflected in the facilities charge then adding the
ISO fee will double charge the customers seeking weekly or daily planned service.
Finally, TIEC recommended that the ISO fee should be charged on a per kilowatt
per day or per kilowatt requested basis rather than on a per megawatt-hour
basis since the cost in question does not depend on the volume of transactions.
STEC supported imposition of the ISO fee for weekly and daily planned service,
since that would prevent customers from gaming the system by taking short-term
planned service. Garland and Pedernales argued that the provision of ISO fee
of $0.15 per megawatt-hour for unplanned services should be in the rule, in
order to provide a regulatory basis for imposing this charge. PURA itself
does not authorize the collection of this fee. Garland recommended charging
prorated impact fees in addition to the $0.15 per megawatt-hour charge for
monthly, weekly and daily planned service since planned service gets higher
priority than unplanned service. Garland also proposed to add language on
disposition of the revenue from the ISO fees: the revenues from ISO fees should
be used first to fund ISO operation. Any excess revenues should be used to
reduce transmission rates for the next year.
The ISO fee is like a wholesale rate, and it should be subject to approval
by the commission. Including a specific amount in the rule, however, may make
it a burdensome procedure. The commission is revising this provision so that
it parallels the approval of a methodology for losses. The commission approved
the initial $0.15 fee, and the adoption of this rule will not require the
fee to be approved unless it is changed. When the ISO fee was initially proposed,
it was intended as means of recovering from those who benefit from an open
wholesale market a portion of the costs of an institution that is important
in the fair functioning of the market. The funding provisions for the ISO
had broad support at the time, and only TIEC has challenged them now. For
these reasons, the commission is not requiring a change in how the ISO fee
is assessed. Moreover, the commission is not convinced that there is a double
recovery of costs in charging both the ISO fee and a facilities charge for
weekly and daily planned service. The commission believes that Garland's proposal
concerning the disposition of revenue from the ISO fee is not necessary. The
ISO fee represents significantly less than the full cost of operating the
ISO, and a surplus from the ISO fee appears to be unlikely under current market
conditions.
Inadvertent energy
TU Electric, TNMP, San Antonio, LCRA, the CSW Companies, and Brazos opposed
the provision of the proposed rule that would require control-area utilities
to compensate each other for inadvertent energy flows under the existing schedule
imbalance tariffs. All claimed that inadvertent energy flows and schedule
imbalance service are two different things, and that the tariff for the latter
can not be used for the former. TU Electric and LCRA claimed that it is not
possible to identify, for billing purposes, the actual "customer" causing
an inadvertent energy flow between control areas. TNMP, LCRA, the CSW Companies,
and Brazos asserted that a control area should not be required to purchase
inadvertent energy as an ancillary service because: (1) the control area may
not be able to control the amount of inadvertent energy it incurs; and (2)
the cause of the inadvertent energy would be difficult to determine. San Antonio
argued that the current system for inadvertent energy in ERCOT is operating
effectively. San Antonio and HL&P expressed doubt that the additional
efficiency gained from developing an "inadvertent energy service" would justify
the time spent to develop the service. HL&P and the CSW Companies argued
that the proposal could also impact system reliability. If control-area utilities
are not required to maintain their units to provide inadvertent energy, but
may instead purchase it, fewer units may be run with the necessary controls
in ERCOT, thereby endangering system reliability. TU Electric agreed that
the different treatment currently afforded inadvertent energy and schedule
imbalances needs to be addressed, and supported the use of commission-approved
tariffs to govern the payments for inadvertent energy. TU Electric and LCRA
suggested that the commission request the ISO, together with interested market
participants, to study the issue of inadvertent energy and schedule imbalance
service and come to the commission with a recommendation on compensation that
will fairly treat both subjects.
Panda and Independents pointed out that it would be anti-competitive not
to have a single tariff applicable to both control-area utilities and other
entities for inadvertent energy flows. They claimed that while control-area
utilities repay imbalances in kind, they charge other entities for inadvertent
energy flows.
Inadvertent energy consists of uncontrollable flows of energy between control
areas. Under current practice, control-area utilities compensate each other
in kind for inadvertent energy. Uncontrollable flows of energy between a control
area and a transmission customer are governed by tariffs for load-schedule
imbalance and generation-schedule imbalance. These tariffs require a monetary
payment for the energy. The proposed rule was intended to make inadvertent
energy and the schedule imbalance services comparable, requiring control areas
to use the schedule imbalance services for inadvertent energy flows.
Most of the control-area utilities opposed the provision of the proposed
rule on inadvertent energy. They argued that: (1) inadvertent energy and schedule
imbalance service are two different things, and that the tariff for one can
not be used for the other; (2) it is not possible to identify, for billing
purposes, the actual "customer" causing an inadvertent energy flow between
control areas; (3) a control area may not be able to control the amount of
inadvertent energy it incurs; (4) the cause of the inadvertent energy would
be difficult to determine; (5) the current system for inadvertent energy in
ERCOT is operating effectively, and there is little to be gained from developing
inadvertent energy as an ancillary service; and (6) the proposal could affect
system reliability, because control-area utilities might be induced to reduce
the level of control that they maintain over their generating units.
There are two aspects to this issue: reliability and compensation. These
issues are largely independent of each other. The parties that raised the
reliability issue seem to be arguing that if control-area utilities are required
to compensate each other in cash, rather than in kind, they will be lax about
adopting measures that might limit inadvertent flows of energy among control
areas, and that this laxity would impair reliability. This argument appears
to be backwards. Repayment in kind is a very generous rule, because it permits
the parties to schedule a time for repayment that is mutually agreeable. Adopting
a requirement to repay in cash on a timely basis would be more onerous and
would probably induce control-area utilities to take additional measures to
limit or control inadvertent energy.
Apart from the reliability issue, the parties have not raised sound reasons
why inadvertent energy should not be repaid in cash. In any system in which
generators owned by different parties are connected, there will be flows that
do not conform precisely to the delivery obligations of the owners of the
generators. The differences can arise from the inexact nature of load forecasting,
variations in generator output, metering and telemetry errors, time correction,
and other factors. The point of the proposed rule was to eliminate the disparity
in the treatment of control areas and other parties with respect to payment
for the energy they receive for any of these reasons. In a retail competition
arena, such as in the California market, these disparities are resolved through
a real-time energy market and an after-the-fact settlement process. In either
case, however, a party that receives power pays for it in cash. The commission
is modifying the proposed rule to simply require that inadvertent energy be
paid for by means of cash payments. The requirement that the schedule imbalance
service be used is being deleted.
San Antonio supported the provision of the proposed rule that any revenue
collected by transmission service providers from transmission customers for
exports of power from ERCOT on an unplanned or monthly, weekly, or daily basis
should be credited back to transmission customers who are taking annual planned
transmission service. According to HL&P it is not proper rate design to
simply divide the annual facilities charge by the number of weeks, days, or
hours in a year to arrive at rates for a shorter duration planned service,
since such a rate design implicitly assumes 100% load factor and would therefore
under-collect costs. If the commission decides to adopt shorter duration service,
rates should either be adjusted to account for a realistic load factor or
a methodology similar to monthly planned service would be needed.
The important criteria for pricing a short-term service are simplicity
and transparency, as TU Electric's reply comments suggest. The service is
a lower priority service than annual planned service, and it is not clear
what level of use participants in the market will make of it. There is not
any reason why the pricing should match every element of the pricing of annual
planned service. TU Electric has proposed a workable pricing scheme, based
on each utility's postage stamp rate component, with a customer paying a prorated
share of the annual rate for the megawatts that it proposes to transmit. Payment
would be on a take or pay basis. It seems likely that in periods in which
transmission paths are congested, persons seeking to ensure power delivery
for short-term sales would buy the short-term service and pay the facilities
charges, loss compensation, and the ISO fee. In periods in which transmission
paths are not congested, unplanned service would be available, with payment
of only loss compensation and the ERCOT ISO fee.
ANP proposed a minimum price for the short-term planned services, with
an auction conducted by the ISO for any service that is over-subscribed. An
auction would be a reasonable means of allocating the rights for such service,
where the value of the service can be expected to vary by time and load-resource
pairing. It is not clear, however, what level of administrative effort would
be required for the ISO to conduct such auctions. It seems likely that if
a short-term planned service is established with a fixed price, a secondary
market would develop for trading rights to service over congested paths, and
that market prices for the service would result. A secondary market is likely
to result in market values for the transmission rights, without imposing on
the ISO the burden of conducting an auction.
Independents and HL&P pointed out that the rates for a period overlapping
peak and off-peak months are not clear and lead to irrational results. Independents
suggested the following language be substituted: "If the sum of the access
fees for the requested months exceeds the annual rate, the total fee charged
shall not exceed the annual rate."
The comments concerning the charges for monthly planned service by Independents
and HL&P are correct. The sentence in the proposed rule that they commented
on is being removed from the rule. The modification being suggested by Independents
is not being adopted. Monthly service cannot be requested more than 30 days
before it is to begin, so it is difficult to see how the provision for multiple
months would be applied.
CITGO argued that the transmission rules should be modified to reduce barriers
to a single cogeneration plant supplying power to multiple industrial plants,
to waive transmission fees for industrial customers that serve as a thermal
host or are interconnected as a thermal host to a cogeneration project that
reduces transmission system loading, and to provide for ready dispatch of
generation facilities that are optimally sited and are most efficient.
Cogeneration facilities serving an industrial load near the cogeneration
facility have significant advantages with respect to the industrial load they
serve. The megawatt-mile impact of transmitting power to an adjacent industrial
load are either very small or are ignored in the ISO's impact calculations.
To the extent that cogeneration facilities also serve other loads that require
the use of the transmission system, the transmission charges should be calculated
in the same manner as transmission charges related to the delivery of power
from other generating facilities.
In the preamble to the proposed rule, the commission posed the following
question: Should the transition adjustment be discontinued or modified?
San Antonio, HL&P, TU Electric, Brownsville, Weatherford, and Granbury
stated that the transition mechanism should be continued. HL&P and TU
Electric argued that the transition mechanism was considered in the formulation
of the recent settlements approved by the commission. Brownsville, Weatherford,
and Granbury stated that they relied upon the transition mechanism in their
budget setting processes. These commenters accepted the commission's rule
and believed that there would be a three-year transition period. Eliminating
the third year of the transition would cause harm to those electric utilities
that entered into settlements approved by the commission and those that have
relied upon it to set operating budgets and make financial projections and
would increase regulatory uncertainty in Texas. TU Electric further commented
that the transition mechanism should be extended (in the event retail competition
legislation is adopted in the upcoming session of the Texas Legislature and
then only through the implementation date of such legislation) to continue
the smoothing of the transition to retail competition by eliminating the substantial
financial burden that the deficit utilities will otherwise experience in 2000
at the same time they will be heavily engaged in planning for the implementation
of retail competition.
Brazos, Garland, TNMP, and STEC stated that the transition mechanism should
be deleted from the proposed rule. TNMP and STEC argued that it is difficult
to implement and no longer necessary, and the burdens of implementing it far
outweigh the benefits that it provides. Consumer-Owned Power Systems argued
that the transition mechanism should not be continued in the third year, because
it has not accomplished any of the desired effects. The transmission-pricing
rule was intended to create a system that fairly compensated all transmission
owners and charged all customers on an equal basis. Delaying full implementation
of the pricing system delays fair transmission pricing. Garland commented
that the transition mechanism has always been unlawful and no longer has any
purpose, and should be eliminated. Also changes in load nominations have made
the transition mechanism calculations increasingly complex, resulting in confusion
and inordinate delays in the finalization of the annual transmission rates.
The CSW Companies noted that while subsection (a)(3) appeared to be an
attempt to clarify the application of the transition mechanism in 1999, by
its specificity it actually proposed a different method than the commission
applied in 1998 in its order in Docket Number 18459. The CSW Companies proposed
changes to subsection (a)(3) so that the transition mechanism is applied consistently
with the order in Docket Number 18459. Brazos objected to the CSW Companies'
proposed changes to the transition mechanism. It commented that the transition
mechanism has been used in its current form for two years and a revision would
only cause heavy delays and extensive relitigation. Garland and LCRA suggested
that the commission consider the language proposed by the CSW Companies if
the transition mechanism is continued.
The continuation of the transition mechanism is obviously a contentious
issue. The parties suggested options ranging from discontinuing the transmission
mechanism now to extending it beyond the time contemplated in the transmission
rule adopted in 1996. While some difficult issues have arisen in applying
the transition mechanism, it has served its intended effect of moderating
the impact of adopting a new transmission pricing mechanism. The comments
suggest that some utilities, relying on the terms of §23.67, have assumed
the continuation of the transition mechanism in their financial planning.
The commission concludes that conditions have not changed sufficiently to
warrant a removal of the transition mechanism, but that there has also not
been a showing made that it should be extended. With respect to the issue
raised by the CSW Companies, the commission construed the rule in Docket Number
18459 as requiring that the transition mechanism be calculated for each stage
of the transition period using the unadjusted rate impact from the 1997 transmission
charges. The modifications to the proposed rule suggested by the CSW Companies
would include this construction in the terms of the rule. Because the modification
is consistent with the commission's interpretation of the rule, it is adopted.
In the preamble to the proposed rule, the commission posed the following
questions: Is it appropriate to include the cost of a weather network in transmission
rates? Will including the costs of such a network in transmission rates afford
the commission an adequate opportunity to review a weather network and determine
whether the costs incurred in completing it are reasonable and necessary?
Brazos, the CSW Companies, HL&P, San Antonio TIEC, TNMP, and TU Electric
opposed the inclusion of MesoNet costs in a utility's TCOS. San Antonio stated
that an effort to mandate ERCOT-wide sharing of the costs of a statewide weather
data collection system in TCOS was premature. Many of these parties questioned
the nature and magnitude of any statewide benefit to the power market and
whether consumers of electricity should bear the costs. San Antonio, in particular,
urged that the benefits should be clearly explored and concretely identified
by ERCOT transmission service providers and the ISO before the costs should
be spread on a system-wide basis. Given the compressed time frame to which
the current rule revisions are subject, San Antonio expressed that this proceeding
was not the appropriate forum for this subject. The CSW Companies argued that
the proposal should be rejected, because it did not adequately consider spreading
the costs to other industries likely to benefit from the system. The Public
Counsel argued that before the costs of the MesoNet could be included in retail
rates, they would have to be shown to be reasonable in a rate case.
STEC supported the inclusion of the costs of a state-wide-data collection
network in an electric utility's wholesale transmission rates. Access by all
electric utilities and the ISO to the data collected through such a network
should be valuable in planning for the type of weather-related emergencies
that frequently occur in Texas. The commission would have the duty to review
the costs incurred by a utility in completing the weather network and to determine
whether the costs were reasonable and necessary. The commission should review
the costs during the utility's TCOS rate filing. Walter R. Anderson and Lee
Harrison, Meteorologists-in-Charge, respectively of the Lubbock and Shreveport
offices of the National Weather Service, supported the MesoNet project. They
expressed the view that this project would provide unparalleled opportunities
for many facets of our economy: from agriculture, fire, weather, and industrial
support to water management and improved forecasts for the general public.
Numerous individuals, particularly persons in weather-related professions,
filed letters supporting LCRA's proposal, arguing that MesoNet would provide
benefit to every electric utility customer in Texas. Litten PRC and Strategic
Partnerships, Inc. commented that the statewide network is vital to Texas.
Electric utility companies could more precisely anticipate peak requirements
and streamline their operations. The near real-time data would produce a new
weather awareness for a spectrum of applications: enhanced fire control, more
efficient use of water resources, and accurate records to quantify drought
severity. Weather forecasts could improve as much as 20-30%. The onset and
duration of wintertime storms would be more precisely forecast and the extreme
cold or ice storm events would be reliably assessed. The network would benefit
every customer of an electric utility in the state of Texas. LCRA replied
that none of the opposing commenters directly refuted the factual assertions
made by Dr. Sickler in his affidavit supporting the Petition. MesoNet will
provide Texas with more accurate and timely weather information, which will
improve load forecasts. Errors in load forecasts translate into higher cost
to electric consumers in that missed load forecasts have resulted in over-
committed or under-committed resources. In the case of over-committed resources,
such resources have been withheld from the market. In the case of under-committed
resources, resources have had to be obtained for the day, often at high market
prices. LCRA filed reply comments noting that while others will certainly
benefit from the MesoNet, all of those others are electric consumers and the
fact that they will benefit is no reason to exclude the costs from TCOS. Finally
LCRA argued that the MesoNet could ease the transition to retail competition.
The ISO and retail service providers will have to depend on hourly load profiles
for different customer classes instead of installing expensive real- time
meters for every load. These profiles will be the basis for scheduling generation
and for billing the majority of loads in ERCOT. It argued that the commission
should authorize implementation of the infrastructure now to allow its development
in time to support the market. Delay may cause large, unnecessary expenditures
for enhanced metering due to lack of faith in the weather-adjusted load profiles.
The letters in support of the weather-recording network make a convincing
case that weather forecasting will improve with the deployment of such a network
and that many Texas businesses will benefit from improved forecasting, including
electric utilities. The benefits are expected to be much broader than the
transmission system or the utility industry. It is not appropriate for the
costs of the network to be borne by transmission customers, absent a cooperative
effort by other users to share in the costs of this network. The commission
urges the proponents of this weather network to engage in discussions to seek
a funding mechanism that will result in a more equitable apportionment of
the costs of this system among those who will benefit from it.
Section 25.193: Procedures for Modifying Transmission
Rates
HL&P recommended deletion of §25.193(a)(4), which requires a transmission
service provider to notify affected persons of proposed changes in a transmission
tariff, since this provision could be used by a party claiming to be affected
but unknown to the utility and thwart the tariff-revision process. HL&P
claimed that it already engages in informal discussion with affected parties
in an effort to bring an acceptable tariff before the commission. Brazos proposed
that the commission permit recovery of additional transmission costs on a
more frequent basis than an annual update. Pedernales argued that §25.193(a)(2)
duplicates the CCN process and recommended that if the commission has already
directed the manner of construction and location of transmission facilities,
then the utility should not be required to carry any burden of proving that
the cost of such facilities is reasonable and necessary.
The requirement for advance notice and informal resolution of issues relating
to tariff changes is unnecessary, and it has been deleted. Initial transmission
rates were set in 1997, and no transmission service provider has requested
a change in its TCOS since then. There does not appear to be a need for an
adjustment to transmission rates more frequently than annually. The commission
typically reviews the reasonableness of invested capital after a facility
is put into service, because the review in a CCN proceeding is based on projected,
rather than actual, costs. The review of the reasonableness of costs that
is required in paragraph (a)(2) is consistent with PURA and current rate practices,
is not unduly duplicative, and is appropriate.
TU Electric strongly encouraged the commission to abandon the requirement
of charging transmission customers on the basis of a netting order issued
by the commission, in favor of traditional utility billing, where commission-established
rates are charged for actual billing units. According to TU Electric, the
process of obtaining a commission order is time consuming and costly and is
inconsistent with the concept of a vibrant, flexible competitive market. TU
Electric argued that if STEC and other cooperatives are concerned that without
the netting order their tax-exempt status will be jeopardized, the issue should
be revisited with these entities and unless they establish a need for a netting
order, this provision should be eliminated. STEC argued that the netting order
should remain in place, because small load entities do not have the internal
resources to know whether they are being charged the correct rate for transmission
service.
Transmission charges have been determined in consolidated proceedings for
1997 and 1998, primarily because the charges of all service providers and
customers are taken into account in applying the transition adjustment and
to permit the use of a netting order. The commission believes that once the
transition adjustment no longer applies, it will be more consistent with a
vibrant, flexible competitive market to apply each transmission service provider's
rates independently. In addition, the Treasury Department has adopted interim
regulations relating to utilities that use tax-exempt financing but are required
to offer open-access transmission service; these rules appear to alleviate
the risk of loss of tax-exempt status for obligations issued by such utilities.
For this reason, the netting order will not be used, once the provision relating
to the transition adjustment expires. Proposed §25.193(a) would have
required the commission to enter an order determining the transmission charges
on an annual basis. Based on TU Electric's comments, the commission is modifying
this provision to refer to the resolution of disputes concerning transmission
charges. In circumstances in which a utility has a tariff for transmission
service and there is no dispute about the ISO's determination of the billing
units for the service, a commission order is probably not necessary.
In the preamble to the proposed rule, the commission posed the following
question: §25.193(a) requires investor-owned electric utilities to update
their rates on an annual basis and permits other electric utilities to do
so. Is the distinction in this subsection appropriate? Can the objectives
be better achieved by a different rule? When should the annual updates under
this section be initiated?
San Antonio approved of the different treatment because of the jurisdictional
differences between these groups. CSW Companies, HL&P, TNMP, and TU Electric
disagreed with the difference in treatment. They argued that making annual
updates optional for all non-IOUs would imply that these utilities would file
to revise their rates when transmission costs go up but not when they go down,
which would lead to an overstated transmission cost. TNMP pointed out that
there are some non-IOU transmission service providers that have larger transmission
systems than some IOU transmission service providers.
Independents supported the proposed annual TCOS updates to reflect changes
in utilities' invested capital, depreciation, loads and megawatt-mile impact,
on the basis that the rule will encourage investment in transmission facilities.
TNMP, however, claimed that requiring transmission service providers to update
their TCOS on an annual basis imposes a large administrative cost burden both
for the commission and the IOUs. TNMP and TU Electric recommended that the
annual TCOS updates to be optional. TU Electric argued that earnings monitoring
would ensure against over-recovery for those who do not seek annual adjustments.
The CSW Companies suggested the use of an annual Transmission Provider Recovery
Factor to update transmission revenue requirement to reflect changes in invested
capital.
TU Electric argued against updating of billing units annually since this
would eliminate a source of funding (from revenue growth) for the transmission
providers to finance transmission expansion and would necessitate more frequent
TCOS filings. TNMP, however, recommended that transmission rates be adjusted
annually to account for changes in overall load on the ERCOT system. Consumer-Owned
Power Systems agreed with the proposal of updating transmission cost annually,
because that will prevent utilities from profiting from increases in transmission
rates related to load growth. At the same time, Consumer-Owned Power Systems
recommended reduction in the rate of return on the transmission investment
to reflect the reduced risk of revenue uncertainty and regulatory lag resulting
from the annual updates.
TIEC argued that annual transmission rate updates to reflect changes in
transmission investment will create significant instability in the transmission
rates; initially rates would rise, because additional transmission costs would
be incurred prior to the addition of loads, and later rates would fall, as
additional load materializes. TIEC recommended that the TCOS proceeding set
rates based on a three-year test-year. In the TIEC proposal, all costs would
be reconcilable later in a subsequent rate proceeding. Public Counsel suggested
that the total TCOS be updated, not just the invested capital. Garland recommended
that language be added to this section to allow utilities using the methods
allowed in §25.192(b)(3) and (4) to update their rates to reflect changes
in the debt service and coverage requirements and capital funding requirements.
As to when the annual updates should be initiated, TU Electric recommended
that the commission should ensure that the rule does not conflict with any
rate freezes under commission order.
As an additional response to various comments, the CSW Companies recommended
that the annual updates should be applicable to all transmission providers
and for all rate components (cost of service, loads, megawatt-mile inputs),
except the rate of return and the debt service coverage multiplier which would
be determined in a full transmission rate proceeding. The CSW Companies and
TU Electric opposed TIEC's proposal of setting rates on the basis of a three-year
test period. The CSW Companies asserted that it would result in over-recovery
for some and under-recovery for others. TU Electric opposed it because it
would be extremely cumbersome. TIEC recommended that if an annual update is
permitted (1) all transmission providers' cost of service should be updated;
(2) both loads and usage should be updated; (3) return of equity should be
adjusted for reduced risk of regulatory lag; and (4) changes in operating
costs should be recognized.
Section 25.193(a) of the proposed rule would require investor-owned electric
utilities to update their rates on an annual basis and permit other electric
utilities to do so. The rule was intended to recognize additions to invested
capital on an annual basis, in order to provide additional incentives to construct
new transmission facilities that are needed in ERCOT. At the same time, during
a period in which transmission additions are minimal and the use of existing
facilities is increasing, a mandatory annual update would benefit customers
by reducing transmission rates. In either instance, rates would closely track
costs for investor-owned utilities.
Equity considerations would support annual adjustments for all transmission
providers on the same basis, either mandatory or permissive. A mandatory annual
update was conceived as a means of having revenues closely track costs, whether
costs are rising or falling. Another mechanism for providing for revenues
to track costs is to adopt an earnings monitoring process for transmission
costs and revenues. This would permit a utility to make a filing that shows
its current costs and revenues, and if they are approximately in balance,
there would be no need for a change in its transmission rates. A permissive
annual update coupled with an earnings monitoring process would provide an
incentive to construct new transmission facilities, would be equitable among
the different kinds of utilities, permit revenues to track costs, and minimize
the administrative costs of rate changes. The commission is revising the rule
accordingly.
The other issue, if an annual update of the transmission rates is permitted
or required, is what may or must be updated. Including changes in billing
determinants in an annual update of TCOS would result in revenues closely
tracking costs, so that if use of the transmission system is rising faster
than the cost of providing transmission service, the restatement of the rates
to new billing determinants would bring the costs and revenues into a closer
match. If transmission rates must be updated on an annual basis to reflect
changes in invested capital, it would be logical to also update billing determinants,
so that cost and revenues would track more closely. If the annual update is
permissive, one source of additional transmission revenue would be regulatory
lag. In other words, a utility's transmission rate would remain in effect,
but its revenues would increase as billing determinants increase. This is
a source of funding for additional transmission facilities (or other cost
increases) that would not require a commission proceeding. With a permissive
annual update and a transmission earnings monitoring process, revenues and
costs might rise at similar rates, and no rate proceeding of any kind would
be required. If costs were rising faster than revenues, through the addition
of new transmission facilities, the utility could elect to file an update
of its transmission-related invested capital, and the commission would adjust
the rate to reflect the changes in invested capital and use of the transmission
system. Alternatively, the utility could file a transmission rate case in
which all costs and use of the system would be reflected in new transmission
rates. If revenues were rising faster than costs, the earnings monitoring
process would be relied on as a means of determining whether the utility's
rates should be reduced. For these reasons, the commission will require that
reductions in invested capital resulting from additional depreciation and
the retirement of facilities and the current level of billing determinants
be taken into consideration when a utility elects to update its rates to reflect
capital additions. The annual update will be limited to changes in invested
capital and billing determinants. This update is intended to be an expedited
means of recovering the costs of additional transmission facilities, and its
purpose would be thwarted if all costs were subject to review. The commission
is revising the rule to make it explicit that in the subsequent reconciliation,
any over-recovery of costs would be subject to refund.
In the preamble to the proposed rule, the commission posed the following
question: Is it appropriate and lawful to permit electric utilities to adopt
a retail rate factor that would permit them to pass through to their retail
customers changes in their wholesale transmission rates?
Consumers Union, OxyChem, Public Counsel, and TIEC claimed that a transmission
rate factor is not permitted under PURA (citing PURA §36.201 and §36.006).
Public Counsel argued that if the risk of regulatory lag is eliminated for
transmission service, the rate of return for transmission investment should
be reduced to a near risk- free rate. Public Counsel also pointed out that
automatic pass-through of any costs would reduce the utility's incentive to
control costs. Consumer Union, Public Counsel and TIEC argued that a retail
transmission cost recovery factor is not appropriate under the transition
plans agreed to by TU Electric and HL&P, where the base rates are not
supposed to increase during the terms of those agreements. TIEC also argued
that this issue need not be addressed now, since costs could not flow through
a factor until a new transmission investment is in service; by then retail
competition may be a reality in Texas and rules may need to be amended again.
HL&P, however, claimed that it is appropriate and lawful to have a
transmission rate factor. HL&P suggested three legal remedies to address
the timely recovery of additional transmission costs. (1) Transmission payments
to others are accounted for in FERC Account 565, which are eligible fuel costs
under Substantive Rule §23.23(b)(2)(B) of this title, and these costs
can be flowed through the fuel factor if the commission removes its exclusion
of these costs from eligible fuel costs. (2) The commission could also declare
the incremental transmission costs "eligible fuel" under the special circumstances
exception in §23.23. (3) Finally, under PURA §34.171, the commission
could provide an incentive to encourage purchase power and include these costs
in the fuel factor for timely recovery. CSW Companies also recommended a retail
transmission cost-recovery factor for recovery of updated facilities charges
from retail customers.
In reply comments, TIEC, Consumers Union, and Public Counsel questioned
the legality of HL&P's proposal for recovering incremental transmission
costs through the fixed fuel factor. Regarding HL&P's argument that timely
cost recovery of transmission cost would encourage power purchases, Public
Counsel argued that there is no evidence of such a relationship between the
two. TIEC also pointed out that the commission considered a similar issue
in Docket Number 17460, the recent fuel reconciliation case of Southwestern
Electric Power Company, and decided that even if the transmission equalization
payments were booked in FERC Account 565, they were not eligible fuel because
these payments included return on equity, and the costs were capacity related.
The same reasoning applies in this instance. TIEC also argued that recovering
transmission costs in fuel factor would have the effect of circumventing the
settlement of HL&P's transition plan.
Adopting a measure to permit changes in transmission costs to be recovered
more quickly from retail customers would be an important element in reducing
the burden of regulatory lag associated with additional transmission investments
and would provide additional incentive to transmission utilities to undertake
transmission projects. Without retail rate recovery, changes in transmission
rates would affect only the amounts recovered at the wholesale level. To the
extent that the commission adopts procedures to ensure close tracking of transmission
costs and revenues, there is little justification for requiring an additional
review before reflecting the costs in retail rates. With respect to the legal
issue, the commission agrees with HL&P's analysis that the commission
has the latitude to permit transmission costs to be recovered through the
fuel factor. The existing fuel rule, Substantive Rule §23.23, permits
transmission expenses to be recovered as fuel costs. There are practical impediments
to implementing a retail transmission factor immediately, however. First,
most of the large IOUs have not had a recent, thorough review of their costs
that included the unbundling of transmission costs from generation and distribution.
The initial TCOS cases reviewed the costs, but many of them were based on
cost-of-service information from prior retail rate cases, and this information
is now quite old. The transmission revenues from retail customers and transmission
costs may have changed significantly since the last retail rate case. The
other impediment is the rate freezes that HL&P, TU Electric and TNMP have
negotiated. Any retail transmission factor should not be inconsistent with
the rate freezes. The commission is adopting a retail transmission factor,
but it will not be implemented until a new TCOS case is conducted, and it
will not be inconsistent with any rate freeze that the commission has approved.
Section 25.194: Determining Peak Load and Megawatt-mile
Impacts
Brazos urged the commission to reexamine whether an additional working
group to participate with the ISO is needed. CSW Companies indicated that
subsection (a)(2) should refer to an "eligible transmission service customer."
HL&P proposed amending this section to lessen the administrative burden
and to clarify the required information. Independents and the CSW Companies
pointed out that to reflect the functional unbundling required by the rules,
"load serving entity" should be used instead of "electric utility" and applied
where appropriate in this section. TIEC submitted that retail customers should
also be represented in the working group, which would be consistent with proposed
§25.197(b).
The ISO has conducted its duties under this section with significant participation
by affected customers and service providers, and fundamental changes to the
process are not warranted. It is appropriate to permit any eligible customer
to make an objection while the ISO is developing the information, as proposed
by the CSW Companies. The commission has used generic terms, such as transmission
service provider and transmission service customer in this rule, and the revision
proposed by Independents and the CSW Companies is consistent with this approach.
The commission also concludes that retail consumers should be represented
at the ISO and on such committees as the working group referred to in this
section. The issue of their representation on the ISO governing body is discussed
in more detail in connection with the comments on 25.197.In response to a
comment from Brazos under §25.192, this section is being revised to require
that the load calculations be determined in a consistent manner, from one
transmission customer to another.
STEC suggested that only a portion of a generating unit for which the utility
has a contractual entitlement should be used in the calculation of megawatt-mile
transmission rates.
The approach suggested by STEC is reflected in §25.194(d) of the rule.
A resource nominated by a transmission service customer as a planned resource
must be one in which the customer has rights by contract or ownership. The
commission believes that the ISO, in performing its reliability function,
monitors the nominations to ensure that generation is not over-committed.
No explicit modification of the rules appears to be needed on this issue.
The CSW Companies commented that to ensure that the definition of transmission
facilities used in determining impact charges is not inconsistent with the
description of the facilities that are allowed in transmission rates, this
section should refer to Substantive Rule §25.192(b)(1)(A). STEC asserted
that transmission service customers that use a transmission service provider's
distribution line for the delivery of its power should be required to pay
for the impact that occurs on the distribution line. TU Electric proposed
language similar to that currently in Substantive Rule §23.70(o)(8) of
this title. TU Electric argued that such language is necessary in order to
complete the description of the megawatt-mile impact billing units and a transmission
customer's billing determinants.
The commission is not aware of problems that have arisen in the determination
of transmission impacts that would warrant the modification suggested by the
CSW Companies. With respect to STEC's comment, §25.191 requires utilities
to provide transmission service over distribution facilities, and the commission
has set rates for this service, where it is provided. There have not been
extensive comments filed on this issue in this proceeding, and the commission
concludes that it would not be appropriate to adopt more detailed provisions
concerning these rates on this record. TU Electric's suggestion appears to
be correct, and the rule has been modified to include the provision it refers
to.
Section 25.195: Terms and Conditions for Transmission
Service
Transmission service requirements
The Consumer-Owned Power Systems argued that the requirement that a transmission
customer negotiate an interconnection agreement with the transmission service
provider should be replaced with a reference to a standard agreement for interconnection.
Independents recommended that the term "control-area requirements" be defined
and subject to approval either by the commission or the ISO. Panda noted that
the proposed rule does not deal with start-up power and the possibility that
a utility might charge a rate that included a demand charge for start-up power.
Panda proposed that the rules be revised to require transmission service providers
to provide transmission service to transmit start-up power to a new generator
and to permit the new generator to repay the power in kind.
Another commenter also suggested that a standard interconnection agreement
be required, in comments relating to §25.191. Such a standard agreement
would facilitate the interconnection of new power generation projects, and
the commission will include such a requirement in the new rules. The additional
details on meeting control area responsibilities proposed by Independents
are not needed in the rules. The ISO has prescribed operating guides that
describe how a control area must operate. In addition, §25.201 provides
for the ISO to determine the adequacy of a transmission service customer's
arrangements for ancillary services. This arrangement permits oversight of
reliability functions by a neutral party, under the broad policy guidelines
prescribed by the commission, yet also permits the ISO and the industry to
respond quickly to changes in the market. Panda's suggestions relating to
start-up power are outside of the scope of the proposed rule and the questions
posed by the commission in publishing the rule. Other parties have not had
an adequate opportunity to comment on this proposal, and, for this reason,
it is not adopted.
Transmission service provider responsibilities
Duke argued that transmission service providers should be required to build
transmission facilities to accommodate requests for transmission service,
whether the service requested is planned or unplanned, if the ISO concludes
that the new facilities are reasonably necessary to serve the network generation
sources that are needed to service the projected loads in the area where the
new generation facility is to be located. TU Electric stated that given the
short timeline for submittal of annual resource nominations, the requirement
to build transmission capacity to satisfy resource nominations is impossible
to implement. The only practical solution to accommodate a nomination for
which transmission capacity does not exist is redispatch. In its reply comments,
TU Electric suggested that §25.195(b) be modified to make it clear that
a transmission service provider has an obligation to build, operate, and maintain
transmission facilities that are needed to relieve transmission constraints,
as recommended by the ISO. STEC suggested that the term "good utility practice,"
which is used in this section, be defined in this Subchapter.
With respect to the Duke proposal, §25.191(e)(4) of the rules requires
a transmission service provider to interconnect its facilities with a new
generating plant and construct interconnection facilities, without regard
to whether the new generating plant has requested planned transmission service.
The commission recognizes that additional transmission facilities may be required
to permit the power from a new generating plant to reach a broad market in
ERCOT. Rather than including a requirement that a transmission service provider
construct facilities to provide such access to the market, the commission
believes that the need for new transmission facilities should be considered
by the ISO and ultimately decided by the commission on a case-by-case basis.
It is possible that the developers of new generation plants will choose locations
for such plants that will require extensive transmission facilities in order
to reach significant markets in ERCOT. The commission has the responsibility
for determining whether new transmission facilities should be built, and the
certification process will permit it to determine the most cost-effective
means of meeting the State's power requirements. With regard to TU Electric's
comments concerning the impossibility of meeting the requirement to build
transmission capacity to satisfy resource nominations, the proposed rule requires
the utility to "endeavor to construct and place into service sufficient transmission
capacity to deliver power from the resources nominated by a transmission service
customer as planned resources to serve the customer's load." This requirement
recognizes that the transmission service provider may not always be able to
meet its customer's planned service requests. TU Electric's suggestion that
the rule recognize a transmission service provider's obligation to build,
operate, and maintain transmission facilities that are needed to relieve transmission
constraints, as recommended by the ISO, is being adopted, with a modification.
The commission has the responsibility for determining whether certain new
transmission facilities should be built, and the rule is being revised to
recognize this responsibility. "Good utility practice" is defined in §25.5
and need not be defined in this section.
Priority for transmission service applications
Brazos and Brownsville supported the priority of service rules in §25.195(d),
based on requests for planned or unplanned service. Brownsville argued, however,
that for areas with transmission import constraints, the priority rules should
be different, and each load-serving entity should have an equivalent right
to use the import capacity, based on its percentage of load in the import-constrained
area. The CSW Companies noted that the existing planned/unplanned distinction
does not support a flexible competitive market. They argued that a new system
should be adopted that permits generators to contract for firm, multi-year
service, without specifying a load, and that loads should be permitted to
contract for firm, multi-year service, without specifying a generator. They
also argued that the right of a transmission customer that is currently receiving
planned service to continue to receive service from a specific resource, if
the resource is shown in the customer's five-year forecast, should be expressly
stated in the rule. Duke argued that new generation plants should not be able
to gain priority to transmission service, merely by making a request for planned
transmission service. According to Duke, the priority of planned loads should
be relevant only among the network generation resources that are taken into
account in determining the scope of any necessary transmission upgrades.
Independents requested that the term "priority" be clarified; that the
rule should specify whether priority refers to obtaining transmission service
or retaining service rights when curtailments are required, or both. Independents,
Garland, Granbury, and Weatherford supported the proposed revision that would
grant a transmission customer priority to planned service when a resource
becomes unavailable due to an unplanned outage; they also suggested that this
priority be extended, so that a transmission customer that has paid for annual
planned transmission service would have priority in replacing a resource that
becomes unavailable for other reasons or when a transmission customer's long-term
contract with a resource provider expires. Garland and Granbury also recommended
that the priority rules be clarified, so that all requests for annual planned
service that are filed by the October 1 deadline would have equal priority.
Weatherford noted the importance that loads be assured that they would not
be squeezed out if transmission becomes constrained. TU Electric proposed
amending this subsection to clarify the meaning of "same transmission capacity"
in connection with the priority in transmitting power from a replacement resource,
and recommended that the commission leave implementation of the details to
the ERCOT ISO. In reply comments, Panda disagreed with CSW Companies' suggestion
that multi-year service be instituted. Panda argued that multi-year service
is unnecessary and would provide opportunities for market power abuse.
With respect to Brownsville's proposal, the ISO has implemented the current
rules by according equal priority to resource nominations filed by October
1. Where competing resource nominations are limited by a transmission constraint,
the ISO has, in effect, implemented a pro rata sharing of the existing transmission
facilities. The commission is modifying the proposed rules to recognize this
application of the rule, without being so specific as to limit the ISO's flexibility
in dealing with constraints. Priority applies both in obtaining service and
retaining it if there is a curtailment of service, and the commission is modifying
§25.200 to make it clear that the priority rules also apply in curtailment
situations. The commission is adopting the suggestion of Garland and Granbury
that the priority rules specify that all requests for annual planned service
that are filed by the October 1 deadline would have equal priority. The commission
is not adopting the suggestions of the CSW companies (1) that the rules permit
generators to contract for firm, multi-year service, without specifying a
load, (2) that loads should be permitted to contract for firm, multi-year
service, without specifying a generator, and (3) that a transmission customer
that is currently receiving planned service have a right to continued service
from a specific resource, if the resource is shown in the customer's five-year
forecast. Most of the commenters supported the existing rules for obtaining
transmission service and priority to service. There were a number of load-serving
utilities that expressed concern about granting firm transmission rights to
generators. They were concerned that giving generators such rights could impair
the ability of load-serving transmission customers to use the transmission
network to serve their retail customers. The first two CSW suggestions would
represent significant changes in how transmission rights are determined, for
which there has not been significant support in this rulemaking proceeding.
Based on the information provided in this proceeding and in the rulemaking
proceeding that the commission conducted in 1995 and 1996 in connection with
the original adoption of transmission rules, a transmission utility needs
to know the level of a transmission service customer's loads and the location
of the generation and loads, in order to plan and build adequate transmission
facilities to serve the customer's needs. The commission recognizes that new
planning methods need to be developed for a vibrant competitive market, but
the rights that the CSW Companies are seeking do not appear to be feasible
today. The third suggestion is also not adopted. The commission believes that
recognizing such a priority might impede the ability of new generation plants
to obtain customers and the transmission service needed to deliver power to
their customers. The Duke proposal also represents a significant change in
transmission rights that was not supported by other commenters. The Duke proposal
assumes that particular transmission upgrades are related to a generation
project; this approach is inconsistent with the fundamental assumption underlying
the rule that the ERCOT transmission system is a network that can simultaneously
serve multiple users. For this reason, the Duke proposal is not adopted. With
respect to the issue raised by Independents, Garland, Granbury, and Weatherford,
the commission is modifying the priority provision to permit a load-serving
transmission customer to change resources in the event of an unplanned outage
or termination of a contract with a planned resource. If the transmission
customer changes resources in these circumstances, it will be able to obtain
planned transmission service for the replacement resource. The commission
is not adopting TU Electric's suggestion that it define "the same transmission
capacity." The concept that is being adopted is that the replacement resource
should be located in the same area and use the same transmission facilities
as the original resource to deliver power to the load, so that the change
in resources does not affect constrained facilities or create additional constraints.
The details of implementing this provision will be left to the ISO.
New construction
LCRA also argued that if the commission requires a generator to bear the
costs of direct interconnection with the transmission grid, it should create
an exception for renewable resources, which typically require long radial
transmission lines to connect to the grid. In reply comments, Independents
supported this approach. Independents and OxyChem argued that the provision
on system upgrades in §25.195(e) should be revised to prohibit a transmission
provider from charging the carrying costs of such upgrades to the developer
of a merchant power plant. In its reply comments, HL&P took issue with
these parties.
The commission is adopting a requirement that transmission service providers
construct the facilities to interconnect new resources to the transmission
network, except for step-up transformers and a protective device at the point
of interconnection. Thus, specific provisions to interconnect renewable resources
are not needed in the rule. The transmission service provider, under this
rule, has the obligation to plan and construct new interconnection facilities.
The construction obligation includes the obligation to finance new facilities.
The rate provisions in §25.193 are intended to permit transmission service
providers to obtain rate recognition of new transmission facilities more quickly
than under current rules. In these circumstances, the transmission service
provider should not be permitted to charge the developer of a power plant
for the carrying costs of new transmission facilities.
The CSW Companies argued that proposed §25.195(e) should be revised
to make it clear that the ISO determines whether new transmission facilities
should be built to accommodate a request for transmission service. According
to the CSW Companies, placing this responsibility in the ISO would eliminate
bias and claims of bias in this decision. They also proposed that this subsection
make it clear that it applies both to requests for interconnection and transmission
service. Duke supported the idea of a "study group," so that where a power-plant
developer requests a transmission study for the new plant, other developers
would have a 90-day window to file a request for inclusion in the study. Independents
urged the commission to require utilities to file interconnection tariffs
or to develop a standard interconnection agreement. Garland argued that a
municipal utility should not be required to construct or acquire new transmission
facilities if doing so would impair the tax-exempt status of its bonds. HL&P
argued that a transmission service provider should not be required to acquire
new facilities for all transmission service requests, but only for requests
for annual planned service, to interconnect a new generator, or for projects
to enhance reliability or relieve congestion that have been approved by the
ISO. HL&P also argued that the obligation to acquire new facilities should
not be conditioned on the unavailability of redispatch or other more economical
means of making transmission capacity available. According to HL&P, this
requirement is inconsistent with functional unbundling and represents an inappropriate
requirement to curtail one planned transmission service request in favor of
another. HL&P expressed the view that a more practical way to manage congestion
is needed. Pedernales urged the commission to streamline the processing of
applications for certificates of convenience and necessity for new transmission
lines.
The commission, for the reasons noted by the CSW Companies, is modifying
other sections of the proposed rule to make it clear that the ISO has a significant
role in connection with requests for interconnection of new generation projects.
The specific proposal of CSW is not adopted, however, because it is the commission
that will have to determine whether new transmission facilities must be constructed.
The commission is not adopting the concept of a "study group" as suggested
by Duke. The disclosure of the existence of projects under development is
also inconsistent with a competitive market for the development of power projects.
The ISO should have the discretion to decide whether interconnection of new
power projects should be studied on an individual basis or collectively, based
on the facts of the particular case and the timing of the requests. The commission
is adopting Independents' suggestion to require transmission service providers
to develop a standard interconnection agreement. This requirement is set out
in §25.195(a). This will facilitate the interconnection of new generation
projects and foster competition in the wholesale market. With respect to Garland's
suggestion that municipal utilities not be required to build new facilities
if doing so would imperil their tax-exempt status, it appears that the Treasury
Department has recognized the impact of open-access transmission service.
It has adopted a temporary rule that will preserve the tax-exempt obligations
of municipal utilities that are required to provide such service. The rules
being adopted by the commission also recognize that a municipal utility may
require a contribution in aid of construction in connection with new facilities.
Such a contribution represents financial support for a transmission project
that is provided to the transmission provider by the transmission customer.
For these reasons, Garland's suggestion is not adopted. The commission is
not adopting the limitation suggested by HL&P on the obligation to acquire
new facilities. The circumstances they suggest are the ones in which the obligation
to acquire new facilities is most likely to arise, but there may be other
circumstances that are difficult to anticipate now in which such an obligation
would be appropriate. The commission is also retaining the language concerning
redispatch. As drafted, this provision requires the ISO to look for a more
economical solution than the acquisition of new transmission facilities. Because
the ISO is comparing the alternatives, it does not undermine the functional
unbundling provisions in the rules. The commission is adopting weekly and
daily planned service, which may provide a means of managing congestion. The
commission recognizes that these services may not be adequate to deal with
the congestion issues that are emerging, but there has not been sufficient
discussion and analysis of congestion management to adopt a more comprehensive
system now. With respect to Pedernales' suggestion, the commission has adopted
in this rule and has adopted in Project Number 17961, new §25.101 of
this title (relating to Certification Criteria), measures to expedite the
consideration of CCNs for new transmission facilities.
Deposit
In connection with the requirement to make a deposit to cover the cost
related to planning and licensing new transmission facilities, ANP proposed
that the refund of any deposit include interest on the deposit at a commercially
reasonable rate. The CSW Companies, the Consumer-Owned Power Systems, HL&P
and STEC proposed that the deposit required in this section cover costs incurred
by a transmission service provider for construction, in addition to planning
and licensing. LCRA argued that a bond or letter of credit should be required
from a developer of a merchant plant to demonstrate its commitment to a project.
USGen supported the deposit requirement as a means of distinguishing serious
generation projects from speculative projects.
The deposit requirement is intended to protect a transmission service provider
from incurring costs for a transmission project that becomes unnecessary because
a power plant developer requests and an interconnection for which additional
transmission facilities are needed and then abandons the project. If a transmission
service provider has proceeded with planning, licensing, and construction,
and the project is later abandoned, the deposit requirement will give the
transmission service provider security for collecting its costs from the developer
of the generation project. The suggestions that the deposit should cover construction
costs, in addition to planning and licensing costs, and that the transmission
service provider should be required to refund the deposit with interest if
the generation project is completed, make sense and are being included in
the rule.
Contribution in aid of construction
Austin proposed that the ISO determine which party benefits from additional
transmission facilities, in applying the "benefits" test to determine whether
a contribution in aid of construction (CIAC) is required. Brazos proposed
that the rules be revised to permit a utility that borrows from the Rural
Utility Service (RUS) to require a CIAC if it is not able to obtain RUS approval
for a project. Brownsville argued that the CIAC provisions are discriminatory,
in that the rules do not permit an entity that owns no transmission to recover
a transmission-related cost. A number of commenters proposed that CIAC be
eliminated, that the "benefits" test be eliminated, or that the circumstances
in which a CIAC is permitted be limited, for example, to circumstances in
which it is required to preserve a utility's tax-exempt status. These commenters
argued that the "benefits" test in the proposed rule introduces too much uncertainty
to be workable in a competitive environment and operates to discriminate against
certain transmission service customers. The commenters that opposed the proposed
provisions on CIAC include the CSW Companies, Garland, Granbury, HL&P,
Independents, OxyChem, TIEC, and Weatherford. In addition, Brownsville, Garland,
and Granbury urged that the rule be revised to impose on a transmission service
provider the obligation to acquire new transmission facilities to accommodate
the load growth of a transmission service customer and eliminate CIACs in
the case of transmission system upgrades that are made to support a load-serving
entity. Brownsville argued that CIACs should be limited to interconnections
and distribution system upgrades. The Consumer-Owned Power Systems argued
that where ERCOT transmission upgrades are needed for a new power plant that
can deliver power either into ERCOT or another area, it should be required
to provide a CIAC or enter a long-term agreement to provide power in ERCOT.
HL&P noted an inconsistency between §25.195(e)(1) and (e)(2) with
respect to the requirement to pay a CIAC. It argued that the same approach
should be used for ancillary services and interconnecting new generators.
Pedernales urged that the rule be modified to provide that a transmission
service provider is not responsible for the costs of new transmission facilities
if the acquisition of the facilities would impair the status of tax- exempt
bonds issued by the service provider.
Based on the comments, the commission concludes that the provision concerning
CIACs in aid of construction should be limited to circumstances in which a
CIAC would preserve the tax-exempt status of obligations issued by the transmission
service provider. Disputes over the CIAC requirement, as the commenters noted,
would be likely to impede the construction of new transmission facilities
in a competitive environment and the requirement might result in different
treatment of facilities built to interconnect new generators and facilities
built to serve loads. The commission has adopted a "bright line" distinction
between a generator and the transmission system, in setting out a transmission
service provider's responsibility to build new interconnection facilities
and system upgrades necessary to accommodate a new generating facility, and
it believes that clear distinctions are needed in determining cost responsibilities
for construction of new facilities built to serve load. With regard to the
comments of Brownsville, Garland, and Granbury urging that the rule impose
on a transmission service provider the obligation to acquire new transmission
facilities to accommodate the load growth of a transmission service customer,
the proposed rule includes such an obligation in §25.195(b). The commission
does not agree that the rule should be amended to eliminate a transmission
service provider's obligation to construct new facilities, if the construction
would impair the tax-exempt status of obligations issued by the provider.
The provision for a CIAC in these circumstances should be adequate to protect
the status of such obligations.
Curtailment of service
In connection with the curtailment rules in §25.195(f), ANP proposed
that interruption be based on operational factors and economic factors, rather
than simply economic factors, as proposed in the published rule. The CSW Companies
expressed the view that the obligation to redispatch should apply to monthly
planned service. They also argued that the transmission providers should retain
authority and responsibility to curtail transmission service, if good utility
practice dictates. They noted that such curtailment may be necessary to prevent
damage to equipment. San Antonio expressed a similar view, recommending that
control-area operators have concurrent power with the ISO to curtail transmission
service, in accordance with standards prescribed by the ISO. Koch suggested
that the rule make it clear that it is the ISO that determines whether there
is an emergency that requires curtailment of transmission service. It also
noted that §25.200(d) permits a transmission service provider to curtail
transmission service in certain circumstances. It recommended that these circumstances
be specific and narrowly defined. STEC noted that the rule requires control-area
utilities to provide notice of interruptions of transmission service to affected
wholesale and transmission customers. STEC suggested that the ISO is in a
better position to have this information and provide the notice.
Comments concerning curtailment of service were also filed in connection
with proposed §25.200, and additional discussion of this issue is set
out in the commission's discussion of that section. The proposed rule prescribes
that the ISO is responsible for curtailment. There may be instances in which
it is appropriate for transmission service providers to curtail service immediately
and notify the ISO, rather than obtain permission first. This is an area in
which the ISO has the authority to adopt and carry out procedures affecting
the reliability of the network, and in which the details of these procedures
do not need to be included in this rule. To make the rules easier to use and
reduce the possibility of inconsistent application, most of §25.195 relating
to curtailment is being moved to 25.200.The ANP suggestion appears to be unnecessary.
Any redispatch or restoration of service will necessarily take into account
operational factors, and this need not be stated in the rule. The rule does
not preclude the use of redispatch for monthly planned service, and there
does not appear to be any reason why it should be specified in the rule. A
transmission provider has the authority to curtail transmission service under
§25.200, and the integration of these sections should eliminate any uncertainty
about this matter. Section 25.200 also sets out the responsibilities for providing
notification of an interruption of service. This is an area where the ISO
may implement more detailed procedures, based on reliability requirements
and the needs of the market.
Filing of contracts
Panda urged that the provision on confidentiality of contracts be strengthened
by referring to "sensitive commercial or financial information" in §25.195(g).
The commission is revising this provision as suggested by Panda.
Section 25.196: Functional Unbundling
Cost separation
The CSW Companies argued that the cost unbundling provisions are unnecessary,
in view of the commission's adoption of Substantive Rule §25.221 of this
title. Consumers Union argued that the proposed rule gives utilities too much
latitude in how to unbundle their costs and recommended that the commission
clarify the relationship between this rule and the rules adopted in Project
Number 16536. Austin and San Antonio opposed the application of the unbundling
rules to municipally-owned utilities, arguing that the commission does not
have the authority to impose this requirement on such utilities.
The commission agrees that with respect to utilities to which §25.221
applies, the cost unbundling requirement in that rule is adequate and need
not be repeated here. For other utilities, the cost separation requirement
in this section is retained. Municipal utilities are required to unbundle
their costs in setting transmission rates.
Separation of functions
ANP supported unbundling generation and transmission and giving the ISO
more authority to determine whether new generators can interconnect with the
transmission system. Brazos argued that the unbundling provisions should be
clarified; where employees are prohibited from conducting reliability and
merchant functions, reliability functions should be defined to exclude generation-related
reliability functions. Brownsville supported structural unbundling, rather
than functional unbundling, as the appropriate means of controlling market
power. HL&P opposed the revision that would limit the application of the
functional unbundling requirement to control-area utilities. It argued that
this requirement should apply to any utility that sells bulk power in the
wholesale market. USGen supported incentives that would induce integrated
utilities to divest assets to reduce market power problems.
The issue of structural unbundling is beyond the scope of this rule, except
as this section adopts unbundling measures to preclude discriminatory conduct.
Where transmission and generation continue to be owned by integrated companies,
functional unbundling rules are essential to afford all generation providers
a reasonable opportunity to compete. The unbundling rules are primarily intended
to ensure that information that a transmission service customer provides to
a transmission service provider is not improperly shared with a generation
company in the same utility. A customer inquiring about transmission service,
for example, may provide sensitive information about its plans to develop
a power plant or about the customers it seeks to serve. The transmission service
provider may have a legitimate need for this information in providing transmission
service, but significant competitive harm could result if the information
were shared with the power marketing or generation operations with which the
transmission service provider is allied. The commission concludes that these
concerns are most pronounced with respect to utilities that operate control
areas, and it is adopting unbundling rules that will apply to control-area
utilities, permitting it to focus its enforcement efforts on control-area
utilities.
Standards of conduct
Consumers Union supported the standards of conduct in the proposed rule.
Independents argued that the commission should review the functional unbundling
plans filed by utilities, and that utilities subject to this provision be
required to obtain approval of an amendment of the unbundling plan prior to
implementing a restructuring that affects the functions that are required
to be unbundled. Wholesale Competitors argued that the functional unbundling
required by the rule is insufficient to ensure vigorous wholesale competition
and that the commission should require structural separation of the vertically
integrated utilities into affiliated companies and adopt strict standards
of conduct. STEC urged that the rule be revised to recognize that during an
emergency curtailment, the communications rules in this section do not apply.
The issue of structural unbundling is addressed above. As to the concern
raised by STEC, the commission believes that the ISO has adequate latitude
in adopting reliability standards to address the matter of communications
during emergencies.
In the preamble to the proposed rule, the commission posed the following
question: §25.196 prohibits utilities and their affiliates from building
power plants in their service areas, as a means of precluding discriminatory
conduct by a transmission service provider. Will this prohibition be effective
and are there are other means to achieve the same end that would be either
more effective or less intrusive?
Austin, after noting that this prohibition does not apply to municipally-owned
utilities, opposed the adoption of the prohibition. It argued that such a
prohibition would result in inefficient locational price signals and that
the possibility of discrimination can be addressed adequately through assigning
the ISO the responsibility of performing security studies associated with
new generation projects. The CSW Companies, CSW Energy, HL&P, and TU Electric
opposed this prohibition, arguing that it is beyond the commission's authority.
The CSW Companies and CSW Energy argued that exempt wholesale generators are
authorized by PURA to compete to sell power, and that the commission has no
authority to limit the location of their generating facilities. They also
argue that the provision is anti-competitive, because it limits how one group
of generating entities may compete to sell power, and that the problem of
discrimination in obtaining transmission service and interconnection should
be addressed through the rules relating to interconnection of new generators
and applying for transmission service. (The CSW Companies noted that they
did not object to this prohibition, insofar as it related to a utility.) CSW
Energy also argued that the rule, if adopted, must be construed as not applying
retroactively. Thus, the rule would not affect generating facilities that
are already in operation, and CSW Energy argued that it would be unfair to
apply the rule to generating facilities that are under construction or for
where a person has entered an agreement to construct or sell the output of
a generating facility. HL&P and TU Electric argued that the commission's
authority with respect to affiliates is limited to the power over specific
transactions, as set out in PURA §14.154, and that the resource-planning
provisions of PURA do not grant the commission such authority. HL&P also
argued that the prohibition is contrary to rights granted to qualifying facilities
under the Public Utility Regulatory Policies Act (PURPA), a Federal statute.
HL&P also argued that the notice of the proposed rule is deficient, with
respect to this issue. TIEC also asserted that this provision of the rule
runs afoul of PURPA. Furthermore, TIEC believed that this prohibition would
be unfair to companies who complied with the current regulations when solicitations
were issued. TIEC recommended that if the commission retains this provision,
a grandfather provision should apply to situations in which a request for
proposals was issued on or before October 9, 1998. TNMP viewed this prohibition
as too broad and unnecessary. TNMP offered as an alternative the commission
prohibit a utility from including in its costs to customers the cost of investing
in, or purchasing from, the new facility without approval through an integrated
resource planning or rate case proceeding.
Independents and Koch argued that the prohibition should be adopted, because
integrated utilities have both motive and opportunity to impede the interconnection
of new independent generating plants in their service areas. Independents
also argued that the commission has adequate authority to adopt such a prohibition,
to promote wholesale competition. They also argued that the rule should be
revised to require utilities to auction off land and associated water rights
in their service areas that were obtained in the expectation of building new
power plants. Alternatively, they recommend that the responsibility for planning
transmission and performing interconnection studies be transferred to the
ISO. Panda also supported the proposed rule. STEC argued that the prohibition
in this section is inadequate to prevent the large utilities in ERCOT from
exercising undue market power; it recommended, instead, divestiture of generation
assets.
The proposed rule prohibited utilities and their affiliates from building
power plants in their service areas, unless the plant is approved through
the integrated resource planning process. The preamble also posed the question
of whether there are other means to achieve the same end that would be either
more effective or less intrusive. The problem addressed by this provision
is discriminatory conduct on the part of a utility that is both a transmission
service provider and a developer of new power plants (either through the generation
function of the utility or through an affiliated non-utility power producer).
Under the current rule and practices, if a generation developer proposes a
new project that will connect to the utility's transmission lines, the utility
must conduct studies to determine whether the interconnection is feasible
and the nature and cost of the additional facilities that will be required
to make a safe, reliable interconnection. The commission is concerned that
the transmission service provider might discriminate against a developer of
a power plant with which it has no common ownership and favor a developer
with which it has some degree of common ownership (whether in the same company
or in an affiliated company). The prohibition in the proposed rule was intended
to preclude discriminatory conduct by a transmission service provider in these
circumstances, by eliminating the motive for the transmission service provider
to favor its own generation function or generation affiliate. Thus, it would
not have a reason to discriminate against a third-party developer.
The issue of discrimination on the part of a transmission service provider
was raised by a developer of a power plant that has had difficulties in getting
transmission studies completed and an interconnection agreement negotiated.
The developer, in order to build and operate the new power plant, must interconnect
it to the transmission network, so that power from the plant can be delivered
to customers. It seemed plausible that discriminatory animus on the part of
the transmission service provider lay behind the developer's difficulties,
because a company that was affiliated with the transmission service provider
was also planning to build a new generation plant in the same general area.
Thus, two developers were trying to build in an area and were competing to
obtain an interconnection with the same transmission service provider and,
ultimately, to sell power to customers. The developer that is affiliated with
the transmission service provider appeared to be getting the cooperation of
the transmission service provider, while the unaffiliated company did not
appear to be getting such cooperation. Moreover, the security study, the first
step in determining whether new facilities are needed to interconnect a new
generator, was not completed in the time required by the existing transmission
rules.
The commission was sufficiently concerned about the matter that it initiated
informal discussions among affected persons to attempt to resolve the matter.
These initial discussions resulted in a commitment by the transmission service
provider to carry out the tasks necessary to interconnect the power plant
of the non-affiliated developer. Subsequently, when it again appeared that
the transmission service provider was impeding the efforts of the non-affiliated
developer to obtain an interconnection agreement, the commission opened an
investigation of the transmission service provider's conduct in connection
with this matter. The transmission service operation of an integrated utility
has a motive and opportunity for discriminatory conduct in these circumstances,
because impeding the interconnection of a new power plant will preclude a
new competitor for the generating function of the utility. This motive and
opportunity are greater where, as in the case described above, the utility
also has an affiliate that is developing a power plant in the utility's service
area. The provisions that are being adopted to prevent discrimination are
not based on mere possibilities, however. The developer discussed above has
spent resources on appeals to the commission and communications with the transmission
service provider over a matter that should be routine. The events also suggest
that the transmission service provider has impeded the developer in its efforts
to finance and build a new power plant as it wished. Because the developer
has had to make appeals to the commission, the matter has become publicly
known and may have led other developers to conclude that ERCOT is not a market
that is receptive to new investment in generation facilities by independent
companies. To meet the legislative objective of a vibrant wholesale market,
independent companies need the assurance that their efforts to develop generation
projects in Texas will be handled fairly by integrated utilities.
The proposed rule would have prohibited a utility or its affiliate from
constructing a new power plant in the utility's service area, unless the plant
was approved by the commission. The following are alternative measures that
could facilitate expeditious interconnection of new resources: (1) adopting
a standard interconnection agreement; (2) devoting additional resources to
discrimination issues, including reviewing utility codes of conduct, auditing
their adherence to the codes of conduct, and monitoring the progress of all
interconnection requests; (3) assigning the ISO a greater role in connection
with the studies related to interconnection of new resources; (4) prohibiting
the construction of a power plant by an affiliate in a utility's service territory,
unless the utility has structurally unbundled and committed to comply with
a code of conduct, (5) including a prohibition on the construction of new
generating facilities in the rule as a penalty that may be imposed by the
commission, if it determines that a utility has violated the code of conduct,
and (6) prohibiting an electric utility from buying power from the affiliated
company that owns a generating facility in the utility's retail service area,
either directly or through a power marketer. The commission could, of course,
adopt the rule as proposed. Measures that are less intrusive than the prohibition
on construction that was proposed in the rule may be effective in controlling
anti-competitive conduct by integrated utilities. The commission believes
that these less intrusive measures should be tried first, but it is determined
that discrimination by transmission service providers not be tolerated.
The commission has the authority to adopt each of these measures under
its authority to adopt rules that are reasonably required in the exercise
of its powers and jurisdiction and to regulate and supervise the business
of each public utility under its jurisdiction. Texas Utilities Code, §14.001,
§14.002. These general provisions of the Texas Utilities Code give the
commission the authority to adopt rules to enforce more specific standards
that are applicable to utilities under other provisions of the Utilities Code,
including (1) the prohibition against utilities granting undue preferences,
in §35.003 and §38.021 and (2) the prohibition against utilities
discriminating against a competitor or engaging in conduct that impairs competition,
in §38.022. The provisions that are being adopted in this rule are also
essential, in the commission's judgment, to ensure that transmission service
is provided on a non-discriminatory basis, as required by §35.004. The
commission has the authority to adopt rules relating to wholesale transmission
service under §35.006.
Some of the parties that filed comments cited provisions of law relating
to the rights of qualifying facilities and exempt wholesale generators; they
argued that the rights granted under federal or state law preclude the commission
from adopting the prohibition in the proposed rule. The commission concludes
that the provisions of law cited by these parties do not preclude the adoption
of this rule or the prohibition that was included in the proposed rule. The
rights granted under federal or state law are not absolute but are subject
to other provisions of law. In particular, qualifying facilities are subject
to regulation by both the FERC and state commissions. Texas Utilities Code
§35.061 directs the commission to adopt and enforce rules to encourage
the economical production of electrical energy by qualifying facilities. In
adopting this rule, the commission must balance the objectives of encouraging
the economical production of electrical energy by qualifying facilities and
preventing discrimination in the wholesale market. Neither of these statutory
objectives is absolute or over-rides the other, and the commission considers
that the rule that it is adopting is a reasonable balance of the two objectives.
Qualifying facilities that are not affiliated with a Texas electric utility
are not subject to any new prohibition and are free to pursue development
plans as they have in the past. Moreover, the adoption of this rule will give
greater assurance to other persons seeking to develop a qualifying facility
that they will be able to obtain transmission service from a utility on non-discriminatory
terms. It will, therefore, foster development of qualifying facilities by
persons other than companies that are affiliated with the utility.
Similarly, exempt wholesale generators have the right under Texas Utilities
Code §35.031 to sell electricity at wholesale. Section 35.033 explicitly
recognizes the right of an exempt wholesale generator that is affiliated with
an electric utility to sell energy to the electric utility with which it is
affiliated "in accordance with Chapter 34 and other laws governing wholesale
sales of electric energy." This section grants the exempt wholesale generator
the right to sell energy to the affiliated electric utility but also recognizes
that the right is subject to other law. These other laws include the prohibitions
against discrimination and anti-competitive conduct that are referred to above.
The right to sell energy to an affiliated utility is thus subject to reasonable
rules adopted by the commission to prevent discrimination by utilities and
to foster competition in the wholesale market.
The prohibitions that the commission is adopting are narrowly drawn to
remove the motive and opportunity for integrated electric utilities to discriminate
against persons who seek to develop new generating plants in their service
areas. To the extent that an affiliate of a utility has assembled the personnel
and other resources to develop power generation projects, it may use these
personnel and resources in other areas of the state or outside of Texas. The
holding companies that own utilities in Texas have invested billions of dollars
in electric facilities in other states and in Europe, Australia, and South
America. The prohibition on developing new projects applies only within the
utility's service area, and it is not applicable if the utility separates
its generation and transmission functions and obtains commission approval
of its code of conduct. The rule does not unduly limit the participants in
the wholesale market, as some have suggested. The effect of the rule is to
remove from the universe of potential competitors to build a new power plant
in an area a company that is affiliated with the utility that is providing
retail service in the area. A number of companies are actively developing
power plants in Texas today, and most of them are not affiliated with Texas
electric utilities. For example, projects have been announced by the following
companies: Duke Energy Services, American National Power, Calpine, Panda Energy,
U.S. Generating Company, Tenaska, and Tractabel. While prohibiting affiliates
of the utility from building a plant in the utility's service area might reduce
the universe of competitors by one, there are still a number of developers
that are active in Texas. Reducing the opportunities for discrimination on
the part of the transmission service provider should significantly enhance
competition. Nor is the prohibition on sales unduly restrictive. This prohibition
will preclude sales only to a portion of the market of potential buyers.
The commission is adopting the following measures in this rule: (1) requiring
a standard interconnection agreement; (2) assigning the ISO a greater role
in connection with the studies related to interconnection of new resources;
(3) prohibiting the construction of a power plant by an affiliate in a utility's
service territory, unless the utility has structurally unbundled and committed
to comply with a code of conduct, (4) including a prohibition on the construction
of new generating facilities in the rule as a penalty that may be imposed
by the commission, if it determines that a utility has violated the code of
conduct, and (5) prohibiting an electric utility from buying power from the
affiliated company that owns a generating facility in the utility's retail
service area, either directly or through a power marketer. The foregoing provisions
are included in §§25.197, 25.196(b)(3)-(6), and 25.198(c)(5) and
(f).
Section 25.197: ERCOT Independent System Operator
Numerous parties expressed opinions regarding whether the ISO governing
board should include retail customer representation, an issue raised in §25.197(b).
Public Counsel, Consumers Union, OxyChem, TIEC, and, initially, STEC, supported
some form of retail customer representation on the governing board. Consumers
Union, arguing for the greatest degree of representation, contended that retail
representatives should be equal in number to the total number of voting wholesale
class representatives, and that the board should be reduced in size to twelve
members (six voting representing the retail class, and six representing the
wholesale class). Consumers Union also argued that three of the retail representatives
should be drawn from the residential class of retail customers, one of which
would be Public Counsel. Public Counsel and TIEC agreed that retail customers
should be represented on the governing board, but did not suggest the level
of detail argued by Consumers Union. For example, TIEC argued for three retail
customer representatives, and that the major retail customer groups (Public
Counsel, TIEC, commercial customers, etc.) should collaborate to choose the
three retail representatives. STEC argued that if retail representation is
adopted, the representatives should (1) represent separate customer classes,
(2) represent urban and rural areas throughout ERCOT, and (3) not be selected
by special interest groups. STEC opposed permitting the Public Counsel or
an interest group like Consumers Union on the board, because they are not
broadly representative of the customers in ERCOT. Public Counsel stated that
it should be included on the board now, because it is charged by law with
representing the interests of residential and commercial customers, and that
the representation of retail customers on the board should be expanded when
retail competition is enacted by the Legislature.
ERCOT, HL&P, CSW Companies, TU Electric, Brazos, Independents, and
San Antonio opposed the proposal to include retail representatives on the
ISO governing board, each arguing that ERCOT does not yet deal with the retail
market, and that it is premature expand the governing board to include retail
customers before the Legislature acts to adopt retail choice. More specifically,
ERCOT stated that (1) the addition of a seventh market group (the retail customers)
to the board would upset the balance and set back the progress that ERCOT
has worked to create; (2) retail customers are already represented through
the
ex officio
membership of the commission
and Public Counsel; and (3) there is no need for specific retail customer
representation at this time because retail access has not yet been authorized.
Moreover, ERCOT claimed that only the large industrial retail customers are
organized and in a position to participate on the board, which would leave
the residential and commercial customers unrepresented. San Antonio commented
that the board presently includes entities that service retail load solely
or primarily, and that the retail load is so diverse that it would be virtually
impossible to ensure adequate representation without making the size of the
board unwieldy, or having retail representation dominated by a single segment.
HL&P and TU Electric indicated that the inclusion of retail representation
on the board would be reasonable (or helpful) upon the effective date of retail
competition, but is not necessary or desirable while the competitive market
is strictly wholesale. Brazos suggested that the commission should instead
ask ERCOT for comments on how ERCOT can function best and then either approve
or deny suggested modifications to ERCOT. The Independents suggested that
the retail customers could be allowed to attend and participate in ERCOT committee
meetings without having a vote.
The commission concludes that the ISO governing board should be expanded
to include voting representatives of retail customers, who shall have the
same level of representation as the other market groups. One of the retail
members will be the Public Utility Counsel or her designee. Two other new
members will be selected by and represent the retail customer classes. The
current governing board of the ISO shall consult with members of organizations
representing retail customers and develop a procedure for selecting the other
retail members. Retail representation on the board is necessary because of
the significant impact of the wholesale transmission market on the retail
market, particularly in view of the ISO's enhanced role in the planning of
transmission facilities. The addition of retail representation will bring
new and necessary voices to the board. This requirement will not be effective
until September 1, 1999, to permit the commission to review any legislation
that might be enacted in the current session relating to the restructuring
of the industry and assess its impact on the ISO.
In the preamble to the proposed rule, the commission posed the following
question: Is it appropriate to add other duties to the ISO, such as giving
the ISO day-to-day transmission planning responsibility and authority to determine
whether new power plants may interconnect with transmission service providers?
Functions
A number of parties raised concerns regarding the proposal in §25.197(c)(1)
which would authorize the ISO to determine "whether a person is eligible for
transmission service." HL&P, TU Electric, Pedernales, and Garland opposed
this provision. HL&P recommended that the reference to "other" in referring
to "eligible customers" (presumably referring to §25.191(e)(1) and the
definitions sections of the substantive rules, §25.5) should be deleted
to avoid confusion. Similarly, TU Electric submitted that it is not appropriate
for the ISO to make the legal determination of whether a person is "eligible
for transmission service" as proposed in §25.197(c)(1). Consumer-Owned
Power Systems, however, agreed that the decision regarding whether a customer
requesting an interconnection agreement is an eligible customer is a decision
that properly rests with the ISO, and the requirements determined necessary
for interconnection by the ISO should be made the subject of a standard agreement.
HL&P agreed that the ISO should facilitate the discussion of loss compensation
among ERCOT members, but that there is no need to codify this task. HL&P
proposed that the ISO's responsibilities for determining the adequacy of resources
to meet ERCOT demand should be limited to ensuring the reliability of the
transmission grid; the ISO should not be put in the position of determining
whether (or when) generation should be built in ERCOT. Therefore, the rule
should clarify that the ISO's responsibilities include "determining the adequacy
of transmission resources." According to HL&P, this change would avoid
the misperception that the ISO could exercise authority over the development
of new generation resources. Likewise, HL&P argued that the ISO should
not be permitted to create and file tariffs, because this would undermine
the independence of the ISO. HL&P stated that regulated transmission providers
are the sole entities that should file tariffs for commission approval. USGen
also asked the commission to consider having the ISO manage a voluntary power
exchange for the ERCOT region, which would not replace bilateral deals, but
would facilitate a short-term market and encourage additional participation
in what is currently an "illiquid" market. Brazos suggested that the words
"ERCOT control areas" in §25.197(d)(1)(A) be deleted or replaced with
"ATC zones."
Section 25.197 includes in the duties of the ISO determining whether a
person is eligible for transmission service. Such a decision should not be
made by a market participant, such as a control-area utility or transmission
service provider that is a part of an integrated utility. The decision of
the ISO in this regard is subject to review through the ADR procedures and
ultimately an appeal to the commission. Resolving issues of eligibility through
these dispute-resolution processes takes time, however, and this provision
is intended to require the affected transmission service providers and prospective
customer to adhere to the ISO's decision, while the dispute is being resolved.
As is noted in the discussion of the comments under §25.191, the commission
is defining the nature of wholesale service through a series of contested
cases. The ISO will need to keep current with such changes in carrying out
this duty. With respect to HL&P's comments concerning losses, the loss
compensation provisions adopted for ERCOT result in a rate that is a part
of the overall charges for transmission service. It is appropriate that the
commission have a role in approving changes in the loss methodology. The description
of the reliability function assigned to the ISO includes "monitoring the adequacy
of resources to meet demand." This does not imply that the ISO has authority
over the development of new generation resources, but specifies that the ISO
has a monitoring role. The commission concludes that this role is an important
element of assuring long-term adequacy and reliability of service, and assigning
such a role to the ISO is consistent with the reliability function carried
out by other regional reliability organizations. This function does not intrude
on either the commission's functions or utilities' responsibilities. With
respect to the comment on tariffs, this section prohibits the ISO from buying
or selling power. The provisions that call for the ISO to establish charges,
such as the provisions relating to the ISO charge and the loss compensation
methodology, do not require the filing of tariffs and do not, in the commission's
judgment, undermine the ISO's independence. The commission recognizes that
a voluntary power exchange would facilitate buying and selling power in ERCOT
and recognizes that there have been discussions of mechanisms for posting
offers, under the auspices of the ISO. The existing rule and proposed rule
required that the electronic information network permit the posting of generation
offers and bids. The commission encourages these efforts to create a voluntary
power pool, in order to provide greater price transparency and forward price
disclosure in ERCOT. There has not been adequate examination of the issue
in this rulemaking proceeding, however, to expand the existing requirement
to include the adoption of a voluntary power exchange. The suggestion by Brazos
to modify the rule to refer to transfer capability between ATC zones has been
made in the rule being adopted, in part. The rule simply refers to "transfer
capability for transmission of energy between areas in ERCOT."
Planning
With regard to ISO autonomy and responsibilities, Consumers Union argued
that the commission must be the ultimate authority both over transmission
planning and ensuring that there is sufficient energy available to meet the
state's needs, and that the ISO's functions should not be expanded without
increasing its independence.
Austin, the CSW Companies, and HL&P contended that the ISO should be
responsible for the long-term planning of the ERCOT bulk transmission system,
in coordination with individual transmission service providers, but the localized
transmission planning and management of service-area facilities and day-to-day
planning responsibilities should be the responsibility of individual transmission
providers who are in a better position to identify and plan for such needs.
The obligation to build facilities and provide reliable service resides with
the transmission service provider, not the ISO. The ISO should not have the
authority to prevent a new power plant from connecting to the ERCOT grid,
but should provide criteria specifying the requirements for direct interconnection.
STEC argued that the transmission service provider and the ISO must have joint
responsibility for day-to-day planning and to determine whether new power
plants may interconnect to the ERCOT transmission system. TU Electric stated
that (1) the definition of bulk transmission projects in §25.197(f) should
be limited to projects that "affect the transfer capability of the ERCOT system,"
and not include the phrase "or result in changes to the operational configuration
of the ERCOT transmission system"; (2) the commission should reject (or clarify)
§25.197(f)(1) to ensure that a transmission provider is not subjected
to yet additional delays if it is required to file CCN applications 60 days
before filing them with the commission; and (3) the proposal in §25.197(f)(3)
regarding commission review of ISO guidelines should be rejected because the
ISO is not regulated by the commission.
Brazos proposed that §25.197(f) and (h) be revised so that the ISO
would only coordinate, not supervise ERCOT planning activities. Brazos argued
that each utility needs to be responsible for its own system planning, while
the ISO's function is to ensure that the end result is a reliable transmission
system that is able to economically meet the needs of planned resources. TIEC
argued that the ISO should have an expanded role in transmission planning
and day-to-day operations. USGen agreed that the ISO's duties should be expanded
to include
overseeing
all transmission planning.
The ISO should have the final say in a transmission plan, but should not do
the planning alone. Along similar lines, Weatherford stated that transmission
providers should provide input, but the final determination of system adequacy
would be the ISO's. Weatherford also suggested that, because the system is
being accessed and paid for as one network, there is no reason for individual
transmission providers to require different interconnection specifications.
Garland, Independents, and Panda suggested that the ISO should have the
resources, and be responsible, for performing security studies for both loads
and generators desiring connections to the transmission system. Garland concluded,
however, that the proposed expanded duties cannot adequately be performed
by the ISO within its current staffing, funding, and other resources. Specifically,
Garland stated that (1) transmission providers should provide their input
to the interconnection process, but the ISO should have the final say on system
adequacy and individual transmission providers should not be permitted to
specify individual interconnection requirements; (2) there should be a quicker
and clearer line of communications between the commission and the ISO in order
for the ISO to receive instructions on implementation questions that involve
a policy consideration; (3) the ISO should be adequately funded so that it
does not need to rely on volunteer staffing from the large utilities, which
serves to disenfranchise the small utilities who do not have the resources
to "volunteer" staff to the ISO; and (4) the funding should be sufficient
to allow the ISO to practically police transactions and adequately review
the data and assumptions used to determine available transmission capacity.
Consumer-Owned Power Systems, Independents, and TIEC agreed that the ISO should
be responsible for performing system security studies. LCRA suggested that
the rules should more clearly define the difference between the "comprehensive"
authority over the planning of bulk transmission projects that affect the
transfer capability of the system and the "supervisory" and coordinating responsibility
over projects that are "local in nature." In addition, LCRA questioned why
different standards apply, stating that there should not be a distinction
between projects based on whether they are local or system-wide. LCRA suggested
that the commission follow the planning procedures and responsibilities outlined
in the ERCOT Transmission Adequacy Task Force Report previously submitted
to the commission. Pedernales supported the proposed expansion of the planning
function of the ISO, and stated that the commission should give great weight
to the ISO's opinion on the technical merits of a project. Pedernales, however,
cautioned that the ISO should not be given any authority to set policy or
make any decisions outside of purely engineering or planning functions.
TIEC expressed concern over ERCOT's practice of adopting NERC policies
because NERC, according to TIEC, has not been an open, representative organization
for all market participants. To ensure fairness, TIEC recommended that any
reliability and interconnection standards and their application be subjected
to commission oversight. Independents recommended that the standards, regardless
of who developed them, should be reviewed and approved by the commission.
Austin argued with regard to §25.197(f)(1), that the words "if applicable"
should be added at the end of the last sentence to recognize that municipally-owned
utilities are not required to obtain CCNs for new transmission facilities.
Similarly, the following sentence should be added to this subsection: "Should
the entity constructing the transmission facilities not be subject to the
Commission's certification process, the proposal shall be submitted to the
ISO at least 60 days prior to starting the detailed design of the transmission
facilities." ANP requested that §25.197(f)(3) be revised to provide that
the commission will expedite approval of ISO-approved transmission upgrades.
The CSW Companies suggested that (1) the ISO should review the operating
records and performance tests of planned resources which were unavailable
during high load periods to determine if these resources are suitable to be
nominated as a planned resource for the following year; (2) the ISO should
be given the authority to initiate bulk planning projects with affected transmission
providers as needed; and (3) the ISO should file periodic reports with the
commission (as proposed) addressing annual developments, updates on the ability
of the transmission system to support wholesale power competition, and the
status of prior ISO-recommended transmission projects and proposals for new
transmission projects. Finally, CSW Companies contended that transmission
service providers or developers of new power plants should be able to obtain
an opinion from the ISO as to what the fair and equitable direct interconnection
costs are in a specific instance.
TU Electric suggested that proposed §25.197(g) be modified to allow
a transmission provider to report or disclose confidential information to
the ISO and state and federal authorities pursuant to a discovery request
in a judicial or regulatory proceeding where a protective order or confidentiality
agreement is obtained prior to disclosure.
Regarding dispute resolution issues, Koch suggested a modification to the
proposed rule to assure that the ISO is authorized to resolve disputes that
arise during the processing of an interconnection application. Regarding §25.197(j),
Independents agreed that disputes involving the ISO should be submitted to
the commission for resolution.
Numerous other comments were filed regarding specific governance and authority
issues. These are summarized below. With regard to §25.197(d)(3), Consumer-
Owned Power Systems recommended that the rule impose an affirmative duty to
post complete information regarding generation bids and offers to ensure that
the smaller players effectively participate in the wholesale market. Koch
also suggested a modification to proposed §25.197(d)(3) to make clear
that parties are free to use the electronic information system to post bids
and offers. Consumers Union recommended that (1) the ISO be subject to the
state's open meetings and open records laws; (2) the commission maintain jurisdiction
over all practices, tariffs, rules, requirements and procedures employed or
adopted by the ISO and that any affected party have the right to seek a hearing
before the commission on any ISO action or recommendation; (3) the ISO be
required to conduct its operation in an economically efficient manner, minimizing
costs or operation and investment and that the commission ensure that ISO
investments and expenditures recovered from retail customers are just and
reasonable, and shared by all users in an equitable, non-discriminatory and
competitively neutral manner; and (4) employees of the ISO be prohibited from
having a financial interest in the economic performance of any power market
participant.
Public Counsel urged that the rule specifically state that the existence
of the ISO, as a quasi-governmental entity, is not intended to affect the
application of any state or federal anti-trust law. TIEC recommended that
the current rule be changed to (1) require the posting of specific prices,
not formula rates, on the ERCOT Electronic Transmission Information Network;
and (2) each ancillary service offering should be posted side-by- side for
all electric utilities as well as other market participants providing the
ancillary service. Independents, however, opposed the changes to §25.197
that would permit market participants to refuse to disclose to the ISO prices
for buying and selling electricity, arguing that the ISO should have no role
in price regulation. Brazos also suggested that the transmission system planners
would need to know information regarding the electrical characteristics of
the generation and load, but would not need to know prices for the purchase
or sale of the power and energy.
OxyChem and TIEC recommended that §25.197(h) be revised to note that
the interconnection standards prescribed by the ISO should not adversely affect
or impede manufacturing or other internal process operations associated with
the interconnected generating facilities, except to the minimum extent necessary
to assure reliability of the ERCOT transmission network. OxyChem stated that
this change is necessary to preclude the ISO from unnecessarily interfering
with manufacturing operations (such as cogeneration) associated with generating
facilities.
In response to the foregoing comments, the commission clarifies that it
intends for the ISO to have broad and comprehensive authority to manage the
ERCOT transmission network, subject to commission oversight. To ensure network
reliability and adequacy, the ISO will have direct supervisory control over
issues involving transmission capacity. Decisions, guidelines, standards,
or recommendations by the ISO, however, will be subject to review by the commission,
if necessary. The ISO will also serve as a facilitator working with generators
and utilities to ensure that adequate generation capacity is in place to serve
ERCOT loads. To carry out these functions, the ISO will also supervise and
coordinate resolution of issues affecting the bulk transmission market that
may be in the nature of localized or day-to-day transmission planning and
management activities. Likewise, the ISO will have authority to set policy
and make decisions that are not purely engineering or planning in nature if
necessary to ensure network reliability and adequacy. In short, if an issue
or project directly or indirectly affects the transmission network, including
adequate generation capacity to serve customers in ERCOT, the ISO is to consider
the issue or project initially and resolve the matter without resort to the
commission, if possible. If a party is not satisfied with the ISO's resolution
of an issue, or the ISO's guidelines or standards, the issue may be appealed
to the commission for review. The commission, however, will give significant
weight to the ISO's recommendation in the event of an appeal.
In response to the specific comments regarding §25.197, the commission
concludes that the ISO has the authority to determine whether a person is
eligible for transmission service, and to ensure that connection of a new
power plant to the network is appropriate only if system reliability and adequacy
will remain secure. The ISO will supervise, rather than merely coordinate,
ERCOT planning activities, and will be responsible for performing security
studies for both loads and generators desiring connection to the network.
With regard to funding, the ISO governing board shall propose to the commission,
if necessary, a method to ensure adequate funding for the ISO to carry out
the responsibilities outlined above and as stated in the rule, and to reduce
the practice of using volunteers provided by the regulated utilities to staff
the ISO. ISO employees also should be prohibited from having a financial interest
in the economic performance of any power market participant. The commission
agrees with TU Electric that the last phrase in the first sentence of §25.197(f)
should be deleted. Therefore, the bulk transmission projects addressed in
that section are limited to projects that "affect the transfer capability
of the ERCOT system." The commission also agrees that §25.197(f)(1) should
be clarified to recognize that municipally owned utilities are not required
to obtain CCNs for new transmission facilities. The phrase "if applicable"
is added to the end of the last sentence in that section to make this clarification.
The commission agrees with OxyChem's request to revise §25.197(h) to
note that the interconnection standards prescribed by the ISO should not,
to the extent possible, adversely affect or impede manufacturing or other
internal process operations associated with interconnecting generation facilities.
Finally, the commission agrees with Public Counsel's position that the existence
of the ISO is not intended to affect the application of any state or anti-trust
law. Although the ISO has been established in accordance with commission Substantive
Rule §23.67(p), the commission, not the ISO, is the agency charged with
implementing PURA. As stated above, all decisions or determinations of the
ISO ultimately are the responsibility of the commission; the existence of
the ISO does enlarge or modify the commission's comprehensive regulatory scheme
over electric utilities. Therefore, new §25.197(k) is added to clarify
that the existence of the ISO is not intended to immunize any conduct in the
competitive market from anti-trust action.
The commission does not agree with the remaining suggested modifications
summarized above. Specifically, there is no need to codify the ISO's facilitation
of loss compensation discussions, or to require that ancillary services be
posted side-by-side for all electric utilities. The ISO has discretion to
determine the best course for dealing with these and other similar details.
For the same reason, the rule does not address discrete issues involving whether
and to what extent confidential information is to be disclosed, or the amount
of information that must be posted regarding generation bids and offers. These
details are left to the discretion of the ISO. However, the ISO itself should
not create or file tariffs; tariffs will be filed by the utilities, subject
to the standards adopted by the commission. The ISO will not be charged with
managing a voluntary power exchange, because such activities are more properly
facilitated by the private market. The commission does not place additional
restrictions the speed with which CCN applications will be processed, although
it is the commission's intention to address these applications as soon as
practicably possible. The commission will also retain review authority over
ISO guidelines in furtherance of its PURA mandate to oversee the public interest.
Finally, the commission will not modify its use of the terms "comprehensive"
and "supervisory" as used in the proposed rule.
With regard to the open government issues raised by the commenters, the
commission concludes that the ISO is not subject to the open meetings and
open records laws because it is not a "governmental body," as that term is
defined in Texas Government Code Annotated §551.001(3) and §552.003(a)
(Vernon 1999). While the rule gives the ISO significant authority to address
disputes initially, and to supervise activities involving the transmission
network, the commission is the "governmental body" that is charged with ultimate
authority over the ERCOT transmission network.
Section 25.198: Initiating Transmission Service
Brazos noted that in §25.198(b)(3), one of the conditions precedent
is that an eligible customer has an executed interconnection agreement. This
requirement would eliminate power marketers from being eligible customers
because they do not own transmission facilities. Brazos suggested that this
provision require an interconnection agreement only if it is necessary.
The commission is modifying the rule as suggested by Brazos.
The CSW Companies suggested that §25.198(b) be revised to require
an eligible customer that is responsible for serving wholesale load to maintain
an average power factor of 95% or greater for the load that is connected to
the transmission system, rather than a power factor of 95% at each point of
delivery. They asserted that there are more efficient ways to ensure that
all wholesale customers carry their fair share of reactive power compensation.
This can be done by distributing capacitor installations among substations
belonging to the wholesale customer. This is suggested because some reactive
loads are best compensated at nearby substations rather than at the offending
substation, where the required size or number of capacitor banks might be
inefficient. TU Electric suggested that the power factor at the point of connection
to the service be specified as a range, as opposed to a single number, but
that the power factor be specified for both the transmission level and distribution
level at the point of interconnection. In addition TU Electric proposed that
the ISO have some latitude in the implementation of this standard. Brazos
suggested that the power factor specified in the rule should range from 95%
lagging to 95% leading; it also suggested that utilities that install equipment
to raise reactive power above the 95% level get a credit for doing so. STEC
suggested that the rules should specify, in accordance with the commission's
Order Number 14 in Docket Number 15840, the point at which the 95% power factor
is to be measured.
With respect to ANP's comments, the commission conducted an evidentiary
proceeding on this issue in Docket Number 15840 to construe §23.70, and
the arguments in this rulemaking proceeding are not sufficiently compelling
to cause it to change the result that it adopted there. While the commission
is not changing its construction of the power-factor requirements, it is not
incorporating them into the rule, in recognition that this is an issue that
needs further exploration.
ANP urged that the distinction between planned and unplanned service be
eliminated. HL&P noted a problem with the application of §25.198(c)
and (e), where the ISO approves a planned transaction that should be rejected.
According to HL&P, the October 1 nomination date does not permit the ISO
to do a thorough analysis of each request for planned service. The ISO, for
example, approved a request for service into the Rio Grande Valley that exceeded
the transmission capacity into the Valley. Approval was grounded in the belief
that no other resources existed for which the transmission system was adequate
to accommodate the request. Subsequent to the nomination date, the principal
affected transmission provider developed a plan to temporarily install generators
in the Valley. When these generators were dispatched to support the load in
the Valley, the costs were charged to all other ERCOT load entities as a redispatch
cost. HL&P suggested that in these or similar circumstances in the future,
redispatch costs should be assigned in same manner as would occur with unplanned
transactions; that is, the redispatch costs should be charged to the affected
load entities only. HL&P suggested that the annual planned service requests
that are filed on October 1 be approved conditionally. If it is later determined
that the service requests cannot be met with the existing transmission capacity,
the load entities whose requests have been conditionally approved would be
required to bear the redispatch costs required to meet their customers' needs.
Other load-serving entities would not share in the responsibility for the
redispatch costs.
The commission held a workshop on the transmission rule prior to the publication
of the proposed new rules, and there was significant opposition to the elimination
of the distinction between planned and unplanned service. Many of those who
commented at the workshop were concerned that such a change would affect their
ability to be sure that they have transmission rights to transmit power to
their customers. The commission proposed weekly and daily planned service
as an additional service that would permit new market participants like ANP
greater assurance that they can deliver power to their customers, without
affecting the annual planned service that is relied on by load-serving utilities
to deliver power to their customers. HL&P's comments proposing that the
ISO conditionally accept requests for planned service may be equitable and
workable in circumstances in which a discrete constraint affects several transmission
customers. The concept might be more difficult or impossible to apply where
several constraints affect different groups of transmission customers. It
seems clear that additional transmission facilities are needed and in the
period before they can be put in service, additional or different mechanisms
for managing congestion may be appropriate. Because of concerns about whether
the HL&P proposal would work in the current environment, the commission
is not adopting it.
The CSW Companies noted that §25.198(c) permits the ISO to initiate
a facilities study. The CSW Companies suggested that this provision should
specify that the transmission provider must perform the facilities study.
Several parties suggested changes in the list of materials required in connection
with an application for annual planned service. TU Electric proposed an additional
requirement, namely, an eligible customer that does not own a resource should
file with its application an affidavit attesting to existence of a power contract,
but need not file the contract itself. STEC and Wholesale Competitors suggested
that the projection of load and resources in §25.198(c)(2)(C) and (D)
should be for ten years, rather than five. STEC urged this change, so that
utilities will have data necessary to comply with FERC filing requirements.
The Wholesale Competitors urged the commission to convene a working group
of ERCOT market participants to develop new and better planning processes
that would recognize the uncertainties in long-term forecasting. Wholesale
Competitors suggested that where this section requires an applicant to provide
the address and telephone number, it should also require an email address.
Where the rule requires a transmission customer to submit a power sales agreement,
Wholesale Competitors urged that the customer should be permitted to file
a redacted contract.
As is noted in the discussion of the functional unbundling requirements,
the commission is modifying the rule to assign the responsibility for conducting
a system security study to the ISO. The commission is not adopting the CSW
Companies' suggestion, because of its concern about the opportunity and motive
for an integrated utility to discriminate against a power plant developer
with which it is not allied. The commission agrees that the transmission customer
should be permitted to file a redacted contract. The ISO has an interest in
assuring that the transmission customer has a right to the power that is the
subject of the contract and may need to review portions of it to do so, but
it does not have any need for sensitive information, such as prices. The commission
recognizes that the transition to a competitive environment is creating a
disconnect between transmission planning and power plant development. It agrees
with the suggestion of STEC that this problems merits additional attention.
In the current environment, it appears questionable to rely on projections
of load and resources for more than five years into the future. For this reason,
it is not adopting the STEC suggestion that a ten-year forecast be required.
Section 25.198(c)(7) permits certain unplanned transactions to be converted
to planned service but requires the transmission customer to purchase additional
megawatt miles, if needed for the transaction. STEC and Wholesale Customers
noted that the rules should specify that the additional megawatt miles must
be purchased from the impacted service provider or a customer of that provider.
The comment in this proceeding do not provide an adequate record to make
the changes proposed by STEC and Wholesale Customers.
TU Electric proposed that §25.198(e) be modified to add language from
the existing §23.70(f)(2) which requires, prior to the completion of
new transmission facilities or upgrades, that transmission providers are obligated
to provide only the level of service that the existing system will support.
The commission agrees that this modification is appropriate, and it has
been included in the rule.
Koch expressed concern that the rules do not address the possibility that
a merchant peaking facility could be a new facility but not a planned resource,
under §25.198(f), (g), and (h). Koch suggested that a merchant peaker
should be subject to simplified application procedures.
Koch has not provided adequate detail as to the changes that it seeks.
For this reason, the commission is not adopting this suggested change. The
commission believes that the provisions that it has included in the rules
in this Subchapter will strengthen the role of the ISO in the process of interconnecting
new generation facilities and reduce the opportunities for integrated utilities
to impede new merchant power plants. In addition, the adoption of short-term
transmission service should enhance the opportunities for the sale of peaking
power. If these measures are not sufficient, the commission will consider
other measures later.
Austin expressed the view that §25.198(f)(4) should be modified to
make it clear that an applicant for unplanned service is not required to provide
information that it has already filed, such as in a request for planned service.
STEC expressed the view that §25.198(f)(4)(C)(vii) needs to be clarified
and stated that it believes that the ISO is not currently requiring transmission
customers to comply with the equivalent provision in the current rules. Brazos
commented that the use of the term "transmission customer" in §25.198(h)
would exclude power marketers and EWGs (because they do not operate facilities
at points of interconnection). Brazos recommended that the term "load entity"
be used instead. The Wholesale Competitors also urged that in §25.198(g)
the term "interconnection agreement" be replaced by "transmission agreement."
Only a transmission agreement is needed to obtain planned or unplanned transmission
service.
The change suggested by Austin is not necessary. In applying this provision,
the commission is confident that the ISO will not require eligible customers
to provide unnecessarily duplicative information. The suggestion to replace
the term "interconnection agreement" with "transmission agreement" is not
appropriate, but §25.191(g) is being modified, as suggested by Brazos,
to recognize that not all transmission service customers own electrical facilities.
One of the commenters noted that the provisions of this section and §25.199
overlapped to some degree. To eliminate the possibility of confusion, the
commission has combined these sections, resulting in the elimination of §25.199.
In the preamble to the proposed rule, the commission posed the following
questions: Will the new short-term planned transmission services enhance the
opportunities in the wholesale market for persons interested in making short-term
sales of power or sales of other specialized services, such as peaking power?
Should the rates for weekly and daily planned service be based on the full
embedded transmission costs, or should they be based on some percentage of
the embedded costs? Should the rates for these services be distance-sensitive?
Should the rates include seasonal or on-peak/off-peak differences? If so,
how should the seasons and peaks be defined and what level of rate differential
should be reflected in the rates?
ANP and San Antonio supported weekly and daily service. Brazos commented
that transmission constraints are an obstacle to short term sales of power,
and that establishing short-term planned transactions will do nothing to relieve
the constraints but will complicate the process for approving transactions.
The CSW Companies commented that the concept of weekly, daily or hourly planned
service does not meet the definition of planned service. Transmission service
of lengths shorter than a year cannot be planned because the grid cannot be
modified to accommodate short-term transactions. The CSW Companies and TNMP
recognized the need for short-term service with a priority higher than unplanned
for replacement of planned services due to outages. If a constraint occurs,
unplanned service would be curtailed before "replacement service". According
to the CSW Companies, any hourly service would be strictly unplanned service.
TNMP was concerned that establishing short-term planned service would result
in incentives for transmission customers to under-estimate annual load, in
order to reduce their access charges, and rely on purchases of short-term
planned service if they experience load in excess of the estimate.
The CSW Companies suggested the adoption of weekly and daily "replacement
service" requiring payment of megawatt-mile charges, an ERCOT ISO transaction
fee, and redispatch costs, if needed. TU Electric made several suggestions
concerning the pricing of short-term planned service, including the deletion
of the proposal to authorize the ISO to develop charges for short term planned
service. It suggested that each transmission provider file a short-term tariff,
based on its postage-stamp rate component, and that service should be on a
"take or pay" basis. The billing units would be in megawatts of transmission
service, unless service is requested to replace a resource nominated for annual
planned service. In that case billing units would be additional megawatts,
if any, of the resources being required as the replacement. TNMP expressed
the view that the price for planned service (monthly, weekly, and daily) should
be based solely on megawatt-miles. In addition, any pricing mechanism should
remove incentives to under-forecast load for annual planning purposes. It
suggested that short-term purchases during the four summer months should be
based on rates equal to three times the megawatt-mile rates. A participant
should not be penalized for load growth, so that the megawatt-mile calculation
should be capped at the megawatt-mile charges that would have been applicable
had the load growth been in the participant's annual nominations. STEC expressed
the view that the ISO should have wide discretion to price transmission service
for weekly and daily service and that rates based on a megawatt-mile impact
matrix would be too cumbersome. ANP expressed the view that rates should be
based on a floor price equal to instantaneous marginal transmission cost,
to maximize system efficiency. If service is oversubscribed at this price,
competitive bidding should set the price. San Antonio supported short-term
rates based on prorated annual rates, including impact and access fees.
The proposed rule would have established planned transmission service on
a weekly and daily basis and authorize the ISO to formulate rates for such
service. Currently, planned transmission service may be purchased on an annual
or monthly basis. The proposed rule did not specify a method for pricing these
short-term services.
Establishing a short-term service with more firmness that the existing
unplanned service was proposed as a means of facilitating the participation
of merchant generation plants in power-sales markets, based on the belief
that they needed greater assurance that they could deliver power to a customer.
Establishing such a service that included capacity costs in the transmission
rates would also be a means of allocating the use of constrained transmission
pathways using economic criteria, rather than non-economic criteria. The only
existing weekly and daily transmission service available is unplanned service,
in which use is allocated to the person who makes the first request for the
service. Where there are significant constraints, persons who wish to obtain
short-term unplanned service could make a request for service as soon as it
appears likely that they will have a transaction that will require transmission
service over a particular path. The current rules on reserving unplanned service
may encourage market participants to make a reservation even before they are
aware of a particular transaction for which they will need transmission service.
If there are many market participant seeking to obtain the use of a constrained
path, they will presumably try to make their reservation as soon as the window
opens for a particular period. In these circumstances, chance largely determines
who obtains the service.
Establishing a short-term service that requires the payment of a fee, particularly
a fee that is forfeited if the service is not used, would require more caution
on the part of a market participant requesting a short-term service and would
allocate the service to those participants whose transaction is of greater
value than the price of the service. If, for example, the transmission rate
for daily planned service from South Texas to North Texas is $30 per megawatt
per day, participants will request the service only if the profit on the transaction
is expected to be more than $30, and they are less likely to request the service
if they do not have a transaction lined up.
With respect to the issue of pricing, it appears that the important criteria
for a short- term service are simplicity and transparency, as TU Electric's
reply comments suggest. The service is a lower priority service than annual
planned service, so it is not important that it match every element of the
pricing of annual planned service. A workable scheme would be pricing based
on each transmission service provider's postage stamp rate component, with
a customer paying a prorated share of the annual rate for the megawatts that
it proposes to transmit. Payment would be on a take or pay basis. In periods
in which transmission paths are not congested, unplanned service would be
available with only loss compensation and the ERCOT fee.
ANP proposed a minimum price for the short-term planned services, with
an auction conducted by the ISO for any service that is over-subscribed. An
auction would be a reasonable means of allocating the rights for such service,
but it is not clear what level of administrative effort would be required
for the ISO to conduct such auction. Moreover, it seems likely that if a short-term
planned service is established with a fixed prices, there would be trading
of rights to service over congested paths in a secondary market, and market
prices for the service would develop in the secondary market. A secondary
market may be able to achieve the same economic benefits as an auction market,
without imposing on the ISO the burden of conducting an auction. The ISO may,
however, have to establish procedures to track ownership rights if such trading
develops.
It is possible that the proposed rule will not work well in practice. For
this reason, the commission is including a provision for commission review
of the service after it has been in effect for six months.
Section 25.199: Transmission Facilities or Upgrades
for New Planned Resources
Austin suggested that the scope of this section be extended to the creation
of new interconnection points. Koch argued that a merchant peaking plant should
be subject to simplified application procedures and interpreted this section
as not requiring a system security study for a merchant peaker. Independents
suggested that this section be deleted and that the studies be addressed in
§25.195. Independents made several recommendations based on the assumption
that this section is retained: (1) the provisions relating to CIACs should
be conformed to §25.195; (2) the ISO should determine which transmission
service providers are affected by a new resource and are entitled to participate
in a security study; (3) the transmission service provider should bear the
costs of a security study; and (4) the ISO should supervise any facilities
study and make an initial determination whether a CIAC is appropriate. TIEC
agreed that the provisions relating to CIACs were in conflict with §25.195
and suggested that this provision be deleted.
The revision proposed by Austin is appropriate and is included in the rule
being adopted by the commission. The changes that the commission is making
to facilitate the interconnection of new generating facilities should alleviate
the problems and uncertainties that developers have encountered in interconnecting
their facilities, and special provisions for merchant peakers to not appear
to be warranted. As suggested by Independents, this section overlaps with
other sections. It is being combined with 25.198.The commission has also amended
the proposed rule to make it clear that §25.195 prescribes the rules
relating to a contribution in aid of construction.
In the preamble to the proposed rule, the commission posed the following
question: Should transmission customers deal with the ISO in arranging for
a security study? Should the ISO be responsible for performing security studies?
The Consumer-Owned Power Systems recommended that the function of performing
security and facilities studies, which the proposed rule would assign to transmission
providers, should be carried out by the ISO instead. They also suggested that
this section specify the information that needs to be provided by a transmission
customer, in order that the initiation of a study is not delayed through uncertainty
about what information needs to be provided. Garland, Independents, and TIEC
supported having security studies performed by the ISO. In particular, Garland
noted that participants in a competitive wholesale market have more confidence
in releasing sensitive information to the ISO than to a transmission provider.
The CSW Companies recommended that the ISO continue to be transmission
customers' point of contact for the initiation of security and facilities
studies. The ISO should initiate security studies and should also supervise
and coordinate the transmission service providers' performance of the studies.
According to the CSW Companies, the transmission providers should be responsible
for performing facilities studies. San Antonio suggested that the ISO's role
should be to review security studies. STEC argued that because of the idiosyncrasies
in the various transmission systems, the transmission service providers should
conduct the security studies, but they should be under close supervision by
the ISO, in particular, to ensure that they are completed within the 60 day
deadline.
One of the modifications to the proposed rule that the commission is making
to facilitate the interconnection of new non-utility generating facilities
is to assign the responsibility for conducting system security studies to
the ISO. This is consistent with the need for unbiased analysis and timely
response and with the assumption of system- wide planning responsibilities
by the ISO. Facilities studies are more likely to involve engineering details
concerning the configuration and operation of the transmission service providers'
transmission system, however, and the responsibility for facilities studies
will remain with the transmission service provider.
Section 25.200: Load Shedding, Curtailments, and
Redispatch
Brazos asked the commission to clarify the requirement for transmission
service providers to notify the ISO of scheduled interruptions to service
of a transmission facility; Brazos questioned whether the notification should
be provided for all scheduled transmission line outages or only for lines
that will effect the wheeling of power and energy.
The commission expects that the ISO will adopt and carry out procedures
concerning notification of transmission outages; the details of these procedures
do not need to be included in this rule.
ANP requested clarification of the provision for the ISO to perform an
economic dispatch of non-utility generators, questioning whether it will have
adequate information about cost and non-cost factors that affect the dispatch
of a generator. Brazos and Austin stated that the ISO may not be able to detect
a transmission problem before the control area, thus the responsibility to
relieve transmission constraints should be done in consultation with the affected
control areas. In addition, San Antonio noted that the authority to recognize
and act on operating conditions should be concurrent as between transmission
providers and the ISO, subject to appropriate ISO-administered guidelines.
The ISO does not on a routine basis obtain cost information about either
utility or non-utility generating facilities, and its ability to direct redispatch
depends on its ability to obtain cost information from transmission customers.
Nevertheless, the least-cost standard is an appropriate standard for the ISO
to apply in directing the redispatch of resources. The proposed rule prescribes
that the ISO is responsible for curtailment. There may be instances in which
it is appropriate for transmission service providers to curtail service, immediately
and notify the ISO, rather than obtain permission first. This is another area
in which the ISO has the authority to adopt and carry out procedures affecting
the reliability of the network, and in which the details of these procedures
do not need to be included in this rule.
Brazos noted that customers that pay an annual transmission access fee
should not bear the cost of redispatch services. Garland commented that redispatch
for annual planned service should be charged to all ERCOT load serving entities.
Redispatch for all other transactions should be paid by the parties benefiting
from the redispatch. San Antonio stated that charges for redispatch should
be paid by the parties that actually benefit from the redispatch, and that
any other result would be inequitable. CSW Companies requested clarification
that the standard methodology referenced in §25.200(c)(3) should apply
to all ancillary services providers who provide redispatch service. Independents
remarked that if a utility has properly unbundled its transmission function,
the transmission provider would not be able to redispatch generating resources.
TIEC pointed out that the pricing provisions that would require customers
to pay both redispatch costs and a facilities charge for short-term planned
service would violate FERC's "or" pricing rule.
With regard to the issue of who pays for redispatch, the commission adopted
the existing redispatch provisions based on its view that the ERCOT system
operated as a single transmission network. This is a fundamental principle
that affects broad issues, such as pricing and access, and narrower issues,
such as redispatch. The commission is retaining this principle in adopting
the new §§25.191 through 25.204, based on its view that the transmission
rules have been effective in fostering competition. It would be inconsistent
with this general principle to adopt a different rule for redispatch. The
commission has the regulatory authority to require electric utilities to file
formulas for determining redispatch costs, but it is not clear whether it
has such authority with respect to other power producers participating in
the wholesale market. For this reason, it is not adopting the change suggested
by the CSW Companies. The commission recognizes that transmission service
and redispatch are provided by different organizations within an electric
utility, and that the rules require that these functions be separated. The
unbundling rules do not preclude the ISO from directing the redispatch of
generating facilities operated by an electric utility, in accordance with
this section. The commission does not agree with TIEC's comment that the redispatch
provisions are inconsistent with the FERC's transmission pricing rules. The
FERC's primary concern with respect to the pricing rules was that transmission
service providers would treat their customers differently than they treat
the power supply operation in the same company, that is, to preclude discrimination.
The rules proposed by the commission treat all transmission customers alike
with respect to redispatch.
Koch Power Inc. suggested adding a new paragraph to this section to allow
competitive providers of generation to challenge decisions made by transmission
providers and to ensure that transmission providers do not have an incentive
to manipulate transmission service to favor their affiliates' generation.
In response, the CSW Companies urged the commission to reject the Koch proposal,
to avoid appearing to expand or reduce legally available remedies.
Other provisions of the rules permit market participants to challenge the
decisions of the ISO, and long-standing commission practice under PURA permits
complaints against utilities. The commission does not see the need to specify
specific remedies for decisions made under this section.
Section 25.201: Terms and Conditions for Ancillary
Services
Ancillary Services
CSW Companies commented that their companies are constrained to provide
ancillary services under cost-of-service based rates, but customers located
in their service areas are not obligated to purchase the services, but may
contract with other regulated and unregulated service providers at their discretion.
CSW Companies asserted that the coexistence of regulated and unregulated ancillary
services cannot be expected to survive market restructuring. In a restructured
market, either ancillary services are monopoly services that require regulated
prices, or they are competitive services where customers are permitted to
shop around for the best market prices. HL&P commented that this section
requires only control-area operators to supply all ancillary services. HL&P
believes this requirement is overly broad and could stifle the development
of a vibrant ancillary service market. HL&P noted that control areas do
need to provide some services (e.g., static and dynamic scheduling), but that
other ancillary services can be provided by any other entity. Therefore, HL&P
argued that there is no reason to require control areas to provide service
that any entity in the competitive market can provide.
The commission agrees that as more power producers enter the wholesale
market and the generation sector becomes less concentrated, competition in
the provision of ancillary services will emerge and there will not be a need
to require electric utilities to provide such services or for the commission
to prescribe the rates for such services. The comments submitted in this project
and in the commission's assessment of the competitiveness of the wholesale
market indicate that the market has not yet reached this level of competitiveness.
Ancillary services remain essential services to permit the wholesale market
to function, and, for this reason, the commission is retaining the provisions
requiring electric utilities to offer these services within pricing limits
set by the commission.
TU Electric suggested that the definition of dynamic scheduling in §25.201(a)(2)
be modified. Austin suggested adding language to paragraph (a)(6), the definition
of emergency energy service, to make it clear that the ISO could require emergency
energy only if prior arrangements that a customer has made for such services
are not implemented in a timely fashion.
TU Electric's suggestion for the definition of dynamic scheduling in §25.201(a)(2)
appears to be a better description of the service and is adopted. The modification
of the definition of emergency energy as posed by Austin appears to limit
the latitude of the ISO during an emergency condition. Such a limitation might
diminish the effectiveness of the ISO in carrying out its duties. Accordingly,
the commission does not concur with Austin's proposed modification to the
definition of emergency energy.
Reserve generation services
TU Electric suggested that a sixth ancillary service category be added,
consisting of reactive power from generation resources, as directed by the
ERCOT ISO and the local control area. Independents opposed TU Electric's recommendation
to include reactive power support as an ancillary service, and to require
that all generators be required to respond to calls for reactive power support
by the control-area operator or the ISO. Further, TIEC expressed concerns
with TU Electric's recommendation because of the complexity that would result
from attempting to price reactive power. TIEC further emphasized that no generally
accepted method has been established to properly quantify the costs of providing
reactive power. TIEC concluded, however, that if TU Electric's recommendation
is adopted that all providers of reactive power support be properly compensated.
Garland agreed in principle with the offering of reactive power as an ancillary
service but expressed several concerns, namely, (1) control-area operators
could be inherently biased in terms of designating must-run units, (2) a bidding
process may be appropriate for valuing reactive power when there is more than
one unit that could provide the service but is not appropriate in a must-run
situation, and (3) a means of costing reactive power in a must-run situation
needs to be established.
The commission understands the importance of reactive power to the reliable
operation of the transmission network and the networks capability to move
power; however, the question of compensation for reactive power raises a number
of complex issues that should be addressed. Accordingly, the commission believes
that these issues should be further explored, for example, through a commission-sponsored
workshop, before adopting mechanisms for compensating for the provision of
reactive power.
Tariffs
San Antonio commented that this section is ambiguous in that it appears
to require control-area operators to file tariffs for both ancillary and reserve
generation services, yet the language states that a utility that provides
"ancillary services" is required to provide a tariff. San Antonio stated that
the language should be revised to make clear exactly what services require
tariff filings.
The commission agrees with the comments of San Antonio. The provision of
the rule relating to tariffs has been modified to make it clear that control-area
utilities are required to file tariffs for both ancillary and reserve generation
services.
Provision of ancillary services by other service
providers
ANP supported allowing generators to compete to provide ancillary services.
San Antonio commented that the following modified language would improve this
provision by limiting the possibility that unscrupulous parties would attempt
to sell ancillary services that they could not actually provide: "Any generator
may compete to provide ancillary services to transmission customers, provided
the generator follows all ERCOT and NERC guidelines applicable to the provision
of each particular ancillary service."
The rule permits any generator to provide ancillary services, and the ISO
has issued guidelines that define the functional requirements for each ancillary
service. This permits a person wishing to buy or sell ancillary services to
readily determine what facilities will be needed to provide the service. These
rules are also an important element of the reliability rules adopted by the
ISO. The commission concludes that an additional reference in the rule to
reliability standards, such as the language proposed by San Antonio, is unnecessary.
Area control service
Austin requested clarification of the meaning "service provider" (i.e.
does it refer to the host or service provider's control area). CSW Companies
commented that this subsection requires the ISO to develop a set of protocols
for an area control service that control-area operating utilities will be
required to offer once the ISO has completed such protocols. CSW Companies
expressed the view that the provision is unclear as to whether a combination
of existing ancillary services or a new ancillary service is intended. CSW
Companies also questioned (1) the meaning of the phrase "with minimal use
of the service provider's generation capacity," (2) who will be the eligible
customers for such service, and (3) whether the ISO's protocols will require
commission approval. HL&P opposed the provision that would require control-area
utilities to provide a new ancillary service that separates control services
from capacity. HL&P expressed the view that the market should be allowed
to determine whether such an ancillary service is needed. TU Electric suggested
that paragraph (e) be deleted. TU Electric contended that so-called "area
control services" are already available under the existing provisions of Substantive
Rule §23.67 of this title. TIEC suggested that subsection (e)(2), which
provides that a control-area utility is not required to provide area control
service to another control-area utility, be deleted. According to TIEC, the
elimination of subsection (e)(2) would provide a natural mechanism to facilitate
a transition to ultimately a single ERCOT-wide control area. STEC, in general,
favored the unbundling of the control component from the capacity component.
Further, STEC favored the use of the 15% reserve requirement as a means for
providing back-up service, as long as control-area capacity requirements can
be met.
One of the market participants proposed a service like the one described
in the proposed rule, in a workshop conducted prior to the publication of
the proposed rule. The primary benefit of this proposal was the possibility
that such a service would reduce the dependence of transmission customers
on a transmission service provider for generation- related services. The commission
concludes, however, that the issues with respect to this service are complex
and have not been adequately explored in this rulemaking proceeding. Accordingly,
the commission believes that this service should not be adopted now but should
be further explored in another forum.
Charges for ancillary services
The Consumer-Owned Power Systems commented that, despite the commission's
efforts to encourage competitive pricing and the adoption of "floor and ceiling"
rates for ancillary services, the reality of the marketplace is such that
most often the ceiling rates are offered on a take-it-or-leave-it basis. Consumer-Owned
Power Systems expressed the view that transmission customers that do not operate
as a control area still face pancaked capacity costs, stating that §25.194
of the proposed rules requires the transmission customer to nominate resources
no less than 115% of peak load, while receiving no recognition of the 15%
reserve capacity for purposes of ancillary services. Consumer- Owned Power
Systems stated that non-control-area transmission customers incur pancaked
capacity costs for ancillary services - once in the 15% reserve capacity and
again in the ancillary service charge. Consumer-Owned Power Systems recommended
that the commission require those utilities that must provide ancillary services
to unbundle the charges for such services to segregate the capacity component
from the control component. They stated that transmission customers should
be able to provide their own capacity for ancillary services to the ancillary
service provider, and purchase only the control component, thereby avoiding
the pancaking of capacity costs between the 15% reserve requirements and capacity
for ancillary services. Consumer-Owned Power Systems noted that this may be
the intent of §25.201(e), but they did not believe that the section would
achieve the desired objective. Koch excepted to this section because of its
belief that the section can be read to apply to unregulated entities. Concerning
paragraph (f)(1), TIEC suggested that in lieu of the existing price ceiling/price
floor rate structure that specific costing methods be determined for each
ancillary service offered. Also, related to paragraph (f)(1), both TIEC and
Independents recommended that generating units not capable of providing ancillary
services (i.e., nuclear units, etc.) be excluded from the determination of
the price ceiling. Independents also argued that generation and load schedule
imbalance, automatic backup and load regulation are monopoly services and
as such should be priced at cost (not based on the price ceiling/ price floor
rate structure). Koch did not believe that the provision of ancillary services
by unregulated entities should be subject to price constraints or cost- based
requirements. Thus, Koch recommended this section be clarified by adding "When
offered by electric utilities" at the beginning of the section.
Several of the large integrated utilities have recommended a lower level
of regulation (or deregulation) of ancillary services. The Consumer-Owned
Power Systems, Independents and TIEC are recommending additional regulation.
The commission has heard a number of comments that suggest that there is not
any significant degree of competition for ancillary services today. However,
since the adoption of the transmission rules in 1996, the ISO has begun operations
and has defined the requirements for offering ancillary services. In addition,
several non-utility power plants have been built in ERCOT, and additional
plants are planned or under construction. These developments suggest the possibility
of new providers entering the ancillary services market, and if current service
providers are demanding prices at the ceiling, this may induce new generating
plants to offer ancillary services. The commission concludes that the best
course, for now, is to continue to permit floor-and-ceiling pricing for the
services that can be competitively offered. With respect to Independent's
comments, the ERCOT operating guides describe load-regulation service as a
service that may be provided by any generator that is able to monitor the
load it is serving through telemetry and respond to moment-to-moment changes
in the load. This service may be provided by a number of control-area utilities
and possibly other power suppliers and is not a monopoly service. The description
of automatic backup is similar; its provision is not limited to a particular
provider. On the other hand, only a host control area may provide load-schedule
imbalance and generation-schedule imbalance. The rule is being revised to
recognize that floor and ceiling pricing is not appropriate for these services.
It was not the intent of this rule to impose regulatory requirements on any
qualifying facilities or exempt wholesale generators. Accordingly, the language
clarification suggested by Koch is not adopted.
Concerning paragraph (f)(3), Austin suggested that the phrase "exceed the
floor" be modified to read "equals the floor". Concerning paragraph (f)(4),
TU Electric suggested modifying the last sentence to read: "Bids or offers
for ancillary service shall not be bundled with a power sale
except at the customer's request."
STEC opposed any provision that
would allow the rebundling of ancillary services due to potential anti- competitive
abuses. In contrast, Garland supported the rebundling of ancillary services
because such arrangements will provide the wholesale customer more bidding
leverage. Concerning paragraph (f)(5), TU Electric suggested that the words
"generation-related" should be added as follows: "Rates for
generation-related
ancillary services shall be prorated on a monthly,
weekly, daily, and hourly basis."
The commission concludes that the phrase in paragraph (f)(3) "exceed the
floor" should read "equals or exceeds the floor", as proposed by Austin. The
commission concurs with the position of STEC concerning the rebundling of
ancillary services. Rebundling, even at the request of the customer, may impede
parties' and the commission's efforts to detect discriminatory conduct. Accordingly,
the modifications to paragraph (f)(4) proposed by TU Electric are not adopted.
HL&P supported incentives to further expand the ancillary service market
as proposed in this section. However, HL&P also recommended the inclusion
of a provision to retain margins from off-system sales (energy) in the manner
suggested by HL&P in Project Number 19501. STEC supported the proposed
sharing of ancillary service revenues (25% to the utility) as a means to foster
more robust ancillary services activity. Austin suggested that §25.201(f)(6)
be explicitly applicable only to investor-owned utilities. CSW Companies recommended
that paragraph (f)(6) be clarified by defining the margin on an ancillary
service sale. CSW Companies proposed the following language: "An electric
utility's margins from the sale of ancillary services shall be any revenue
received by that utility that is above its out-of-pocket costs for providing
such service." Public Counsel and TIEC opposed the sharing of ancillary service
revenues, and recommended that 100% of the margins on such sales continue
to be used as an offset to the fuel revenue requirement. Public Counsel stated
that the commission has provided no evidence that transferring this windfall
to shareholders will have any beneficial impact on the wholesale market. Public
Counsel also claimed that, because the costs associated with the provision
of ancillary services are included in rates, fairness dictates that native
load customers should receive 100% of ancillary service revenues. Public Counsel
also commented that the rule's margin-sharing provision can provide an incentive
for utilities to deploy ancillary services in a manner that is detrimental
to native load customers (e.g., economic incentives may provide an incentive
to distort the normal economic dispatch order). Public Counsel also commented
that the decision whether an ancillary service that is priced below embedded
cost is a "discounted rate" under PURA §36.007(d) should be made on a
case-by-case basis, rather than based on a pre-judgment by the commission
set out in the rule. TIEC argued that unless there is an agreed-upon method
for costing each specific ancillary service, there would be no consistent
or definable way to quantify a margin.
The modifications that the commission included in the proposed rule were
intended to provide an incentive for utilities to offer ancillary services
at rates below the ceiling rate. Utilities face some risk in offering a rate
that is lower than the ceiling, because the commission might conclude in a
fuel reconciliation proceeding that the utility should have offered the ceiling
rate, in order to provide the greatest benefit to its native-load customers.
This modification will provide the utility an opportunity to earn a margin
on the sale of ancillary services to compensate it for the risks it takes
in offering a rate that is below the ceiling. The issue of margins from off-system
sales is being addressed in a separate rulemaking project, Project Number
19865. The commission concurs with Austin that this provision, paragraph (f)(6),
should not apply to municipal utilities, and the rule has been modified accordingly.
Other issues concerning the application of this provision should be addressed
in other forums, such as rate cases or fuel reconciliation proceedings.
Responsibility for ancillary services
CSW Companies recommended that the commission give the ISO the necessary
authority to
require
any generator in ERCOT
to furnish ancillary services when designated to do so by the ERCOT ISO. CSW
Companies proposed that the provision be amended to read, "The independent
system operator shall have the authority to designate any generating facility
in ERCOT as an ancillary service provider of those ancillary services identified
in the ERCOT Operating Guides as services that a generator can provide. Any
facility so designated will have the same obligations as a generating facility
of a control-area operating utility." CSW Companies expressed the view that
this change is necessary because, as more merchant plants are built in ERCOT,
the ISO faces a generating portfolio over which it has little control. With
respect to pricing, CSW Companies recommended the generator be limited to
a range set by floor and ceiling prices of the host area utilities. Consumer-Owned
Power Systems commented that small load entities that do not have significant
diversity of resources must purchase backup capacity and end up paying for
reserves twice - once in the 15% reserve requirement and again in the backup
capacity charge - which places them at an unreasonable disadvantage. They
expressed the view that this problem can be corrected through backup arrangements
administered by the ISO. Under this arrangement, so long as a load entity
has satisfied its 115% reserve requirement (for transmission service), the
load entity should be able to obtain backup power through the ISO for an energy
charge only, which should be the supplier's incremental cost for producing
the energy. STEC supported the requirement that the ISO be authorized to require
any generator in ERCOT to provide ancillary services, but cautions that the
commission probably does not currently have legislative authority to do so.
Independents opposed granting the ISO this authority. Independents contended
that a maturing wholesale market would alleviate the need for the ISO to undertake
this responsibility. Further, Independents argued that independent generators
would be forced to sacrifice sales if the ISO had this authority.
As is noted above, ancillary services remain essential services to permit
the wholesale market to function, and, for this reason, the commission is
retaining the provisions requiring electric utilities to offer these services
within pricing limits set by the commission. For the reasons set out above,
the commission believes that the current pricing rules are conducive to the
entry of new providers into the ancillary services market, resulting in more
competitive prices for such services. With regard to STEC's comments, it was
not the intent of this rule to impose a requirement to provide ancillary services
on any qualifying facilities or exempt wholesale generators.
Initiating service
CSW Companies stated that the commission should make it clear that in order
to receive transmission service, the customer should arrange for the necessary
ancillary services. CSW Companies proposed that, in the event that a transmission
customer does not arrange for necessary ancillary services, the ISO should
deny the customer's transmission request.
This matter is adequately addressed in §25.201(g), as initially proposed.
This provision is being adopted without substantive changes.
Application procedures
Concerning subsection (i)(2)(a), Brazos contended that the 20 minute advance
notice requirement for initiating ancillary service in connection with hourly
transmission service is not feasible. A 20 minute requirement, if applicable,
should be the result of negotiations among parties. ANP noted that the ancillary
service provider may also be the same entity that sells the power. Accordingly,
ANP recommends an exclusion for such entities from the prohibition on providing
information in subsection (i)(6).
The notice requirements were the subject of negotiations among interested
parties when the transmission rules were adopted in 1996, and the comment
filed by Brazos does not provide an adequate basis for revising these requirements.
In response to the comment of ANP the commission is modifying subsection (i)(6)
to permit information to be provided to the organization providing an ancillary
service.
Section 25.202: Billing and Payment for Transmission
Service and Ancillary Services
Independents stated that billing for transmission services by each transmission
provider imposes an unnecessary administrative burden on each entity involved.
Independents suggested that the commission require ERCOT members to develop
a centralized billing system allowing the netting of all monthly charges.
The commission is not convinced that there is a need for it to adopt a
netting requirement, such as was proposed by the Independents. This issue
is a commercial matter than can be handled by buyers and sellers of these
services.
Section 25.203: Alternative Dispute Resolution
Garland questioned the delegation to the ISO of the administration of the
alternate dispute resolution (ADR) process. Garland stated that the delegation
of the ADR responsibility places the ISO in a "judicial administration" role,
which goes beyond the ISO's technical responsibilities for ERCOT system security,
market facilitation, and coordination of transmission planning. ERCOT commented
that complaints against the ISO should not be excluded from the ADR process,
as the rule currently provides. Rather, if a complaint is made against the
ISO, parties should be given the opportunity for mediation and arbitration
prior to filing a complaint with the commission. Koch provided language for
a suggested revision to §25.203(a) to ensure that the curtailment of
transmission service qualifies as a dispute eligible for the ADR process,
prior to filing a complaint with the commission.
The commission disagrees with Garland, and agrees with the comments by
ERCOT and Koch. The ISO is well qualified and placed for the efficient and
fair administration of the dispute resolution procedures as proposed in §25.203.
As noted throughout this preamble, the commission intends for the ISO to be
involved in all aspects of the transmission network reliability and adequacy.
This involvement includes initial attempts to resolve disputes among parties
regarding the ERCOT transmission network. Therefore, the proposed language
will not be modified to preclude the ISO from administering the ADR provisions
of the rule. As to the other comments, the commission adds new §25.203(j)
to state that complaints against the ISO will be subject to the ADR process
and, in accordance with Koch's comments, §25.203(a) is revised to ensure
that the curtailment of transmission service qualifies as a dispute eligible
for the ADR process, prior to filing a complaint with the commission.
Section 25.204: Summary of Required Filings
The commission also solicited comments on the costs and benefits of the
proposed rules.
Panda commented that the rule will aid the development of a vibrant wholesale
power market in Texas, and that transmission additions and upgrades will occur
faster than otherwise. The CSW Companies noted that they have not done a study
measuring the cost of compliance with the proposed rules. CSW Energy suggested
that the commission's determination that there will be no effect on small
businesses and no cost of compliance as a result of the rule changes is in
error. CSW Energy asserted that if, in pursuing a contract with a qualifying
facility (QF), it comes under the prohibition in §25.196, it could be
eliminated as a competitor for the project. It expressed the view that this
provision would hurt a small business exploring the benefits of a QF contract.
The likely result of rule is reduced number of competitors and increased costs.
All comments, including any not specifically discussed herein, were fully
considered by the commission. In adopting these sections, the commission makes
other minor modifications for the purpose of clarifying its intent.
The new sections are adopted under the Public Utility Regulatory
Act, Texas Utilities Code Annotated §14.002 (Vernon 1998) (PURA) which
provides the commission with the authority to make and enforce rules reasonably
required in the exercise of its powers and jurisdiction; PURA §31.001,
which declares that the public interest requires that rules, policies and
principles be formulated and applied to protect the public interest in a more
competitive marketplace; §35.002, which grants all generators the right
to compete for the business of selling power; §35.003, which prohibits
an electric utility from granting an undue preference to an affiliate in the
purchase or sale of electric energy at wholesale; §35.004, which requires
electric utilities to provide comparable wholesale transmission service, directs
the commission to ensure that electric utilities provide non-discriminatory
transmission service, and requires the commission to adopt reasonable rates
for transmission service; §35.005, which permits the commission to require
an electric utility to provide wholesale transmission service, determine whether
the terms and conditions of such service are reasonable, and require the construction
or enlargement of a transmission facility; §35.006, which directs the
commission to adopt rules relating to wholesale transmission service; §35.007,
which requires electric utilities to file tariffs in compliance with the rules
adopted under §35.006; and §35.008, which permits the commission
to require a party to a dispute concerning the prices or terms of wholesale
transmission service to engage in a non-binding alternative dispute resolution
process.
Cross-Index to Statutes: Public Utility Regulatory Act §§14.002,
31.001, and 35.002 - 35.008.
§25.191.Transmission Service Requirements.
(a)
Purpose. The purpose of Subchapter I, Division 1 of this
chapter (relating to Transmission and Distribution), is to clearly state the
terms and conditions that govern wholesale transmission access and related
ancillary services, in order to:
(1)
increase competition in the sale of electric energy at
wholesale in Texas,
(2)
preserve the reliability of electric service, and
(3)
enhance economic efficiency in the production and
consumption of electricity.
(b)
Nature of transmission service. Transmission service allows
transmission service customers to use the transmission systems to deliver
power from generation resources to serve their loads, inside and outside of
the Electric Reliability Council of Texas (ERCOT). Service provided pursuant
to Division 1 of this subchapter permits a transmission service customer to
use the transmission systems of all of the transmission service providers
in ERCOT.
(c)
Definitions. The following terms, when used in Division
1 of this subchapter have the following meanings, unless the context clearly
indicates otherwise:
(1)
Planned transmission service - A service that permits a
transmission service customer to use the transmission service providers' transmission
systems for the delivery of power from planned resources to loads on the same
basis as the transmission service providers use their transmission systems
to reliably serve their native load customers. This service shall have priority
over all unplanned transmission service.
(2)
Unplanned transmission service - A service that permits
a transmission service customer to use the transmission service providers'
transmission systems to deliver energy to its loads from resources that have
not been designated as the transmission service customer's planned resources.
This service permits such energy to be delivered if sufficient transmission
capacity is available to support the requested service.
(d)
Application. Unless otherwise explicitly provided, Division
1 of this subchapter applies to electric utilities in ERCOT, as the term "electric
utility" is defined in the Public Utility Regulatory Act §35.001. The
transmission service standards described in Division 1 of this subchapter
also apply to transmission service to, from, and over the direct-current interconnections
between ERCOT and the Southwest Power Pool, to the extent that tariffs for
such service incorporating the terms of this Division 1 of this subchapter
are approved for electric utilities that own an interest in the interconnections.
(e)
Obligation to provide transmission service. Each electric
utility in ERCOT that owns transmission facilities shall provide wholesale
transmission service to other electric utilities, power marketers, exempt
wholesale generators, qualifying facilities and other eligible transmission
service customers, in accordance with the provisions of Division 1 of this
subchapter. Each electric utility that owns transmission facilities shall
file a tariff for transmission service and shall take transmission service
for all of its uses of its transmission facilities in accordance with the
terms of its tariff for transmission service.
(1)
Each electric utility that owns transmission facilities
shall provide transmission service to other electric utilities, power marketers,
exempt wholesale generators, qualifying facilities and other eligible transmission
service customers on the same terms and conditions that it provides transmission
service to itself. Where an electric utility has contracted for another person
to operate its transmission facilities, the person assigned to operate the
facilities shall carry out the operating responsibilities of the electric
utility under Division 1 of this subchapter.
(2)
The obligation to provide comparable wholesale transmission
service applies to an electric utility, even if the electric utility's interconnection
with the transmission service customer is through distribution, rather than
transmission facilities.
(A)
A transmission service provider that owns facilities for
the delivery of electricity to an eligible transmission service customer purchasing
electricity at wholesale using facilities rated at less than 60 kilovolts
shall provide an eligible transmission service customer access to the transmission
service provider's delivery points on the same pricing, terms and conditions
used by the transmission service provider in serving similar primary metered
distribution- level customers.
(B)
Beginning September 1, 1999 a transmission service provider
shall also provide access at the distribution level to another electric utility,
in order to transmit power to a retail customer in an area in which the other
electric utility has the right to provide retail electric service. Such service
shall be provided under the same pricing and other terms and conditions available
to the transmission service provider in serving similar customers.
(3)
The obligation to provide transmission service
includes the obligation to provide reactive power support to maintain adequate
system voltage support and control.
(4)
A transmission service provider shall interconnect
its facilities with new generating sources and construct facilities needed
for such an interconnection, in accordance with Division 1 of this subchapter.
(5)
Service provided pursuant to Division 1 of this subchapter
allows a transmission service customer to deliver energy from its planned
resources to serve loads within ERCOT, deliver unplanned energy to its loads
without an additional facilities charge, deliver energy to third parties in
connection with a sale of energy to loads within ERCOT, and transmit power
over transmission facilities within ERCOT for export from ERCOT.
(6)
All transmission service and ancillary services shall
be provided on a non- discriminatory basis, in a manner that is comparable
to the service provider's use of such services to serve its native load customers.
(f)
Resale of transmission rights. A transmission service customer
that holds transmission and ancillary transmission service rights under Division
1 of this subchapter may resell those rights to another eligible transmission
service customer.
(g)
Redispatch. ERCOT utilities shall provide redispatch services
in accordance with §25.200 of this title (relating to Load Shedding,
Curtailments, and Redispatch).
(h)
Scheduling. Control-area utilities shall schedule a transmission
service customer's resources and accommodate changes to schedules requested
by transmission service customers. Control area utilities shall implement
requested schedules and changes to schedules for third party transmission
service customers upon the same terms and conditions and within the same time
frames applied by control area utilities in scheduling resources to serve
their native load customers.
§25.192.Transmission Service Rates.
(a)
Charges for transmission service. Transmission service
customers shall incur both facilities charges and loss compensation charges
for planned transmission service. Transmission service customers shall incur
loss compensation charges and an independent system operator (ISO) fee for
unplanned transmission service. Transmission service customers shall incur
facilities charges and an ISO fee for weekly and daily planned transmission
service. The facilities charge for annual and monthly planned transmission
service shall consist of an access fee and an impact fee. Facilities charges
shall be determined in transmission ratemaking proceedings conducted periodically,
at such intervals as the commission determines are appropriate.
(1)
The costs included in the access fee will be seven-tenths
of the annual cost of transmission service for each transmission service provider
in the Electric Reliability Council of Texas (ERCOT). A transmission service
customer taking planned transmission service will pay a share of these costs,
based on its share of the total load in ERCOT.
(A)
For each transmission service provider, an access rate
will be calculated by dividing seven-tenths of the transmission service provider's
annual transmission cost of service by the total ERCOT load, as calculated
in accordance with this section.
(B)
Each transmission service customer taking annual planned
transmission service will pay an access charge to transmission service providers,
calculated by multiplying the applicable access rate by the transmission service
customer's peak load, as calculated in accordance with this section.
(2)
The costs included in the impact fee will be
three-tenths of each transmission service provider's annual cost of transmission
service. A transmission service customer taking planned transmission service
will pay an impact fee to the transmission service providers, based on the
impact of transmitting its resources to its loads, calculated using the vector-absolute
megawatt-mile method for assessing impacts.
(A)
For each transmission service provider, a megawatt-mile
rate will be calculated by dividing three-tenths of the transmission service
provider's annual transmission costs, as determined in accordance with this
section, by the sum of the megawatt-mile impacts of all planned resources
on the transmission service provider's system, using the impacts calculated
in accordance with §25.194 of this title (relating to Determining Peak
Loads and Megawatt-Mile Impacts).
(B)
Each transmission service customer taking annual planned
transmission service will pay an impact charge to transmission service providers,
calculated by multiplying the applicable rate by the impact of the transmission
service customer's planned resources on the transmission service provider's
system, as calculated in accordance with §25.194 of this title.
(3)
In adopting facilities charges under this section,
the commission shall apply a transition mechanism in 1999 to reduce the impact
of the changes in the level of transmission charges under this section on
an electric utility or its customers. In applying this transition mechanism,
the commission shall calculate the "unadjusted rate impact" for each electric
utility, which shall be the difference between the facilities charge and the
transmission revenues an electric utility would receive under this section,
both calculated at the time transmission rates were first determined under
the commission's open-access transmission rules, and without regard to any
adjustment under this paragraph. An adjustment shall be made to the 1999 facilities
charge equal to 70% of the difference between the 1997 facilities charge incurred
by an electric utility and its annual transmission cost of service for calendar
year 1997.
(4)
The commission may adjust the facilities charges under
this section to account for any transmission revenues that an electric utility
receives under an existing transmission contract.
(5)
The facilities charge for the short-term planned service
described in §25.198 of this title (relating to Initiating Transmission
Service) will be based on a prorated portion of seven-tenths of the annual
cost of transmission service for each transmission service provider and will
be charged on the basis of the megawatts of transmission service that are
reserved. A transmission service customer will be obligated to pay all transmission
service providers for this service upon making a request, whether the customer
uses the service or not. Transmission service providers shall file tariffs
for this service for commission approval.
(b)
Transmission cost of service. The annual transmission cost
of service for each transmission service provider shall be based on the annual
expenses in Federal Energy Regulatory Commission (FERC) expense accounts 560-573
(or accounts with similar contents) plus the depreciation, federal income
tax, and other associated taxes, and the commission-allowed rate of return
based on FERC plant accounts 350-359 (or accounts with similar contents),
less accumulated depreciation and accumulated deferred federal income taxes.
(1)
The following facilities are deemed to be transmission
facilities:
(A)
power lines, substations, and associated facilities, operated
at 60 kilovolts or above, including radial lines operated at or above 60 kilovolts,
except the step-up transformers and a protective device associated with the
interconnection from a generating station to the transmission network;
(B)
substation facilities on the high side of the transformer,
in a substation where power is transformed from a voltage higher than 60 kilovolts
to a voltage lower than 60 kilovolts;
(C)
the portion of the direct-current (DC) interconnections
with the Southwest Power Pool that are owned by a transmission service provider
in ERCOT; and
(D)
capacitors that are operated at a voltage of 60 kilovolts
or below, if they are located in a distribution substation, the load at the
substation has a power factor in excess of 0.95 without the capacitors, and
the capacitors are controlled by an operator or automatically switched in
response to transmission voltage.
(2)
In determining the annual transmission cost of
service under this subsection, the following expenses shall not be included:
(A)
expenses of an electric utility that are otherwise included
in its annual transmission cost for service under any existing transmission
contract (including the value of goods and services exchanged for transmission
service);
(B)
transmission expenses paid to another electric utility
in accordance with this section; and
(C)
expenses for transmission service outside of ERCOT.
(3)
For municipal utilities, river authorities, and
electric cooperatives, the commission may permit the use of reasonable alternative
methods of determining the annual cost of transmission service, including
the cash flow method, consistent with the rate actions of the rate-setting
authority for a municipal utility, and an alternative method for determining
the utility's return, as permitted in paragraph (4) of this subsection.
(4)
For municipal utilities, river authorities, and electric
cooperatives, the return may be determined based on the electric utility's
actual debt service and a reasonable coverage ratio. In determining a reasonable
coverage ratio, the commission will consider the coverage ratios required
in the electric utility's bond indentures or ordinances and the most recent
rate action of the rate-setting authority for the electric utility.
(5)
The commission may adopt rate-filing requirements
that provide additional details concerning the costs that may be included
in the annual transmission cost and how such costs should be reported in a
proceeding to establish transmission rates.
(c)
Billing units. As used in this section, a transmission
service customer's system demand is the average of the demand of the transmission
service customer's retail and wholesale customers for hours that are coincident
with the most recent ERCOT system coincident peak demand. In determining a
transmission service customer's demand and ERCOT system coincident peak demand,
the actual demand on electric utility systems shall be considered, and the
ERCOT system coincident peak demand shall be an average of the highest aggregate
demand in each of the months of June, July, August, and September of the relevant
period. Actual electric utility demand shall be calculated based on the electric
utility's net hourly generation, plus wholesale purchases, minus wholesale
sales.
(1)
The megawatt-mile impact of transmitting resources to load
shall be calculated using the loads and resources at the ERCOT peak and shall
be calculated by the independent system operator or calculated under its supervision.
Megawatt-mile impacts shall be calculated in the manner prescribed in §25.194
of this title.
(2)
Peak demand and megawatt-mile impact may be adjusted
for known and measurable changes to wholesale customer loads and resources,
when such changes can be identified and quantified with reasonable certainty.
(d)
Transmission revenue. The facilities charges prescribed
in subsection (a) of this section are intended to provide each transmission
service provider an opportunity to recover its transmission cost of service.
Revenue from the transmission of electric energy out of ERCOT over the DC
ties that is not recovered through rates for annual planned transmission service
and revenue from monthly, weekly, and daily planned transmission service shall
be credited to all transmission service customers as a reduction in the transmission
cost of service for transmission service providers that receive the revenue.
(e)
Compensation for losses. A transmission service customer
that uses transmission service to transmit power to its loads shall compensate
affected control-area utilities for energy losses resulting from such transmission
service. Losses shall be calculated by the independent system operator under
a method approved by the commission. The method of compensation for losses
shall provide reasonably accurate compensation for the cost of supplying losses
incurred under different system conditions.
(f)
Independent system operator charges. Transmission service
customers shall incur an ISO fee for weekly and daily planned transmission
service and for unplanned transmission service, payable to the independent
system operator. Changes in the fee are subject to approval by the commission.
(g)
Inadvertent energy. Control-area utilities shall compensate
each other for inadvertent energy flows under a tariff requiring monetary
payments. The independent system operator shall develop any necessary procedures
to implement this subsection.
(h)
Transmission rates for exports from ERCOT. Facilities charges,
ISO charges, and loss compensation for exports of power from ERCOT will be
assessed to transmission service customers for that portion of transmission
that is within the boundaries of ERCOT, in accordance with this section.
(1)
For the purposes of facilitating these transactions, the
annual facilities charge shall be prorated on a monthly, weekly, daily and
hourly basis.
(2)
Transmission service customers exporting power from
ERCOT on an unplanned basis will be assessed an access charge based on the
duration of the transaction, and will be charged only for the transmission
service actually used. Transmission service customers exporting power from
ERCOT on a planned basis will be assessed an access charge based on duration
of the service requested.
(3)
The monthly on-peak access fee will be one-fourth
the annual rate, and the monthly off-peak access fee will be one-twelfth the
annual rate. The peak period used to determine the applicable transmission
rate for such transactions shall be the months of June, July, August, and
September. The impact charge will be calculated in accordance with this section.
§25.193.Procedures for Modifying Transmission Rates.
(a)
Revision of transmission rates. Each provider of transmission
and ancillary service in the Electric Reliability Council of Texas shall periodically
revise its transmission and ancillary service rates to reflect changes in
the cost of providing such services. Any request for a change in transmission
rates shall comply with the filing requirements established by the commission
under §25.192 of this title (relating to Transmission Service Rates).
(1)
Each transmission service provider in ERCOT may on an annual
basis update its transmission rates to reflect changes in its invested capital.
If the transmission service provider elects to update its transmission rates,
the new rates shall reflect the addition and retirement of transmission facilities
and additional depreciation on such facilities and changes in loads and megawatt-mile
impacts.
(2)
An update of transmission rates under paragraph (1)
of this subsection shall be subject to reconciliation at the next complete
review of the electric utility's transmission cost of service. The commission
shall review whether the cost of transmission plant additions are reasonable
and necessary at the next complete review of the electric utility's transmission
cost of service. Any over-recovery of costs, as a result of the update, is
subject to refund.
(3)
The commission may prescribe a schedule for providers
of transmission and ancillary services to file proceedings to revise the rates
for such services.
(4)
Mechanisms will be established for a utility that
serves retail load to expeditiously pass through to retail customers changes
in wholesale transmission charges. These mechanisms will be implemented only
following a review of the utility's transmission cost of service after the
effective date of this section, if it is a transmission service provider,
and consistent with any rate freeze applicable to the utility.
(5)
Transmission service providers shall file reports
that will permit the commission to monitor their transmission costs and revenues,
in accordance with filing requirements and a schedule prescribed by the commission.
(b)
Commission order. The facilities rates and charges calculated
in accordance with Division 1 of this subchapter (relating to Transmission
and Distribution), of this title will be converted to monthly amounts, and
such monthly charges will be paid to the transmission service providers. Disputes
concerning the charges for transmission service may be resolved by the commission.
§25.194.Determining Peak Load and Megawatt-Mile Impacts.
(a)
Information relating to peak load and impact calculations.
The vector-absolute megawatt-mile impacts referred to in §25.192 of this
title (relating to Transmission Service Rates) shall be calculated in accordance
with this subsection. Each electric utility in the Electric Reliability Council
of Texas (ERCOT) shall on an annual basis provide to the independent system
operator historical information concerning peak loads and the load and resource
information necessary to perform the calculations described in this section.
(1)
The independent system operator shall establish a working
group, with equal participation from all market participants that are eligible
for participation in the governance of the independent system operator and
shall appoint a chair of the working group. This working group shall review
the peak load information and load flow case and the underlying data, reconcile
the peak load information, and perform the impact calculations. The independent
system operator shall include in the working group any transmission service
provider or eligible transmission service customer that requests to participate.
(2)
The chair of the working group shall report in writing
to the independent system operator either the working group's unanimous acceptance
of the data, or the objections raised to the data by any transmission service
provider or eligible transmission service customer. Disputes over the data
will be resolved in accordance with the procedures for alternative dispute
resolution prescribed in §25.203 of this title (relating to Alternative
Dispute Resolution).
(b)
Peak load. The working group established under this section
shall determine the prior year's peak load for ERCOT and for each transmission
service customer, in accordance with §25.192 of this title. Peak load
will be determined in a consistent manner, to the greatest extent possible,
from one transmission service customer to another.
(c)
Load flow model. Megawatt-miles for all ERCOT loads shall
be determined using a single load flow model that is based on the following
conditions or assumptions:
(1)
the transmission system will be configured as it is anticipated
to operate in the upcoming summer season;
(2)
every generator that is a part of any load's planned
resource commitment will be represented in the calculations; and
(3)
the models and assumptions used will be applied in
a consistent manner, to the greatest extent possible, from one transmission
service provider to another and from one transmission service customer to
another.
(d)
Pairing of loads and resources. The impact calculation
is based on identifying the generating units that, by reason of ownership
or contractual entitlement, are serving the load of a transmission service
customer and have been identified as planned resources. Each group of generating
units and the loads they serve are referred to in this section as a transmission
event.
(e)
Nomination of resources. Each transmission service customer
taking service under Division 1 of this subchapter (relating to Transmission
and Distribution), shall nominate from its list of planned resources a specific
amount of generation from each unit, such that the sum of the nominations
is greater than or equal to 115% of the electric utility's demand or at a
level based on the reserve requirement established by the independent system
operator. Such nominations shall be consistent with an economic dispatch of
the transmission service customer's resources.
(f)
Method. The vector-absolute megawatt-mile impact is an
assessment of the impact of the transmission of power and energy made by calculating
the sum of the impacts of individual transmission lines with a nominal operating
voltage of at least 60,000 volts when measured phase-to-phase. The impact
for each transmission line is the product of the vector-absolute change in
megawatt power flows for the transmission line and the length of each line
in miles, calculated for each generator.
(1)
The impact calculation is based on a single load-flow base
case that takes into account all transmission events.
(2)
The impact calculation is performed for each generator
bus that serves load within a single transmission event, as follows:
(A)
A portion of the load on every bus that is assigned to
the particular transmission event is removed.
(B)
The output of the generators in the transmission event
is reduced by an amount that results in a balancing of load and generation,
without affecting the output of generators that are not included in the transmission
event.
(C)
The vector-absolute change in flow on every line is determined
by comparing the flow calculated in subparagraph (B) of this paragraph with
the base case and multiplying the vector-absolute change in flow, in megawatts,
by the length of the line in miles.
(D)
The megawatt-mile impact per megawatt of generation is
determined by dividing the impact determined in subparagraph (C) of this paragraph
by the generation change used in subparagraph (B) of this paragraph.
(3)
From the information calculated in paragraph
(2) of this subsection, a matrix is prepared that shows the megawatt-mile
impact on each transmission service provider per megawatt of generation for
each generator in each transmission event.
(4)
The total megawatt-mile impact of a transmission event
is determined by summing the product of the nomination level for each generator,
as prescribed in subsection (e) of this section, and the megawatt-mile impact
per megawatt for that generator, as calculated in paragraph (2) of this subsection.
(5)
Using the impacts calculated in accordance with this
subsection, the impact on a transmission service provider's transmission system
will be calculated as follows:
(A)
the total impact of each transmission service customer's
planned resources will be determined by calculating the sum of the customer's
megawatt miles of impact on the transmission service provider's system; and
(B)
the total impact of all transmission service customers'
planned resources will be determined by calculating the sum of all transmission
service customers' megawatt miles of impacts on the transmission service provider's
system.
§25.195.Terms and Conditions for Transmission Service.
(a)
Transmission service requirements. As a condition to obtaining
transmission service, a transmission service customer that owns electrical
facilities in ERCOT shall execute interconnection agreements with the transmission
service providers to which it is physically connected. The commission will
develop a standard agreement for the interconnection of new generating facilities,
and when this standard agreement is approved, it shall be used by transmission
service customers and transmission service providers. The transmission service
customer shall either:
(1)
operate as a control area under applicable guidelines adopted
by the national reliability organization and the independent system operator
for Electric Reliability Council of Texas; or
(2)
satisfy its control area requirements, including the
provision of all necessary ancillary services by contracting with the transmission
service provider or by purchasing the necessary services from another service
provider or non- utility provider of such services, in accordance with good
utility practice.
(b)
Transmission service provider responsibilities. The transmission
service provider will plan, construct, operate and maintain its transmission
system in accordance with good utility practice in order to provide transmission
service customers with planned transmission service over its transmission
system in accordance with Division 1 of this subchapter (relating to transmission
and distribution). The transmission service provider shall include transmission
service customers' load in its transmission system planning and shall, consistent
with good utility practice, endeavor to construct and place into service sufficient
transmission capacity to deliver power from the resources nominated by a transmission
service customer as annual planned resources to serve the customer's load
on the same basis as the transmission service provider's delivery of its own
nominated generating and purchased resources to its native load customers.
The transmission service provider will plan, construct, operate and maintain
facilities that are needed to relieve transmission constraints, as recommended
by the ISO, in accordance with this Division 1 of this subchapter (relating
to Transmission and Distribution). The construction of facilities requiring
commission issuance of a certificate of convenience and necessity is subject
to such commission approval.
(c)
Transmission service customer redispatch obligation. A
transmission service customer will redispatch its resources to provide annual
planned transmission service to third parties. The redispatch of resources
pursuant to Division 1 of this subchapter shall be on a non-discriminatory
basis among all transmission service customers and transmission service providers.
(d)
Priority for transmission service applications. Planned
transmission service shall have priority over unplanned transmission service,
and annual planned transmission service shall have priority over planned transmission
service of a shorter duration.
(1)
Subject to the foregoing priorities, for applications for
planned or unplanned transmission service, complete applications filed earlier
with the independent system operator shall have priority over applications
that are filed later. Requests for annual planned transmission service filed
on or before the date prescribed in this subchapter will be accorded equal
priority.
(2)
Where a transmission service customer is using annual
planned transmission service for a resource that becomes unavailable due to
an unplanned outage or the expiration of a power supply contract, the transmission
service customer shall have priority, in using the same transmission capacity
to transmit power from a replacement resource, over other requests for unplanned
transmission service or planned transmission service of a shorter duration.
(e)
Construction of new facilities. If additional transmission
facilities or interconnections between electric utilities are needed to provide
transmission service pursuant to a request for such service, the transmission
service providers where the constraint exists shall acquire the facilities
necessary to permit the transmission service to be provided, unless the independent
system operator determines that redispatch or other more economical means
of making transmission capacity available will permit the requested transmission
service to be provided. If additional facilities are needed to provide ancillary
services to a customer requesting such service, the ancillary service provider
shall acquire the facilities necessary to permit the ancillary service to
be provided.
(1)
If, in order to provide ancillary services, an electric
utility must construct new facilities, the ancillary services customer may
be required to enter a long- term contract for ancillary service or make a
contribution in aid of construction to cover all or a part of the cost of
acquiring the new facilities, to the extent that the acquisition of the additional
facilities is for the customer's benefit.
(2)
When an eligible transmission service customer requests
transmission service for a new generating source that is planned to be interconnected
with a transmission service provider's transmission network, the transmission
service customer shall be responsible for the cost of installing step-up transformers
to transform the output of the generator to a transmission voltage level and
a protective device at the point of interconnection. The transmission service
provider shall be responsible for the cost of installing any other interconnection
facilities that are designed to operate at a transmission voltage level and
any other transmission system upgrades that may be necessary to accommodate
the requested transmission service.
(A)
An affected transmission service provider may require the
transmission service customer to pay a reasonable deposit or provide another
means of security, to cover the costs of planning, licensing, and constructing
any new transmission facilities that will be required in order to provide
the requested service.
(B)
If the new generating source is completed and the transmission
service customer begins to take the requested transmission service, the transmission
service provider shall return the deposit or security to the transmission
service customer. If the new generating source is not completed and new transmission
facilities are not required, the transmission service provider may retain
as much of the deposit or security as is required to cover the costs it incurred
in planning, licensing, and construction activities related to the planned
new transmission facilities. Any repayment of a cash deposit shall include
interest at a commercially reasonable rate.
(3)
An eligible transmission service customer that
is requesting transmission or ancillary service may be required to make a
contribution in aid of construction to cover all or a part of the cost of
acquiring additional facilities, if the acquisition of the additional facilities
would impair the tax-exempt status of obligations issued by the provider of
transmission or ancillary services.
(f)
Curtailment of service. In an emergency situation, as determined
by the independent system operator and at its direction, control-area utilities
may interrupt transmission service, if necessary, to preserve the stability
of the transmission network and service to customers. Such curtailments shall
be carried out in accordance with §25.200 of this title (relating to
Load Shedding, Curtailments, and Redispatch).
(g)
Filing of contracts. Electric utilities shall file with
the commission all new interconnection agreements and agreements involving
the sale or purchase of electric utility generation, transmission, or ancillary
services at wholesale within 30 days of their execution. Upon a showing of
good cause, appropriate portions of the filings required under this subsection
may be subject to provisions of confidentiality to protect competitively sensitive
commercial or financial information. Interconnection agreements are subject
to commission review and approval upon request by any party to the agreement.
§25.196.Functional Unbundling.
(a)
Cost separation. Each electric utility that is subject
to the requirements in §25.221 of this title (relating to Electric Cost
Separation) shall separate its costs and rates in accordance with the provisions
of that section. Other electric utilities in the Electric Reliability Council
of Texas shall separate their costs and rates, based on the costs associated
with the utility's generation, transmission, and distribution functions. Unless
otherwise directed by the commission, the cost and rate separation requirements
prescribed in this section shall not require the statement of unbundled rates
on retail customer bills.
(b)
Separation of functions. Each electric utility subject
to the rules in Division 1 of this subchapter (relating to Transmission and
Distribution) that operates a control area shall functionally separate the
operation of its transmission facilities and the operation of its wholesale
power purchase and sale activities.
(1)
Electric utility personnel shall be physically separated
to the maximum extent practicable and necessary to accomplish the purposes
of this section. Each electric utility subject to this section shall make
a filing with the commission showing how it will implement the requirements
of this section, including written procedures governing the exchange of information
and physical separation of personnel among its functionally separated organizational
units. This filing shall be amended if the requirements of this section are
amended or the electric utility changes its organization or procedures relating
to the requirements of this section.
(2)
Electric utilities may request limitations on the
requirement to separate their personnel, based on a showing that complete
physical separation would impair the reliability of electric service. The
electric utility bears the burden of demonstrating that the separation of
personnel requirements contained in this rule would impair system reliability.
(3)
An electric utility with an affiliate that owns a
generating facility in the electric utility's retail service area shall not
buy power from the affiliate, either directly or through a power marketer,
without express authorization from the commission. This provision does not
apply to any purchase agreement that was entered prior to the effective date
of this section.
(4)
An affiliate of an electric utility shall not construct
a new generating plant in the electric utility's retail service area, either
directly or through an exempt wholesale generator or qualifying facility,
unless the facility is approved in accordance with §25.170 of this title
(relating to Hearing on the Final Integrated Resource Plan) or the electric
utility meets the following conditions:
(A)
the electric utility separates its generation operations
and transmission operations into separate corporate entities, in a manner
approved by the commission; and
(B)
the generation and transmission operations of the electric
utility and its affiliates operate under a code of conduct approved by the
commission.
(5)
Paragraph (4) of this subsection shall not apply
to any generating facility for which an affiliate of an electric utility has
made, prior to March 11, 1999, a firm commitment for construction of such
a facility under a contract with an unrelated person or submitted a written
offer or proposal to an unrelated person for the construction of such a facility.
(6)
If the commission finds that an electric utility has
violated the rules in Division 1 of this subchapter, it may impose an appropriate
penalty, including the following:
(A)
assess an administrative penalty under the Public Utility
Regulatory Act §15.023; or
(B)
prohibit the utility and any affiliate of the utility from
constructing a new generating facility in the electric utility's retail service
area, unless the facility is approved in accordance with §25.170 of this
title or §25.171 of this title (relating to Certificate of Convenience
and Necessity for Generation Facilities).
(c)
Standards of conduct. In performing its obligations under
Division 1 of this subchapter, a transmission or ancillary service provider
shall apply the provisions of this section in a non-discriminatory manner
to all users, including itself. In addition, any electric utility that operates
a control area shall comply with the following standards:
(1)
The employees of an electric utility that are engaged in
wholesale merchant functions (that is, the purchase or sale of electric energy
at wholesale), other than purchases required under the Public Utility Regulatory
Policies Act, shall not:
(A)
conduct transmission system operations or reliability functions;
(B)
have preferential access to the electric utility's system
control center and other facilities, beyond the access that is available to
other market participants;
(C)
have preferential access to information about the electric
utility's transmission system that is not available to users of the electronic
information network established in accordance with Division 1 of this subchapter;
or
(D)
obtain information about the electric utility's transmission
system and offerings of ancillary services, including calculations of available
transmission capacity and information concerning curtailments, through means
or sources other than the electronic information network operated by the independent
system operator.
(2)
To the maximum extent practicable, employees
of an electric utility engaged in transmission system operations must function
independently of employees engaged in wholesale merchant functions and of
employees of any affiliate of the electric utility. Employees engaged in transmission
system operations may disclose information to employees of the electric utility
engaged in merchant functions only through the electronic information network,
if the information relates to the electric utility's transmission system or
offerings of ancillary services, including calculations of available transmission
capacity and information concerning curtailments.
(3)
Information concerning transfers of persons between
an organizational unit that is responsible for transmission system operations
and a unit that is responsible for wholesale merchant functions shall be provided
to the independent system operator on a monthly basis and shall be made available,
on request, to any market participant.
(4)
If an employee of an electric utility discloses or
obtains information in a manner that is inconsistent with the requirements
in this subsection, the electric utility shall post a notice and details of
the disclosure on the information network.
(5)
Employees of an electric utility engaged in transmission
operations shall apply the rules in Division 1 of this subchapter and any
tariffs relating to transmission and ancillary service in a fair and impartial
manner.
(6)
Provisions of this section that allow no discretion
shall be strictly applied, and where discretion is allowed, it shall be exercised
in a non-discriminatory manner.
(7)
This subsection shall not apply to data that do not
relate to transmission service operations such as information on human resource
policies.
(d)
Communications with eligible customers. A transmission
or ancillary service provider shall use all reasonable efforts to communicate
promptly with all eligible customers to resolve any questions regarding their
requests for service in a non- discriminatory manner.
(e)
Standard of due diligence. If a transmission or ancillary
service provider or customer is required to complete activities or to negotiate
agreements as a condition of service, each party shall use due diligence to
complete these actions within a reasonable time.
§25.197.ERCOT Independent System Operator.
(a)
Purpose. The purpose of the independent system operator
is to foster a healthy wholesale market in the Electric Reliability Council
of Texas (ERCOT) by maintaining the reliability of the electrical network
and facilitating wholesale market transactions.
(b)
Governance. The ERCOT independent system operator shall
be administered through procedures that allow equal participation by all wholesale
market participants and retail customers. Effective September 1, 1999, retail
customers shall have the same level of representation on the governing board
as each of the wholesale market groups. One of the retail representatives
shall be the Public Utility Counsel or her designee, and the governing board
of the independent system operator shall consult with members of organizations
representing retail customers and develop a procedure for selecting the other
retail members.
(c)
Functions. The ERCOT independent system operator shall
operate an integrated ERCOT electronic transmission information network and
carry out the other functions prescribed by this section. The independent
system operator's responsibilities shall include, but not be limited to the
following:
(1)
administering, on a daily basis, the ERCOT transmission
tariffs, including determining whether a person is eligible for transmission
service;
(2)
serving as the single point of contact for the initiation
of transmission transactions;
(3)
supervising the performance of functions related to
the reliability and security of the ERCOT electrical network, including ensuring
that control areas perform the instantaneous balancing of ERCOT generation
and load and monitoring the adequacy of resources to meet demand;
(4)
coordinating the scheduling of ERCOT generation and
transmission transactions;
(5)
directing the curtailment and redispatch of ERCOT
generation and transmission transactions on a non-discriminatory basis to
preserve system reliability in emergencies, including determining how any
curtailment or redispatch would be accomplished, the cost of the redispatch,
and the assignment of redispatch cost responsibility, in accordance with the
provisions of Division 1 of this subchapter (relating to Transmission and
Distribution);
(6)
analyzing, coordinating, and directing the redispatch
of ERCOT generation transactions on a non-discriminatory basis for economic
purposes to free up transmission capacity, including determining how any curtailment
or redispatch would be accomplished, the cost of the redispatch, and the assignment
of redispatch cost responsibility, in accordance with the provisions of Division
1 of this subchapter;
(7)
implementing the loss compensation mechanism approved
by the commission and administering transaction accounting among market participants;
(8)
accepting and supervising the processing of all requests
for interconnection to the ERCOT transmission system from owners of new generating
facilities;
(9)
performing any system security study, with the assistance
of affected transmission service providers, when a joint study agreement has
been executed with a transmission service customer requesting transmission
service under Division 1 of this subchapter;
(10)
supervising ERCOT transmission system planning, in
accordance with subsection (f) of this section; and
(11)
administering the alternative dispute resolution
procedures in §25.203 of this title (relating to Alternative Dispute
Resolution).
(d)
Electronic transmission information network. The ERCOT
electronic transmission information network shall permit electric utilities,
qualifying facilities, power marketers, and exempt wholesale generators to
have contemporaneous, real-time access to information concerning the availability
of transmission service and the availability and cost of ancillary services
on a non- discriminatory basis. Transmission-owning electric utilities in
ERCOT shall rely upon this information network to obtain contemporaneous access
to information about the ERCOT transmission system.
(1)
The ERCOT electronic transmission information network will,
at a minimum, provide all information required under any Federal Energy Regulatory
Commission (FERC) regulations governing electronic transmission information
networks, which apply to electric utilities under FERC jurisdiction, subject
to appropriate regional variations approved by the FERC. Information that
an electric utility is required to make available to market participants in
accordance with §25.196 of this title (relating to Functional Unbundling)
shall be posted on the electronic information network. The information on
the network shall include, but not be limited to:
(A)
total and available transfer capability for transmission
of energy between areas in ERCOT and to, from, and over the direct-current
(DC) interconnections with the Southwest Power Pool;
(B)
ERCOT transmission prices;
(C)
ancillary service prices, including any pricing discounts
for such services;
(D)
requests and offers for transmission service and ancillary
transmission services on the primary and secondary transmission markets;
(E)
transmission scheduling data;
(F)
transmission service curtailment and interruption data;
and
(G)
information necessary to verify redispatch cost calculations.
(2)
The methodology used and data required to independently
reproduce information related to the total and available transfer capability
for the transmission of energy between ERCOT control areas and to, from, and
over the DC ties shall be provided upon request to any transmission service
customer.
(3)
The electronic information system shall also include
a capability for posting generation bids and offers.
(4)
Electric utilities shall use the electronic information
network when offering ancillary services, requesting transmission service,
and responding to requests for transmission service. Market participants other
than electric utilities may also post offers to sell ancillary services on
the electronic information network.
(e)
Commercial functions. The ERCOT independent system operator
shall not purchase or sell bulk electricity. The ERCOT independent system
operator shall not dispatch generation facilities, but shall have full authority
to direct the redispatch of generation facilities under the circumstances
specified in Division 1 of this subchapter.
(f)
Planning. The independent system operator shall supervise
ERCOT transmission system planning and exercise comprehensive authority over
the planning of bulk transmission projects that affect the transfer capability
of the ERCOT transmission system. The independent system operator's authority
with respect to transmission projects that are local in nature is limited
to supervising and coordinating the planning activities of transmission service
providers.
(1)
The independent system operator shall evaluate and make
a recommendation to the commission as to the need for any transmission facility
over which it has comprehensive transmission planning authority. A proposal
for new transmission facilities subject to the independent system operator's
planning authority shall be submitted to the independent system operator at
least 60 days prior to the filing of an application for the certification
of the transmission facilities with the commission, if applicable.
(2)
A transmission service provider shall coordinate its
transmission planning efforts with those of other transmission service providers,
insofar as its transmission plans affect other transmission service providers.
(3)
Within 120 days of the effective date of this section,
the independent service operator shall submit to the commission its proposed
guidelines and procedures for implementing this subsection. The independent
system operator shall submit to the commission any subsequent revisions or
additions to the guidelines and procedures as they are proposed. The independent
system operator may seek input from the commission as to the content and implementation
of its guidelines and procedures as it deems necessary.
(g)
Information and coordination. Providers of transmission
and ancillary services and customers of such service providers shall provide
such information as may be required by the independent system operator to
carry out the functions prescribed by this section. The ERCOT independent
system operator shall have a fiduciary responsibility to maintain the confidentiality
of competitively sensitive information entrusted to it by providers of transmission
and ancillary services, their customers, and prospective customers. Providers
of transmission and ancillary services shall also maintain the confidentiality
of competitively sensitive information entrusted to them by the independent
system operator or a transmission or ancillary services customer.
(h)
Interconnection standards. In performing its functions
related to the reliability and security of the ERCOT electrical network, the
ERCOT independent system operator may prescribe reliability and security standards
for the interconnection of generating facilities that use the ERCOT transmission
network. Such standards shall not adversely affect or impede manufacturing
or other internal process operations associated with such generating facilities,
except to the minimum extent necessary to assure reliability of the ERCOT
transmission network.
(i)
Reports. The independent system operator shall periodically
file with the commission reports concerning the reliability of the ERCOT electrical
network and its transmission planning efforts, including a list of any transmission
projects that it recommends.
(j)
Disputes. Any disputes regarding the administration, procedures,
decisions, or conduct of the ERCOT independent system operator may be submitted
to the commission for resolution.
(k)
Anti-trust laws. The existence of the ISO is not intended
to affect the application of any state or federal anti-trust laws.
§25.198.Initiating Transmission Service.
(a)
Initiating service. Where a transmission service customer
uses the transmission facilities in the Electric Reliability Council of Texas
(ERCOT), whether its own facilities or those of another transmission service
provider, in serving its native load or in making sales of energy to a third
party, it shall apply for transmission service pursuant to this section. Transmission
service customers and transmission service providers shall provide the information
that is required under this section to the independent system operator.
(b)
Conditions precedent for receiving service. Subject to
the terms and conditions of this section, the transmission service provider
will provide transmission service to any eligible transmission service customer,
provided that:
(1)
the eligible transmission service customer has completed
an application for service under subsection (c), (d), or (e) of this section;
(2)
the eligible transmission service customer and the
transmission service provider have completed the technical arrangements set
forth in subsection (g) of this section;
(3)
if the eligible transmission customer operates electrical
facilities that are interconnected to the facilities of a transmission service
provider, it has executed an interconnection agreement for service under this
section or requested in writing that the transmission service provider file
a proposed unexecuted agreement with the commission;
(4)
the eligible transmission service customer has arranged
for ancillary services necessary for the transaction; and
(5)
if the eligible transmission service customer is responsible
for serving wholesale load, it shall maintain a power factor of 95% or greater
at each point of interconnection.
(c)
Application procedures for annual planned transmission
service. An eligible transmission service customer requesting annual planned
transmission service under this section must submit an application for service
to the independent system operator, no later than October 1 in the year preceding
the year in which service is to commence. The purpose of this application
is to identify deficiencies in the ERCOT transmission system so that plans
may be formulated by the independent system operator and transmission service
providers to correct these deficiencies. A completed application shall provide
information required in paragraph (1) of this subsection.
(1)
The following information shall be provided in connection
with an application for service under this section:
(A)
the identity, address, e-mail address, telephone number
and facsimile number of the party requesting service and the name of a contact
person to deal with matters relating to the application;
(B)
a statement that the party requesting service is, or will
be upon commencement of service, an eligible transmission service customer
under Division 1 of this subchapter (relating to Transmission and Distribution);
(C)
a description of the load to be served (including a five-year
forecast of summer and winter peak load and resource requirements beginning
with the first year after the service is scheduled to commence, in the format
prescribed by the independent system operator);
(D)
a description of planned resources (current and five-year
projection), which shall include, for each resource:
(i)
location, unit size and amount of capacity from a unit
to be designated as a resource,
(ii)
reactive power capability (both leading and lagging) of
all generators,
(iii)
operating restrictions, including:
(I)
any periods of restricted operations during the year;
(II)
minimum loading level of unit,
(III)
normal operating level of unit, and
(IV)
any must-run unit designations required for system reliability
or contract reasons,
(iv)
a description of purchased power designated as a resource,
including source of supply, control area location, transmission arrangements
and, if applicable, delivery points into ERCOT,
(v)
to the extent arrangements have been made for ancillary
services, the identity of the providers of ancillary services,
(vi)
the service commencement date of the requested transmission
service and service termination date or duration of service,
(vii)
where the transmission service customer serving the load
does not own the resource, a copy of the contract between the transmission
service customer and the owner of the resource, which may be redacted to remove
market- sensitive information not needed in assessing the request for service,
and
(viii)
any other information designated by the independent
system operator as reasonably necessary to evaluate the ability of the interconnected
ERCOT transmission systems to reliably accommodate the requested service.
(2)
The independent system operator shall provide
to affected transmission service providers the information needed for them
to evaluate the request.
(3)
The independent system operator must acknowledge the
request within ten days of receipt. The acknowledgment must include a date
by which a response will be sent to the eligible transmission service customer
and a statement of any fees associated with responding to the request (e.g.,
system studies).
(4)
If an application fails to meet the requirements of
this subsection, the independent system operator shall notify the eligible
transmission service customer requesting service within 15 days of receipt
and specify the reasons for such failure. Wherever possible, the independent
system operator will attempt to remedy deficiencies in the application through
informal communications with an eligible transmission service customer.
(5)
If a system security study is required, upon approval
of the requesting transmission service customer, the independent system operator
will initiate such a study. If this study concludes that the transmission
system is adequate to accommodate the request for service, either in whole
or in part, or that no costs are likely to be incurred for new transmission
facilities or upgrades, the transmission service will be initiated or tendered,
within 15 days of completion of the system security study.
(6)
If the independent system operator determines as a
result of the system security study that additions or upgrades to the transmission
system are needed to supply the transmission service customer's forecasted
transmission requirements, the transmission service provider will, upon the
approval of the requesting transmission service customer, initiate a facilities
study. When completed, a facilities study will include an estimate of the
cost of any required facilities or upgrades and the time required to complete
such construction and initiate the requested service.
(7)
Unplanned transmission service transactions of a duration
of 30 days may be converted to planned transmission service transactions upon
approval of an application submitted pursuant to subsection (d) of this section.
To the extent that such a conversion requires more megawatt miles than those
offset by terminating a previously approved planned transaction, the additional
megawatt miles may be purchased from transmission service providers or from
other transmission service customers. The participants to such a transaction
are responsible for the costs of feasibility analysis.
(d)
Application procedures for other planned transmission service.
An eligible transmission service customer may request monthly, weekly, or
daily planned transmission service in connection with a change in its designated
planned resources or other transmission needs. The independent system operator
may establish hourly planned transmission service, if it deems that it is
feasible.
(1)
The independent system operator shall determine maximum
and minimum lead times for submitting requests for planned transmission service
other than annual planned transmission service.
(2)
The application must provide information similar to
that required for annual planned transmission service for the period that
the planned transmission service is to be effective.
(3)
When the independent system operator determines that
the service can be provided and a system security study is not required it
will notify the requesting transmission service customer and tender transmission
service.
(4)
The independent system operator shall develop charges
for planned transmission service under this subsection, in accordance with
§25.192 of this title (relating to Transmission Service Rates). The transmission
charges shall be subject to commission approval.
(e)
Application for unplanned transmission service. Eligible
transmission service customers wishing to use the ERCOT transmission system
for unplanned transmission service must submit a request for service to the
independent system operator. The duration for unplanned transactions is from
one hour to 30 days. In no case shall unplanned transactions be accepted for
consideration more than 30 days in advance of the actual commencement of service.
(1)
Requests for service must be submitted with at least the
lead times prescribed in subparagraphs (A)-(D) of this paragraph:
(A)
for hourly transactions, at least 20 minutes in advance,
(B)
for daily transactions, no later than 2:00 p.m. the day
before the transaction is to commence,
(C)
for weekly transactions, at least two days in advance,
and
(D)
for monthly transactions, at least four days in advance.
(2)
A response to a request for service will be made
by the independent system operator as soon as practical after the request
is made. Unless the parties agree to a different time frame, responses to
requests for unplanned transmission service shall be provided no later than
the times prescribed in subparagraphs (A)-(D) of this paragraph:
(A)
for hourly transactions, within 10 minutes of the request
for service,
(B)
for daily transactions, within four hours of the request
for service,
(C)
for weekly transactions, within 24 hours of the request
for service, and
(D)
for monthly transactions, within two days of the request
for service.
(3)
A request for a transaction will be analyzed
first for the next hour and allowed to start if no violations of the transmission
operating criteria are anticipated.
(4)
The following information shall be provided in connection
with an application for unplanned transmission service:
(A)
the identity, address, telephone number and facsimile number
of the party requesting service and contact person to deal with questions
concerning the application for service;
(B)
a statement that the party requesting service is, or will
be upon commencement of service, an eligible transmission service customer
under this section;
(C)
a description of the load to be served and the resources
serving the load, which shall include, for each resource:
(i)
location, unit size and amount of capacity from that unit
to be designated as resource,
(ii)
reactive power capability (both leading and lagging) of
all generators,
(iii)
operating restrictions, including minimum loading level
of unit, and normal operating level of unit,
(iv)
a description of purchased power designated as a resource
including source of supply, control area location, and, if applicable, delivery
points into ERCOT,
(v)
to the extent arrangements have been made for ancillary
services, the identity of the providers of ancillary services,
(vi)
when service is to begin and the anticipated duration,
and
(vii)
if the unplanned transmission service will result in
the transmission service customer's using different resources than its planned
resources, a statement of the effect of the unplanned transmission service
on the use of the planned resources.
(5)
The independent system operator will make
every reasonable attempt to begin the transactions as soon as possible to
conform to the requested commencement time. Operating restrictions, anticipated
redispatch needs, the potential for curtailment, and other related information,
if known, will be communicated to the requester to see if the transactions
are still feasible for the eligible transmission service customer given the
known restrictions.
(6)
The independent system operator, at its discretion,
may take requests outside the timeframes prescribed in paragraph (1) of this
subsection, if practical given the current or expected operating conditions
on the transmission service providers' systems. The independent system operator
may set longer notification and response times than those prescribed in paragraphs
(1) and (2) of this subsection, during a system emergency, and shall periodically
review the notification and response times and may propose to the commission
revisions to those times. The independent system operator may put such revisions
into effect, pending action by the commission on its proposal.
(f)
System security study. When a transmission service customer
applies for planned transmission service for a new resource under this section,
the independent system operator shall notify affected transmission service
providers of the application and request comments from them concerning the
scope of any security study. The transmission service customer and the independent
system operator shall execute a joint study agreement for performing a system
security study to determine the feasibility of integrating such new resource
into the transmission service providers' transmission system, and whether
any upgrades of facilities providing transmission or ancillary services are
needed. The independent system operator will perform the security study.
(1)
In performing the system security study, the independent
system operator shall apply the same methods and criteria that the transmission
service providers employ in integrating new resources or new loads.
(2)
The independent system operator shall complete the
system security study and provide the results to the transmission service
customer within 60 days after the receipt of the executed study agreement
and receipt from the transmission service customer of all the data necessary
to complete the study. In the event the independent system operator is unable
to complete the study within the 60 day period, it will provide the transmission
service customer a written explanation of when the study will be completed
and the reasons for the delay.
(3)
The requesting transmission service customer shall
be responsible for the cost of the system security study and shall be provided
with the results thereof, including relevant workpapers.
(4)
The independent system operator will use a methodology
consistent with good utility practice to conduct a system security study and
shall coordinate with affected transmission service providers as needed in
determining the most efficient means for all electric utilities in ERCOT to
assure feasibility of transmission service.
(g)
Facilities study. Based on the results of the system security
study, the transmission service provider shall perform, pursuant to an executed
facilities study agreement with the transmission service customer, a facilities
study addressing the detailed engineering, design and cost of transmission
or ancillary services facilities required to provide the requested transmission
service.
(1)
The facilities study will be completed as soon as reasonably
practicable. If the transmission service provider may charge a contribution
in aid of construction under §25.195 of this title (relating to Terms
and Conditions for Transmission Service), the transmission service provider
shall notify the transmission service customer whether it considers that a
contribution in aid of construction is appropriate and the amount of the contribution.
The transmission service provider shall base its request on the information
in the system security study and the facilities study and the rules in §25.195
of this title.
(2)
The transmission service customer shall be responsible
for the reasonable cost of the facilities study pursuant to the terms of the
facilities study agreement and shall be provided with the results of the facility
study, including relevant workpapers.
(3)
The transmission service provider shall be responsible
for the costs of any facilities study undertaken to determine the engineering,
design and cost of facilities associated with the transmission service provider's
addition of new resources used to serve the transmission service provider's
load. Such costs will be separately booked by the transmission service provider.
(h)
Technical arrangements to be completed prior to commencement
of service. Service under this section shall not commence until the installation
has been completed of all equipment specified under the interconnection agreement,
consistent with guidelines adopted by the national reliability organization
and the independent system operator, except that the transmission service
provider shall provide the requested transmission service, to the extent that
such service does not impair the reliability of other transmission service.
The transmission service provider shall exercise reasonable efforts, in coordination
with the transmission service customer, to complete such arrangements as soon
as practical prior to the service commencement date.
(i)
Transmission service customer facilities. The provision
of transmission service shall be conditioned upon the transmission service
customer's constructing, maintaining and operating the facilities on its side
of each point of interconnection that are necessary to reliably interconnect
and deliver power from a resource to the transmission system and from the
transmission system to the transmission service customer's loads.
(j)
Transmission arrangements for resources located outside
of ERCOT. It shall be the transmission service customer's responsibility to
make any transmission arrangements necessary for delivery of capacity and
energy produced from a resource outside of ERCOT to the interconnection with
the Southwest Power Pool. The independent system operator and transmission
service provider shall undertake reasonable efforts to assist the transmission
service customer in coordinating and scheduling arrangements with connecting
systems within ERCOT.
(k)
Changes in service requests. A transmission service customer's
decision to cancel or delay the addition of a new planned resource shall not
relieve the transmission service customer of the obligation to pay a contribution
in aid of construction to cover the costs of transmission facilities constructed
by a transmission service provider, under the rules in §25.195 of this
title. Upon receipt of a transmission service customer's written notice of
such a cancellation or delay, a transmission service provider will use the
same reasonable efforts to mitigate the costs and charges owed by the transmission
service customer to the transmission service provider as it would to reduce
its own costs and charges.
(l)
Annual load and resource information updates. A transmission
service customer shall provide the independent system operator with annual
updates of load and resource forecasts consistent with those included in its
application for transmission service by October first of each year. The transmission
service customer also shall provide the independent system operator with timely
written notice of material changes in any other information provided in its
application relating to the transmission service customer's planned load,
resources, its transmission system or other aspects of its facilities or operations
affecting the transmission service provider's ability to provide reliable
service under Division 1 of this subchapter.
(m)
Termination of planned transmission service. A transmission
service customer may terminate planned transmission service after providing
the transmission service provider with written notice of the transmission
service customer's intention to terminate. A transmission service customer's
provision of notice to terminate service under this section shall not relieve
the transmission service customer of its obligation to pay transmission service
providers any rates, charges, or fees, including contributions in aid of construction,
for service previously provided under the applicable interconnection service
agreement, and which are owed to transmission service providers as of the
date of termination.
§25.200.Load Shedding, Curtailments, and Redispatch.
(a)
Procedures. Transmission service providers and the independent
system operator shall establish non-discriminatory emergency load shedding
and curtailment procedures for responding to emergencies on the transmission
system.
(1)
Transmission service providers and transmission service
customers will comply with the load shedding and curtailment procedures established
under this section.
(2)
Transmission service providers and customers will
implement such programs during any period when the independent system operator
determines that a transmission capacity constraint exists and such procedures
are necessary to alleviate the constraint.
(3)
The transmission service provider will notify the
independent system operator in a timely manner of any scheduled transmission
facility interruption (e.g., scheduled maintenance).
(b)
Transmission constraints and redispatch. During any period
when the independent system operator determines that a transmission constraint
exists on the transmission system, and such constraint may impair the reliability
of a transmission service provider's system or adversely affect the operations
of either a transmission service provider or a transmission service customer,
the independent system operator will take whatever actions, consistent with
good utility practice, that are reasonably necessary to maintain the reliability
of the transmission service provider's system and avoid interruption of service.
The independent system operator shall notify affected transmission service
providers and transmission service customers of the actions being taken. In
these circumstances, transmission service providers and transmission service
customers shall take such action as the independent system operator directs.
(1)
Any interruption shall be based on operational factors
and shall not accord a higher priority to the electric utility's native load
customers than to its customers taking transmission service. Priority shall
be accorded to transmission service customers in accordance with §25.195(d)
of this title (relating to Terms and Conditions for Transmission Service).
(2)
Service to all transmission service customers shall
be restored as quickly as possible.
(3)
The independent system operator shall determine whether
a proposed redispatch is cost-effective and which transmission service customer
shall redispatch its generating resources to facilitate a transaction.
(4)
To the extent the independent system operator determines
that the reliability of the transmission system can be maintained by redispatching
resources, or when redispatch arrangements are necessary to facilitate generation
and transmission transactions for an eligible transmission service customer,
a transmission service provider or transmission service customer will initiate
procedures to redispatch its resources, as directed by the independent system
operator. The obligation to redispatch resources includes the obligation to
redispatch non-utility resources that a transmission service customer is relying
on.
(5)
To the greatest extent possible, any redispatch shall
be made on a least-cost non-discriminatory basis. Any redispatch under this
section will provide for equal treatment among transmission service customers,
subject to the priorities set out in §25.195(d) of this title. If the
independent system operator determines that a transmission service provider
will not have adequate transmission capacity to satisfy the full amount of
a valid request for planned transmission service, the transmission service
provider nonetheless shall be obligated to offer and provide the portion of
the requested planned transmission service that can be accommodated without
addition of any facilities. This obligation includes a duty to redispatch
resources to increase the level of planned transmission service that may be
provided. However, the transmission service provider shall not be obligated
to provide transmission service, to the extent that the service requires the
addition of facilities or upgrades to the transmission system, until such
facilities or upgrades have been placed in service.
(c)
Cost responsibility for relieving capacity constraints.
Electric utilities in the Electric Reliability Council of Texas (ERCOT) shall
provide redispatch services on a non-discriminatory basis to all wholesale
market participants when necessary to preserve system reliability or to alleviate
transmission constraints that impede wholesale generation and transmission
transactions. The independent system operator shall keep a record of the circumstances
requiring redispatch.
(1)
The price for redispatch services for annual planned transactions
shall be based on the cost of providing the service, which shall be allocated
among transmission service customers in proportion to each customer's share
of the transmission cost of service, as determined by the commission under
§25.192 of this title (relating to Transmission Service Rates). For redispatch
required to accommodate an annual planned transaction, the electric utility
providing the redispatch service shall provide information documenting the
costs incurred to provide the service to the independent system operator.
This information shall be available to affected persons.
(2)
The cost of redispatch services for other transactions
(including planned transmission service of a duration of less than a year)
shall be borne by the transmission service customer for whose benefit the
redispatch is made. Electric utilities shall provide binding advance bids
for redispatch services for unplanned transactions. The participants in unplanned
transactions shall be promptly notified by the independent system operator
that their transactions may be or have been continued through redispatch;
shall be informed of the cost of the redispatch measures; and shall have the
opportunity to abandon or curtail their transactions to avoid additional redispatch
costs.
(3)
ERCOT utilities that are required to provide ancillary
services under Division 1 of this subchapter (relating to Transmission and
Distribution), shall include in their tariffs a standard methodology for calculating
redispatch costs.
(4)
To the extent that non-utility resources are redispatched
by an electric utility pursuant to this subsection, the compensation for such
services shall be consistent with this subsection.
(d)
System reliability. Notwithstanding any other provisions
of this section, the transmission service provider reserves the right, consistent
with good utility practice and on a non-discriminatory basis, to interrupt
transmission service without liability on the transmission service provider's
part for the purpose of making necessary adjustments to, changes in, or repairs
to its lines, substations and other facilities, or where the continuance of
transmission service would endanger persons or property.
(1)
In the event of any adverse condition or disturbance on
the transmission service provider's system or on any other system directly
or indirectly interconnected with the transmission service provider's system,
the transmission service provider, consistent with good utility practice,
may interrupt transmission service on a non-discriminatory basis in order
to limit the extent or damage of the adverse condition or disturbance, to
prevent damage to generating or transmission facilities, or to expedite restoration
of service.
(2)
The transmission service provider will give the independent
system operator, affected transmission service customers, and affected suppliers
of generation as much advance notice as is practicable in the event of such
interruption.
(3)
The transmission service customer's failure to respond
to established emergency load shedding and curtailment procedures to relieve
emergencies on the transmission system may result in the transmission service
customer being deemed by the transmission service provider to be in default
and subject to an assessment of an administrative penalty under the Public
Utility Regulatory Act §15.023.
(4)
The independent system operator shall report the interruption
to the commission, together with a description of the events leading to the
interruption, the services interrupted, the duration of the interruption,
and the steps taken to restore service.
§25.201.Ancillary Services.
(a)
Ancillary services. Each electric utility in the Electric
Reliability Council of Texas (ERCOT) that operates a control area shall provide
the following ancillary services:
(1)
Static scheduling is a service that establishes specific
hourly schedules for the transmission of power, by coordinating the event
among the affected control areas.
(2)
Dynamic scheduling is a service that may be used for
load or generation that is connected to the transmission system of one control
area to access bulk power and ancillary services from another control area.
(3)
Load regulation service provides intra-hour changes
in the output of generating units to match changes in the load being served.
(4)
Generation-schedule imbalance service compensates
for energy mismatches between the scheduled and actual transmission between
the seller of power and a provider of transmission service in the generation
host's control area.
(5)
Load-schedule imbalance service compensates for energy
mismatches between the scheduled and actual transmission between the seller
of power and a provider of transmission service in the load host's control
area.
(6)
Emergency energy service consists of scheduling services,
capacity and energy required to replace a capacity resource in an emergency,
at the direction of the independent system operator.
(b)
Reserve generation services. Each electric utility in ERCOT
that operates a control area shall provide the following services, unless
the commission otherwise orders:
(1)
Responsive reserve consists of the daily operating reserves
that are intended to help restore the frequency of the interconnected transmission
system within the first few minutes of an event that causes a significant
deviation from the standard frequency. Responsive reserves may be provided
by unloaded generation facilities that are on line, interruptible load controlled
by high set under-frequency relays, or from a direct-current (DC) tie response
that stops frequency decay.
(2)
Spinning reserve consists of the net generation capability
on line that is not loaded, but could be loaded, and capability of a DC tie
that can be utilized in a specified time.
(3)
Scheduled backup service consists of scheduling services,
capacity and energy required to replace a capacity resource on a planned or
scheduled basis.
(4)
Automatic backup service consists of scheduling services,
capacity and energy required to replace a resource on an unscheduled basis.
(5)
Load following service provides hour-to-hour changes
in the output of generating unit to match changes in the load being served.
(c)
Tariffs. Each electric utility that provides ancillary
or reserve generation services shall file a tariff for such services and shall
take such services for its own wholesale and retail operations, in accordance
with the terms of its tariff for ancillary services.
(1)
If a customer requests a service not listed in subsection
(a) or (b) of this section or an electric utility intends to offer a service
not listed in subsection (a) or (b) of this section, the electric utility
may supply the service. In the case of a service requested by a customer,
the definition and price may be determined by negotiations between the service
provider and the customer. The service may be provided immediately upon the
execution of a contract between the parties, but the service will be subject
to approval by the commission.
(2)
An electric utility that provides a service not specified
in its tariffs shall file a tariff or modification to a tariff within 30 days
of initiating the service and shall makes the service available to all wholesale
market participants on a non-discriminatory basis. Any offer of a new service
shall be posted on the ERCOT electronic transmission information network.
(3)
All ancillary services shall be discretely priced
and separately provided on a non-discriminatory basis to all wholesale market
participants.
(4)
An electric utility may request limitations on its
obligation to provide ancillary services, based on the size of the electric
utility and the cost of acquiring the equipment necessary to provide a service,
based on its use of tax-exempt financing instruments, or for other good cause.
The electric utility has the burden of establishing that any such limitation
is reasonable and shall include the limitation in its tariffs.
(d)
Provision of ancillary services by other service providers.
An electric utility that is not required to provide an ancillary service may
file a tariff to provide such a service. Any generator may compete to provide
ancillary services to transmission service customers.
(e)
Charges for ancillary services. Ancillary services, other
than static and dynamic scheduling, load-schedule imbalance, and generation-schedule
imbalance, may be offered at rates that are negotiated with the customer,
subject to a price floor and ceiling and subject to the non-discrimination
requirements in Division 1 of this subchapter (relating to Transmission and
Distribution).
(1)
For services that are related to the production of electricity,
the price ceiling for capacity shall be based on the electric utility's average
embedded cost of generating capacity, and the price floor will be calculated
using the methodology prescribed in Public Utility Regulatory Act §36.007.
An ancillary service provider may not impose more than one capacity charge
for capacity-related ancillary services associated with a single transaction,
if the services may be provided by the same generating capacity.
(2)
Rates for static and dynamic scheduling, load-schedule
imbalance, and generation-schedule imbalance shall be established on the basis
of the cost of providing the service.
(3)
Offers to supply an ancillary service must be made
available to all wholesale market participants on a non-discriminatory basis.
Ancillary service providers shall post on the ERCOT electronic information
network on a contemporaneous basis any ancillary services offered to persons
buying or selling electricity in the bulk power market at less than the ceiling
price established in accordance with this section. The service provider shall
offer comparable rates on all services to similarly-situated transmission
service customers on a non-discriminatory basis; in particular, if a service
provider offers an ancillary service associated with a transaction, it must
make that same offer of service available to all parties interested in that
transaction on a non-discriminatory basis. A charge for an ancillary service
that equals or exceeds the floor but does not exceed the ceiling established
for such a services in accordance with this section shall not be deemed a
discount under Public Utility Regulatory Act §36.007.
(4)
An electric utility may not require the purchase of
generation services from it as a condition for the provision of ancillary
services or for discounts on such services. The purchase of power from a source
shall not be contingent on purchase of ancillary services from the same source.
Bids or offers for ancillary services shall not be bundled with a power sale.
(5)
Rates for ancillary services shall be prorated on
a monthly, weekly, daily and hourly basis.
(6)
For an investor-owned utility or cooperative utility,
three-fourths of the utility's margins from the sale of ancillary services
shall be credited to native-load customers.
(f)
Responsibility for ancillary services. A transmission service
customer is responsible for obtaining or providing necessary ancillary services.
The independent system operator shall assess whether an eligible transmission
service customer has secured ancillary services that are adequate for a proposed
transaction, shall notify the transmission service customer if additional
ancillary services are needed, and shall notify affected transmission service
providers of the ancillary service arrangements that the customer has made,
including the services being provided and the identity of the service providers.
(1)
A transmission service customer may provide the ancillary
services necessary for prudent electric utility operation by purchasing the
services from the transmission service provider or from another supplier,
or supplying the service to itself. A transmission service provider shall
not unreasonably refuse to accept contractual arrangements with another entity
for ancillary services. The independent system operator shall foster the provision
of ancillary services by non-utility suppliers.
(2)
An eligible customer may designate an agent to represent
it in making arrangements for ancillary services under this section.
(3)
A person who requires ancillary services to utilize
transmission service within ERCOT or to transmit power across the interconnection
with the Southwest Power Pool is an eligible customer under this section.
(g)
Initiating service. In order to receive ancillary services
under this section, the eligible customer shall:
(1)
complete an application for service as provided under subsection
(h) of this section;
(2)
complete the technical arrangements set forth in subsection
(i) of this section; and
(3)
execute a service agreement for service under this
section, or request in writing that the electric utility file a proposed unexecuted
service agreement with the commission.
(h)
Application procedures. An eligible customer requesting
service under this section must submit an application to the service provider.
(1)
A completed application shall provide the following information:
(A)
the identity, address, telephone number, and facsimile
number of the party requesting service;
(B)
a statement that the party requesting service is, or will
be upon commencement of service, an eligible service customer under this subsection;
(C)
the service requested, its commencement date and the term
of the requested service.
(2)
Requests for ancillary services must be submitted
with at least the lead time prescribed as follows:
(A)
to support hourly transactions, at least 20 minutes in
advance of the commencement of the transaction;
(B)
to support daily transactions, no later than 2:00 p.m.
the day before the transaction is to commence;
(C)
to support weekly transactions, at least two days in advance;
(D)
to support monthly transactions, at least four days in
advance; and
(E)
to support planned annual transactions, at least 15 days
in advance.
(3)
If an application fails to meet the requirements
of this section, the service provider shall notify the eligible customer requesting
service and specify the reasons of such failure. A service provider's response
to a request under this subsection must include a statement of any fees associated
with responding to the request (e.g., system studies).
(4)
Unless the parties agree to a different time frame,
responses to requests for ancillary services shall be provided by the electric
utility to the transmission service customer no later than the time prescribed
in subparagraphs (A)-(E) of this paragraph:
(A)
for hourly transactions, within 10 minutes of the request;
(B)
for daily transactions, within four hours;
(C)
for weekly transactions, within 24 hours;
(D)
for monthly transactions, within two days; and
(E)
for planned annual transactions, within seven days.
(5)
Wherever possible, the electric utility will
attempt to remedy deficiencies in the application through informal communications
with the eligible customer.
(6)
The ancillary service provider will not divulge information
from the application to its marketing personnel, its affiliates, or persons
buying or selling electricity in the bulk power market, except that it may
provide information necessary to make arrangements for the service to an organizational
entity involved in providing the service.
(7)
The independent system operator may set longer notification
and response times than those prescribed in paragraphs (2) and (4) of this
subsection, during a system emergency, and shall periodically review the notification
and response times and may propose to the commission revisions to those times.
The independent system operator may put such revisions into effect, pending
action by the commission on its proposal.
(i)
Technical arrangements to be completed prior to commencement
of ancillary service. The provision of ancillary service shall be conditioned
upon construction, maintenance and operation of facilities necessary to reliably
interconnect and receive service from the ancillary service provider consistent
with good utility practice. Additional requirements may be applied by an electric
utility only if they are reasonably and consistently imposed to ensure the
reliable operation of the systems of affected electric utilities and service
providers, are applied in a non-discriminatory manner, and have been approved
by the independent system operator. The ancillary service provider shall exercise
reasonable efforts, in coordination with the customer, to complete such arrangements
as soon as practical prior to the service commencement date.
(j)
Termination of service. A customer may terminate service
under this subsection following written notice of the customer's intention
to terminate. A customer's provision of notice to terminate service under
this section shall not relieve the customer of its obligation to pay the service
provider any rates, charges, or fees, including contributions in aid of construction,
for service previously provided under the applicable service agreement or
the operating agreement, and which are owed to the service provider as of
the date of termination; nor shall such a notice relieve the customer of its
obligations under a long-term contract with the service provider.
(k)
Notification. The customer or service provider of any ancillary
service shall report to the independent system operator the identity of the
provider and user of such service and the non-price terms and conditions.
§25.202.Billing and Payment for Transmission Service and Ancillary Services.
(a)
Billing and payment. Within a reasonable time after the
first day of each month, the service provider shall submit an invoice to the
customer for the charges for all services furnished under this section during
the preceding month.
(1)
The invoice shall be paid to the service provider by the
customer so that the service provider will receive the funds by the 20th calendar
day after the date of issuance of the invoice, unless the provider and the
customer agree on another mutually acceptable deadline. All payments shall
be made in immediately available funds payable to service provider, or by
wire transfer to a bank named by the service provider.
(2)
Interest on any unpaid amount shall be calculated
in accordance with the methodology specified for interest on overbillings
and underbillings in §23.45(h) of this title (relating to Billing). Interest
on delinquent amounts shall be calculated from the due date of the bill to
the date of payment. When payments are made by mail, bills shall be considered
as having been paid on the date of receipt by the service provider.
(3)
In the event the customer fails, for any reason other
than a billing dispute as described in subparagraph (A) of this paragraph,
to make payment to the service provider on or before the due date, and such
failure of payment is not corrected within 30 calendar days after the service
provider notifies the customer to cure such failure, a default by the customer
shall be deemed to exist.
(A)
Upon the occurrence of a default, the service provider
may initiate a proceeding with the commission to terminate service. In the
event of a billing dispute between the service provider and the customer,
the service provider will continue to provide service during the pendency
of the proceeding, as long as the customer:
(i)
continues to make all payments not in dispute; and
(ii)
pays into an independent escrow account the portion of
the invoice in dispute, pending resolution of such dispute.
(B)
If the transmission service customer fails to meet the
requirements in subparagraph (A) of this paragraph, then the service provider
will provide notice to the customer and to the commission of its intention
to terminate service.
(C)
Any dispute arising in connection with the termination
or proposed termination of service shall be referred to the alternative dispute
resolution process described in §25.203 of this title (relating to Alternative
Dispute Resolution).
(4)
Any person who knowingly makes use of an ancillary
service required by the independent system operator without the agreement
of the party providing that service shall pay to such service provider an
amount equal to three times the otherwise applicable charge. In no case shall
a service provider knowingly provide such an ancillary service without prior
arrangements with the customer, nor shall a service provider unilaterally
impose such an ancillary service on an unwilling purchaser.
(b)
Indemnification and liability.
(1)
Neither a customer nor service provider shall be liable
to the other for damages for any act that is beyond such party's control,
including any event that is a result of an act of God, labor disturbance,
act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion,
breakage or accident to machinery or equipment, a curtailment, order, regulation
or restriction imposed by governmental, military, or lawfully established
civilian authorities, or by the making of necessary repairs upon the property
or equipment of either party.
(2)
Notwithstanding the provisions of paragraph (1) of
this subsection, a transmission service customer and service provider shall
assume all liability for, and shall indemnify each other for, any losses resulting
from negligence or other fault in the design, construction, or operation of
their respective facilities. Such liability shall include a transmission service
customer or service provider's monetary losses, costs and expenses of defending
an action or claim made by a third person, payments for damages related to
the death or injury of any person, damage to the property of the service provider
or transmission service customer, and payments for damages to the property
of a third person, and damages for the disruption of the business of a third
person. This paragraph does not create a liability on the part of a service
provider or transmission service customer to a retail customer or other third
person, but requires indemnification where such liability exists. The indemnification
required under this paragraph does not include responsibility for the service
provider's or transmission service customer's costs and expenses of prosecuting
or defending an action or claim against the other, or damages for the disruption
of the business of the service provider or customer. The limitations on liability
set forth in this subsection do not apply in cases of gross negligence or
intentional wrongdoing.
(c)
Creditworthiness for transmission service and ancillary
services. For the purpose of determining the ability of a customer to meet
its obligations related to transmission and ancillary services and any other
obligation in Division 1 of this subchapter (relating to Transmission and
Distribution), a service provider may require reasonable credit review procedures.
This review shall be made in accordance with standard commercial practices.
(1)
The service provider may require a customer to provide
and maintain in effect during the term of service, an unconditional and irrevocable
letter of credit in a reasonable amount as security to meet its responsibilities
and obligations under Division 1 of this subchapter or an alternative form
of security proposed by the customer and acceptable to the service provider
and consistent with commercial practices established by the Uniform Commercial
Code that reasonably protects the service provider against the risk of non-payment.
(2)
If a transmission service customer is creditworthy,
no letter of credit or alternative form of security shall be required.
§25.203.Alternative Dispute Resolution (ADR).
(a)
Obligation to use alternative dispute resolution. Subject
to the right to seek direct commission review pursuant to subsection (i) of
this section, in the event that a dispute arises over the provision of transmission
service, including the curtailment of such service, or ancillary services
or the pricing or other terms or conditions of such services, the parties
to the dispute shall engage in mediation or other alternative means for resolving
the dispute, prior to filing a complaint with the commission.
(b)
Referral to senior representatives. Such disputes shall
be referred for resolution to a designated senior representative of each of
the parties to the dispute. Such representatives shall make a good faith effort
to resolve the dispute on an informal basis as promptly as practicable. In
attempting to resolve the dispute within a mutually agreeable time period,
they may seek the informal advice of the independent system operator (ISO)
regarding resolution of the dispute. The informal advice of the independent
system operator is not binding on either party.
(c)
Mediation or arbitration. In the event parties are unable
to resolve the dispute under subsection (b) of this section, the parties shall
either refer the matter to arbitration in accordance with the procedures in
this subsection or, upon agreement of all parties, shall engage in mediation
with the assistance of a neutral third party of their choice who has training
or experience in mediation.
(1)
The independent system operator shall administer the arbitration.
The independent system operator shall maintain a commission-approved list
of qualified persons available to serve on arbitration panels who are knowledgeable
in electric utility matters, including electricity transmission and bulk power
issues, to be selected from a list of persons proposed by owners and users
of the transmission system wishing to participate in the development of the
list. The independent system operator shall select at least one name submitted
by each stakeholder for the list. The independent system operator shall also
maintain a separate list of attorneys experienced in arbitration that may
be available to chair the arbitration panels.
(2)
A party shall initiate arbitration by filing a letter
with the independent system operator requesting that arbitration be scheduled.
A copy of the letter shall be served upon the other party to the dispute at
the same time the letter is filed with the independent system operator. The
independent system operator shall provide the parties the list of persons
qualified to serve on arbitration panels and list of persons available to
chair arbitration panels, within ten working days of receipt of the letter.
(3)
Only parties to the dispute may participate in the
arbitration.
(d)
Arbitration panel. Any arbitration initiated under this
section shall be conducted before a three-member arbitration panel. Each party
shall choose one arbitrator from the approved list of panel members. In the
event there are more than two parties to the dispute, the parties shall jointly
select the two arbitrators. The two arbitrators chosen by the parties shall
choose the chairman of the arbitration panel. If the two arbitrators chosen
by the parties are unable to agree on the selection of a chairman, they will
be dismissed and the parties shall select two different arbitrators from the
approved list. The arbitrators are not required to choose the chairman from
the names of persons on the independent system operator's list of panel members
so long as the person chosen is an attorney who is qualified as an arbitrator.
Panel members chosen shall not have any current or past substantial business
or financial relationships with any party to the arbitration (other than previous
arbitration experience). The chairman of the panel shall make all necessary
arrangements for arbitration to commence within ten working days of completion
of the panel.
(e)
Procedures. The arbitrators shall provide each of the parties
an opportunity to be heard and, except as otherwise provided herein, shall
generally conduct the arbitration in accordance with the Commercial Arbitration
Rules of the American Arbitration Association and any applicable commission
rules. The panel may request that the parties provide additional technical
information relevant to the dispute. The arbitration panel shall render a
decision within 30 calendar days from the closing of the evidentiary record
of the arbitration and shall notify the parties in writing of such decision
and the reasons therefor. The decision shall not be considered precedent in
any future proceeding.
(f)
Basis for decision. The arbitrators shall be authorized
only to interpret and apply the provisions of the commission's rules relating
to transmission and ancillary services, the independent system operator's
rules, the electric utility's transmission tariff, and any service agreement
entered into under that tariff and shall have no power to modify or change
any of the above in any manner.
(1)
The arbitrators may agree with the positions of one or
more of the parties, or may recommend a compromise position.
(2)
The arbitration panel decision shall be filed in the
commission's Central Records and shall be considered by the commission in
preparing a Preliminary Order, should either party file a complaint regarding
the arbitrated matters. The complaint shall be docketed and may be referred
to the State Office of Administrative Hearings. The decision may be admitted
in evidence in any such complaint proceeding.
(g)
Costs. Each party shall be responsible for the following
costs, if applicable:
(1)
its own costs incurred during the arbitration process;
(2)
its pro rata share of the costs of the three arbitrators,
pooled and shared evenly among the parties.
(h)
Effect of pending arbitration. The transaction which is
the subject of the dispute shall be allowed to go forward pending the resolution
of the dispute to the extent system reliability is not affected.
(i)
Effect on rights under law. Nothing in this section shall
restrict the rights of any party to file a complaint with the commission under
relevant provisions of the Public Utility Regulatory Act or with the Federal
Energy Regulatory Commission under the Federal Power Act or the right of an
electric utility to seek changes in the rates or terms for transmission or
ancillary services, following the completion of the alternative dispute resolution
procedures in this section.
(1)
Use or application of the arbitration provisions in this
subsection does not affect the jurisdiction of the commission over any matters
arising under this section.
(2)
Nothing in this section shall restrict the right of
a market participant to file a petition seeking direct relief from the commission
without first utilizing the alternative dispute resolution process where an
action by or the independent system operator might inhibit the ability of
an electric utility to provide continuous and adequate service to its customers.
(3)
Because of the imminent threat to the health and welfare
of an electric utility's customers in the event of a reliability problem,
a petitioner's dispute will be heard by the commission in an emergency session
except in those instances where a quorum of the commission is not present.
In those instances where a quorum is not present, the chairman of the commission
shall have the authority to issue an interim order to resolve the dispute
so as to protect the reliability of the system, with the order remaining in
effect until such time as a quorum is present.
(j)
Applicability of ADR to the ISO. Complaints against the
ISO shall be subject to the ADR provisions and procedures established in this
section.
§25.204.Summary of Required Filings.
Summary of required filings. This section summarizes the filings and
matters requiring commission approval that are adopted in Division 1 of this
Subchapter (relating to Transmission and Distribution). The applicability
and deadline for each filing are detailed in the relevant sections of Division
1 of this subchapter:
(1)
Tariffs for wholesale transmission service, in accordance
with §25.191(e) of this title (relating to Transmission Service Requirements);
(2)
Facilities charges for transmission service, in accordance
with §25.192(a) of this title (relating to Transmission Service Rates);
(3)
Tariffs for short-term planned transmission service,
in accordance with §25.192(b) of this title;
(4)
Methods for determining transmission losses, in accordance
with §25.192(e) of this title;
(5)
Changes in the independent system operator fee, in
accordance with §25.192(f) of this title;
(6)
Tariffs and procedures for implementing monetary payment
for inadvertent energy, in accordance with §25.192(g) of this title;
(7)
Updates of transmission rates to reflect changes in
invested capital, in accordance with §25.193(a) of this title (relating
to Procedures for Modifying Transmission Rates);
(8)
Earnings monitoring reports for transmission costs
and revenues, accordance with §25.193(a) of this title;
(9)
Information concerning peak loads and load and resource
information relating to the calculation of megawatt-mile impacts, in accordance
with §25.194(a) of this title (relating to Determining Peak Loads and
Megawatt-Mile Impacts);
(10)
Filing of new agreements, including interconnection
agreements, governing the sale or purchase of generation, transmission, or
ancillary services at wholesale, in accordance with §25.195(g) of this
title (relating to Terms and Conditions for Transmission Service);
(11)
Description of separation of functions, in accordance
with §25.196(b) of this title (relating to Functional Unbundling);
(12)
Proposed transmission planning guidelines and procedures,
in accordance with §25.197(f) of this title (relating to ERCOT Independent
System Operator);
(13)
Periodic reports by the independent system operator
on the reliability of the transmission network and recommended transmission
projects, in accordance with §25.197(i) of this title;
(14)
Methodologies for determining redispatch costs, in
accordance with §25.200(c) of this title (relating to Load Shedding,
Curtailment, and Redispatch); and
(15)
Tariff for ancillary services, in accordance with
§25.201(c) and (d) of this title (relating to Ancillary Services).
This agency hereby certifies that the adoption has been
reviewed by legal counsel and found to be a valid exercise of the agency's
legal authority.
Filed with the Office of the Secretary of State on March
24, 1999.
TRD-9901753
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: April 13, 1999
Proposal publication date: October 9, 1998
For further information, please call: (512) 936-7308
16 TAC §25.271
The Public Utility Commission of Texas (commission) adopts
new §25.271, relating to Foreign Utility Company Ownership by Exempt
Holding Companies with changes to the proposed text as published in the November
20, 1998, issue of the
Texas Register
(23
TexReg 11760). The rule is necessary to clarify reporting requirements and
delete obsolete language. The report requires exempt utility holding companies
that do not file income statements and balance sheets for their subsidiaries
with the SEC to file them with the commission. This new section was adopted
under Project Number 17709.
The Appropriations Act of 1997, HB 1, Article IX, Section 167 (Section
167) requires that each state agency review and consider for readoption each
rule adopted by that agency pursuant to the Government Code, Chapter 2001
(Administrative Procedure Act). Such reviews shall include, at a minimum,
an assessment by the agency as to whether the reason for adopting or readopting
the rule continues to exist. The commission held three workshops to conduct
a preliminary review of its rules. As a result of these workshops, the commission
is reorganizing its current substantive rules located in 16 Texas Administrative
Code (TAC) Chapter 23 to (1) satisfy the requirements of Section 167; (2)
repeal rules no longer needed; (3) update existing rules to reflect changes
in the industries regulated by the commission; (4) do clean-up amendments
made necessary by changes in law and commission organizational structure and
practices; (5) reorganize rules into new chapters to facilitate future amendments
and provide room for expansion; and (6) reorganize the rules according to
the industry to which they apply. Chapter 25 has been established for all
commission substantive rules applicable to electric service providers.
The commission requested specific comments on the Section 167 requirement
as to whether the reason for adopting or readopting the rule continues to
exist. No comments were received regarding the Section 167 requirement. The
commission finds that the reason for adopting the rule continues to exist.
The commission received comments on the proposed new section from the Central
and South West Texas Electric Utility Operating Companies (CSW), Houston Lighting
& Power Company (HL&P), and Texas Utilities Electric Company (TU
Electric). CSW's comments stated their understanding that the proposed changes
would not affect their current reporting requirements under their February
13, 1996, agreement to comply with this rule. The commission agrees that CSW's
existing SEC reporting process contains the information called for in the
proposed section, and that no additional reporting will be required from the
company as a result of this amendment.
Texas Utilities Electric Company requests that the language in the proposed
amendment be more specific. They suggest that the terms "income statement
and balance sheet" be substituted for the term "financial statements." The
commission agrees that the term "financial statements" was somewhat unclear,
and has changed the proposed language to state that the information to be
provided is: "A consolidating statement of income of the exempt holding company
and its subsidiary companies for the last calendar year, together with a consolidating
balance sheet of the exempt holding company and its subsidiary companies as
of the close of such calendar year." This amended reporting requirement is
more descriptive than the published requirement of "financial statements"
and closely parallels the SEC reporting requirement under Rule U-3A-2 for
exempt holding companies.
HL&P recommended two changes to the proposed amendment to make the
requirement of financial statements more clear. First, the company suggested
that the financial statements be limited to first tier subsidiaries. Further,
HL&P recommended that language be added that the financial statements
may be unaudited. The commission believes the amended wording is consistent
with HL&P's suggestion regarding first tier subsidiaries. Further, the
commission understands that since the reporting date for this information
in March, it is likely that the information provided will be unaudited.
In adopting this section, the commission makes other minor modifications
for the purpose of clarifying its intent. To be consistent with the SEC reporting
requirement that such information be filed by March 1 of each year, the commission
has changed the due date of this report to 14 days after March 1, or March
15. This is close to the commission due date of March 11 for SEC financial
reports related to foreign utility company investments by other exempt holding
companies.
This section is adopted under the Public Utility Regulatory Act,
Texas Utilities Code Annotated §14.002 (Vernon 1998) (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 §14.154
which grants the commission jurisdiction over an affiliate that has a transaction
with an electric utility under the commission's jurisdiction.
Cross Index to Statutes: Public Utility Regulatory Act §14.002, and
§14.154.
§25.271.Foreign Utility Company Ownership by Exempt Holding Companies.
(a)
Certification to Securities and Exchange Commission. Upon
request by a holding company which is exempt under §3 of the Public Utility
Holding Company Act of 1935, codified at 15 United States Code 79, the commission
may certify to the Securities and Exchange Commission (SEC) that the commission
has the authority and resources to protect ratepayers and that it intends
to exercise its authority over holding companies owning both a jurisdictional
electric utility and a foreign utility company (FUCO) under the safe harbor
provisions of subsection (c) of this section or the case-by-case review provisions
of subsection (d) of this section. The commission may also notify the SEC
that a previously-issued certification regarding a requesting holding company
will be ineffective prospectively.
(b)
Policy goals. The commission will seek to protect the public
interest in having electricity service available to all citizens of the state
at just, fair, and reasonable rates that are unaffected by investments by
exempt holding companies in foreign utility companies (FUCOs), while avoiding
strictures that would place exempt holding companies at a competitive disadvantage
in international markets. The commission will consider these policy goals
in each decision whether to issue a certification or to notify the SEC that
a previously-issued certification is prospectively withdrawn.
(c)
Safe harbor investments. The following safe harbor provisions
shall be applicable to investments in FUCOs by exempt holding companies that
are affiliated with electric utilities subject to the regulatory jurisdiction
of the commission:
(1)
The commission shall certify to the SEC that the commission
has the authority and resources to protect ratepayers subject to its jurisdiction
and that it intends to exercise its authority, provided that all holding companies
of electric utilities that are subject to the regulatory jurisdiction of this
commission shall have filed with the commission corporate undertakings, signed
under oath by an authorized executive officer of the holding company agreeing
to adhere to the covenants and to make the filings specified in paragraph
(2) of this subsection.
(2)
The holding company shall adhere to the following
covenants:
(A)
That any indebtedness incurred in relation to the acquisition
by the holding company, or by any affiliate of the electric utility, of an
ownership interest in a FUCO will be without recourse to the electric utility;
(B)
That the electric utility, the holding company, or any
affiliate of the electric utility will not enter into any agreements under
the terms of which the electric utility is obligated to commit funds in order
to maintain the financial viability of a FUCO or an affiliate of the electric
utility investing in a FUCO;
(C)
That the electric utility will not provide, directly or
indirectly, any guarantees or other forms of credit support for any funds
borrowed by the holding company or an affiliate of the electric utility in
connection with the acquisition of any ownership interest in a FUCO;
(D)
That the electric utility, the holding company, or any
affiliate of the electric utility will not make any investment in a FUCO under
circumstances in which the electric utility would be liable for the debts
and/or liabilities of the FUCO incurred as a result of acts or omissions of
the FUCO;
(E)
That the electric utility will maintain and provide a copy
to the commission of its accounting policies and procedures that assure that
the electric utility is adequately and fairly compensated by the holding company
or an affiliate of the electric utility for any use of the electric utility's
assets or personnel in furtherance of a FUCO;
(F)
That the holding company provides the commission reasonable
access to books and records and financial statements, or copies thereof, of
the FUCO or other affiliate doing business with the FUCO, in English and stated
in United States dollars, as the commission may request to:
(i)
review transactions between the electric utility and such
FUCO or affiliate pursuant to the Public Utility Regulatory Act §14.154;
and
(ii)
review transactions between any affiliate and the FUCO
if such affiliate also has transactions directly or indirectly with the electric
utility;
(G)
That the holding company will file with the commission
quarterly a report listing the total amount of the aggregate investments by
the holding company and its subsidiaries and the percentage of the holding
company's consolidated net worth, from the company's most recent SEC form
10-Q, represented by such investments;
(i)
"Aggregate investment" means all amounts invested, or committed
to be invested, in exempt wholesale generators located outside the United
States (foreign EWGs) and FUCOs, for which there is recourse, directly or
indirectly, to the holding company. Among other things, the term shall include
preliminary development expenses that culminate in the acquisition of a foreign
EWG or a FUCO.
(ii)
Such report shall be filed no later than ten days following
the filing of the 10-Q for the quarter.
(H)
That in the event the holding company anticipates making
any investment in a FUCO that would result in the aggregate investment as
defined in subparagraph (G) of this paragraph of such holding company exceeding
30% of the consolidated net worth of such holding company, the holding company
shall so advise the commission before a final commitment to ownership of such
FUCO is made;
(I)
That the electric utility will provide, by March 31 of
each year, a copy of the electric utility's three-year cash flow forecast;
(J)
That the holding company will provide to the commission
all SEC forms for reporting information related to foreign EWG and FUCO investments,
no later than ten days after such forms are provided to the SEC;
(K)
That the holding company will promptly notify the commission
whenever any of the following occurs:
(i)
It is unable to provide the certifications, undertakings,
or documents provided for in this paragraph;
(ii)
The aggregate investment exceeds 30% of consolidated net
worth;
(iii)
The holding company's operating losses attributable to
its direct or indirect investments in foreign EWGs and FUCOs exceeded 5.0%
of consolidated retained earnings during the previous four quarters; and
(L)
That the holding company will comply with the informational
filing requirements of subsection (d) of this section in connection with a
contemplated investment in a FUCO, unless the commission finds good cause
not to require the holding company to provide such additional information.
(d)
Other Investments. For any occasion for which a holding
company has undertaken to notify the commission of an event specified in subsection
(c)(2)(H) or (K) of this section, the following provisions apply:
(1)
The holding company shall provide the following information,
to the extent such information is reasonably available at the time of submission
of the filing, at least 30 days before the date when it anticipates making
a final commitment to ownership of a FUCO not already covered by a certification
letter:
(A)
A description of the proposed investment, including a description
of the FUCO assets being acquired, their geographical location, the form of
the investment (partnership, joint venture, direct purchase, etc.), the holding
company's percentage share of the investment, a description of how the investment
will fit into the corporate subsidiary structure, and any other information
reasonably necessary in the opinion of the holding company to provide a complete
overview of the nature of the proposed investment;
(B)
Any financial requirements and/or commitments by the holding
company or the electric utility that will be made or assumed as a result of
this investment; this information should include, but is not limited to, an
estimate of the amount of equity capital to be invested;
(C)
Any debt obligations resulting from this investment which
will provide recourse to the holding company or the electric utility;
(D)
The holding company's general corporate objectives regarding
diversification and foreign utility investments, and the specific objectives
of the proposed FUCO investment;
(E)
A statement that the electric utility has effective written
policies and accounting procedures which insure that any use by the FUCO of
assets or personnel of an affiliate of the electric utility, or other transactions
between the FUCO and an affiliate of the electric utility shall not negatively
affect Texas ratepayers; and a statement that the electric utility will demonstrate
in each subsequent rate proceeding before the commission, and each subsequent
audit, that no FUCO investment increased the cost of capital or revenue requirement
of the electric utility;
(F)
A calculation, based on the holding company's most recent
SEC Form 10-Q, of aggregate consolidated holding company investments as defined
in subsection (c)(2)(G) of this section as a percentage of consolidated holding
company net worth, stated both before and after all asset transfers from any
affiliate of the electric utility to FUCOs at fair market value;
(G)
A statement that the holding company will provide to the
commission all SEC forms for reporting information related to foreign EWG
and FUCO investments, no later than ten days after such forms are provided
to the SEC; and
(H)
Responses to questions, if any, contained on a commission
prescribed form.
(2)
The notification prescribed in this subsection
may be submitted less than 30 days before the date when the holding company
anticipates making a final commitment to ownership of a FUCO not already covered
by a certification letter upon a showing of good cause. Good cause for purposes
of the preceding sentence shall be deemed to include, without limitation,
a representation that the holding company lacked the information required
to make a submission at an earlier date or a representation that making the
submission at an earlier date would have unreasonably jeopardized the ability
of the holding company to go forward with the contemplated investment.
(3)
In its review of the information provided pursuant
to this section, the commission will consider, among other things, the number
and magnitude of prior FUCO investments by the holding company, including
the diversity among the countries in which such investments are located and
other differences between such investments, and the magnitude of the proposed
investment and its effect on the diversity of the portfolio.
(e)
Post-investment reporting. The electric utility shall comply
with the following post- investment reporting obligations:
(1)
With respect to any investment in a FUCO for which an informational
filing was made pursuant to subsection (d)(1) of this section, the electric
utility or holding company shall notify the commission no later than ten days
after the holding company makes a final commitment to ownership of a FUCO
that such a commitment has been made. Such notice shall include any material
corrections, additions, and supplementation of previously-provided information;
and
(2)
For any FUCO investment covered by a certification,
the electric utility or holding company shall notify the commission no later
than 30 days after any material change in the circumstances or nature of an
investment in a FUCO. Such notice shall include all appropriate corrections,
additions, and supplementation of previously-provided information. A material
change would include, but is not limited to, any change that would have an
adverse impact of greater than 1.0% of consolidated net worth most recently
reported; full or partial divestiture of the investment; a catastrophic event
that destroys a significant amount of FUCO property or results in loss of
life that could result in a significant liability claim; a change in the laws
or government policy having a material impact on the FUCO; or an event which
would place a significant restriction on the repatriation of earnings of the
FUCO.
(3)
Unless included in SEC reports, each exempt utility
holding company which directly or indirectly holds an interest in FUCOs or
foreign EWGs shall provide the following information: A consolidating statement
of income of the exempt holding company and its subsidiary companies for the
last calendar year, together with a consolidating balance sheet of the exempt
holding company and its subsidiary companies as of the close of such calendar
year.
(A)
The information shall be provided in English, monetary
amounts in U.S. dollars, and according to generally accepted accounting principles.
(B)
Such information must be received by the commission annually
no later than March 15.
(f)
Commission standards for granting or maintaining certification.
(1)
In general, the commission will issue and continue certification
when the aggregate investment in FUCOs and foreign EWGs is less than 30% of
the holding company's consolidated net worth, and the company has satisfactorily
provided the information and assurances set out in the preceding subsections.
(2)
With respect to any investment in a FUCO for which
an informational filing was made pursuant to subsection (d)(1) of this section,
the commission shall determine on a case by case basis whether to issue a
certification to the SEC or maintain a previously issued certification. The
commission shall endeavor to make such a determination prior to the date when
the holding company anticipates having to make a final commitment to ownership
of the FUCO. If the commission determines that it does not intend to continue
certification, it may inform the SEC that maintaining a previously-issued
certification would be inappropriate.
(3)
The commission shall notify the holding company requesting
the certification or retention of certification of its decision within 45
days of receiving the request. If no action is taken by the commission within
45 days of receiving the request, the certification shall be deemed granted
or affirmed.
(4)
Any information submitted by a holding company pursuant
to this section may be submitted by the holding company under seal. Each page
tendered under seal shall have the words "Confidential Information" typed
or stamped on its face. The holding company shall clearly identify each portion
of the application alleged to be Confidential Information; identify the exemption
to the Public Information Act, Texas Government Code Annotated, Chapter 552
(Vernon Supp. 1998), applicable to the alleged Confidential Information; and
provide a detailed explanation of why the alleged Confidential Information
is exempt from public disclosure under the Public Information Act. If the
commission receives a Public Information Act request for disclosure of Confidential
Information, then the Executive Director shall promptly so notify the holding
company. The Executive Director shall timely request an Attorney General's
opinion as to whether the information falls within any of the exemptions identified
in Subchapter C of the Public Information Act. The Executive Director shall
promptly provide to the holding company a copy of an Attorney General opinion
regarding the claim of confidentiality. If an Attorney General opinion recommends
disclosure of Confidential Information, either in whole or in part, then the
Executive Director shall not release such information for ten calendar days,
in order to allow the holding company time to pursue any legal remedies that
it may have. The holding company may require the execution of an appropriate
confidentiality agreement prior to providing access to such confidential information
to the Legal Division of the Office of Regulatory Affairs or other interested
party. The form of any such confidentiality agreement shall be approved by
the Legal Division prior to filing and included with the informational filing.
This agency hereby certifies that the adoption has been
reviewed by legal counsel and found to be a valid exercise of the agency's
legal authority.
Filed with the Office of the Secretary of State on March
26, 1999.
TRD-9901791
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: April 15, 1999
Proposal publication date: November 20, 1998
For further information, please call: (512) 936-7308
Subchapter G. Advanced Services
16 TAC §26.142
The Public Utility Commission of Texas (commission) adopts
new §26.142, relating to Integrated Services Digital Network (ISDN).
Section 26.142 is adopted with no changes to the proposed text as published
in the December 4, 1998, issue of the
Texas Register
(23 TexReg 12057) and the text will not be republished. The new section
replaces §23.69 of this title (relating to Integrated Services Digital
Network (ISDN)) and establishes the minimum criteria for the provision of
ISDN to customers of dominant certificated telecommunications utilities (DCTU).
This section is adopted under project number 17709.
This section is expected to result in the availability of ISDN to customers
of DCTUs. ISDN provides the public switched telephone network with the capability
for end-to-end digital connectivity. Examples of uses for ISDN are telecommuting,
teleconferencing, distance learning, and telemedicine.
The Appropriations Act of 1997, HB 1, Article IX, Section 167 (Section
167) requires that each state agency review and consider for readoption each
rule adopted by that agency pursuant to the Government Code, Chapter 2001
(Administrative Procedure Act). Such reviews shall include, at a minimum,
an assessment by the agency as to whether the reason for adopting or readopting
the rule continues to exist. The commission held three workshops to conduct
a preliminary review of its rules. As a result of these workshops, the commission
is reorganizing its current substantive rules located in 16 Texas Administrative
Code (TAC) Chapter 23 to (1) satisfy the requirements of Section 167; (2)
repeal rules no longer needed; (3) update existing rules to reflect changes
in the industries regulated by the commission; (4) do clean-up amendments
made necessary by changes in law and commission organizational structure and
practices; (5) reorganize rules into new chapters to facilitate future amendments
and provide room for expansion; and (6) reorganize the rules according to
the industry to which they apply. Chapter 26 has been established for all
commission substantive rules applicable to telecommunications service providers.
The duplicative sections of Chapter 23 will be repealed as each new section
is proposed for publication in the new chapter.
The commission requested specific comments on the Section 167 requirement
as to whether the reason for adopting or readopting the rule continues to
exist. No comments were received regarding the 167 requirement. The commission
finds that the reason for adopting the rule continues to exist.
Interested parties filed written comments on January 4, 1999. The commission
received timely written comments on the proposed rule from Sprint.
Comments regarding §26.142
Sprint expressed three concerns about language proposed for deletion. Sprint
maintained that some of the sections (§23.69(d)(4)-(6)) that were proposed
for deletion from §26.142 are still necessary, and that these deletions
could have unintended consequences.
Sprint asserted that the removal of §23.69(d)(4) through (6) would
remove DCTUs that did not have exchanges greater than 50,000 access lines
as of February 22, 1995 from compliance with the ISDN rule. Thus, subsection
(c) of §26.142 would have the effect of applying only to DCTUs with exchanges
greater than 50,000 access lines as of February 22, 1995.
The commission rejects Sprint's argument. First, the obligation to implement
ISDN remains intact in §26.142(c)(1)-(3), regardless of the size of exchange
areas. Section 23.69(4)-(6) simply required the preparation of a plan to outline
a DCTU's good faith effort toward making ISDN available. This section did
not independently obligate DCTUs to provide ISDN.
Second, the rule has never based the obligation to provide ISDN upon the
size of a DCTU. The rule did, and continues to, distinguish the manner in
which ISDN is provided in exchange areas with more than 50,000 access lines
versus exchange areas with fewer than 50,000 access lines. Customers in exchange
areas with 50,000 or more customers may not be provided ISDN through a foreign
exchange (FX) arrangement; customers in exchange areas with fewer than 50,000
access lines may be provided ISDN through FX arrangements.
Sprint also maintained that the removal of the aforementioned paragraphs
would have the effect of removing a compliance date for the implementation
of ISDN.
The commission points out that the obligation to implement ISDN to exchange
areas with more than 50,000 access lines and exchange areas with fewer than
50,000 access lines was July 1, 1996 in §23.97. Since that date has passed,
it is now assumed that these exchange areas have ISDN in place.
Finally, Sprint argued that §26.142 would remove the ability for DCTUs
to comply with the ISDN rule by "making available end-to-end digital connectivity
that is equal to or superior to ISDN."
This language is not necessary in §26.142. The referenced language
was contained in paragraphs requiring particular DCTUs to prepare a "plan
about a good faith effort to make ISDN available to all customers no later
than January 1, 2000." These plans were prepared and filed by January 1, 1997;
thus, the commission is already aware of the plans for good faith efforts
toward making available ISDN or end-to-end digital connectivity that is equal
to or superior to ISDN. The commission has authority outside of this section
to require any reports it may need to determine the status of ISDN or end-to-end
digital connectivity.
This section is adopted under the Public Utility Regulatory Act,
Texas Utilities Code Annotated §14.002 (Vernon 1998) (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 §55.001 which requires public utilities to furnish service, instrumentalities,
and facilities that are safe, adequate, efficient, and reasonable; and §55.002(1)
which grants the commission authority to adopt rules a public utility must
follow in furnishing a service.
Cross-Index to Statutes: Public Utility Regulatory Act §§14.002,
55.001 and 55.002(1).
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on March
26, 1999.
TRD-9901795
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: April 15, 1999
Proposal publication date: December 4, 1998
For further information, please call: (512) 936-7308
16 TAC §26.271
The Public Utility Commission of Texas (commission) adopts
new §26.271, relating to Expanded Interconnection. Section 26.271 is
adopted with no changes to the proposed text as published in the December
11, 1998, issue of the
Texas Register
(23
TexReg 12596) and will not be republished. The Public Utility Regulatory Act
§60.141 requires that the commission adopt rules for expanded interconnection.
Project Number 17709 has been assigned to this proceeding.
This section is expected to result in a growth in competition that should
increase local exchange company (LEC) incentives for efficiency, encourage
LECs to deploy new technologies that facilitate innovative service offerings,
and reduce prices for services available from both the LECs and alternative
providers. It should also improve LEC responsiveness to customers in the provision
of existing services and increase choices available to access customers who
value redundancy and route diversity.
The Appropriations Act of 1997, HB 1, Article IX, Section 167 (Section
167) requires that each state agency review and consider for readoption each
rule adopted by that agency pursuant to the Government Code, Chapter 2001
(Administrative Procedure Act). Such reviews shall include, at a minimum,
an assessment by the agency as to whether the reason for adopting or readopting
the rule continues to exist. The commission held three workshops to conduct
a preliminary review of its rules. As a result of these workshops, the commission
is reorganizing its current substantive rules located in 16 Texas Administrative
Code (TAC) Chapter 23 to (1) satisfy the requirements of Section 167; (2)
repeal rules no longer needed; (3) update existing rules to reflect changes
in the industries regulated by the commission; (4) do clean-up amendments
made necessary by changes in law and commission organizational structure and
practices; (5) reorganize rules into new chapters to facilitate future amendments
and provide room for expansion; and (6) reorganize the rules according to
the industry to which they apply. Chapter 26 has been established for all
commission substantive rules applicable to telecommunications service providers.
The duplicative sections of Chapter 23 will be proposed for repeal as each
new section is proposed for publication in the new chapter.
The commission requested specific comments on the Section 167 requirement
as to whether the reason for adopting or readopting the rule continues to
exist. No comments were received on the proposed section. The commission finds
that the reason for adopting the rule continues to exist.
This section is adopted under the Public Utility Regulatory Act,
Texas Utilities Code Annotated §14.002 (Vernon 1998) (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 §60.141 which requires the commission to adopt rules for expanded
interconnection that are consistent with rules and regulations of the Federal
Communications Commission relating to expanded interconnection, treat intrastate
private line services as special access service, and provide that an incumbent
local exchange company is required to provide expanded interconnection to
another local exchange company, the second local exchange company shall in
a similar manner provide expanded interconnection to the first company.
Cross-Index to Statutes: Public Utility Regulatory Act §14.002 and
§60.141.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on March
26, 1999.
TRD-9901793
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Effective date: April 15, 1999
Proposal publication date: December 11, 1998
For further information, please call: (512) 936-7308
Chapter 35.
Enforcement
Subchapter A. Transportation of Liquor
16 TAC §35.6
The Texas Alcoholic Beverage Commission adopts a new rule
§35.6 with changes to the proposed text as published in the February
12, 1999, edition of the
Texas Register
(24
TexReg 901). The rule operates to allow members of the manufacturing tier
to temporarily hold alcoholic beverages in regional forwarding centers while
that product is in transit from the place of manufacture to its authorized
recipient.
The commission recognizes that maintenance of an efficient distribution
system between members of the manufacturing and wholesale tiers of the alcoholic
beverage industry has, in recent times, become a complex process. This complexity
is due, in part, to the need of the product suppliers to promptly fill purchaser
orders while simultaneously honoring changes in those orders with respect
to quantities, types of alcoholic beverages ordered, and package configurations.
These needs may be more effectively satisfied if the supplying industry member
is allowed to change the content, makeup, or configuration of an order while
the alcoholic beverages are in transit to their authorized recipient rather
than require that altered orders be shipped exclusively from the point of
manufacture.
This rule addresses this need by allowing alcoholic beverage manufacturers
to establish and maintain regional forwarding centers where product can be
temporarily held while in transit. Because the product remains under the control
of the shipping member while in the center, it may be repackaged, reconfigured
into different shipment lots, or rerouted before transportation on to its
ultimate recipient. The rule further operates to insure that ownership and
operational interests of the three tiers remain separate as required by the
Alcoholic Beverage Code; that the agency maintains the ability to inspect
for, and charge, violations of the code and rules at regional forwarding centers;
and that the agency maintains its ability to track all alcoholic beverages
as they are moved into and around the state.
As originally proposed, the rule only extended the right to use regional
forwarding centers to out of state manufacturers. The Wholesale Beer Distributors
of Texas and Anheuser-Busch commented that the rule should be altered to allow
use of such centers by Texas manufacturers. The commission found this comment
to be well taken inasmuch as manufacturing tier members, whether in or out
of the state, are authorized to transport alcoholic beverages by reference
to the code provisions cited in paragraphs (a) and (b) of the adopted rule,
and all such members face the same difficulties of efficient distribution
of their product. This change occasioned amendment to paragraphs (a), (b)
and (b)(1) to the rule as originally published.
This rule originally sought to create "regional distribution centers."
The Wholesale Beer Distributors of Texas noted that "distribution" is a term
of art in the Alcoholic Beverage Code, referring to members of the wholesale
tier of the beer industry. Since the envisioned centers were manufacturing
tier facilities, confusion could result from referring to them as "distribution
centers." The commission agreed with this comment and made the necessary changes
to the title of the rule, and paragraphs (b)(1),(2),(3),(4),(6),(7),(c),(d)
and (e) of the rule as originally published.
Anheuser-Busch pointed out that, in commercial law, the term "sale" is
subject to various meanings. Therefore, it is advisable to give some definition
to the term in this rule and thereby avoid unnecessary contested cases arising
under the rule. The commission agreed and adopted this change to paragraph
(b)(4) of the rule.
After discussion with industry members, the staff recognized that the centers
should not be used as a subterfuge to avoid involvement of the wholesale tier
in shipments of alcoholic beverages. Accordingly the staff recommended, and
the commission adopted the addition of paragraph (b)(5) of the rule.
The Wholesale Beer Distributors of Texas suggested that the language of
paragraph (b)(2) be clarified to insure that operators of forwarding centers
be identified with the product shipper. The commission declined to adopt this
suggestion because the rule as originally published identifies the facility
operator as "the agent" of the manufacturing tier member. Under the definition
of licensee and permittee as contained in the Alcoholic Beverage Code, industry
members are identified with, and vicariously responsible for, the actions
of their agents. Therefore, the commissioners thought the suggested change
unnecessary.
Similarly, the Wholesale Beer Distributors of Texas suggested that the
phrase "in any form or degree" be added to paragraph (b)(3). The commission
declined this suggestion as unnecessary. Further, this commenter further suggested
that the rule specifically state the authorized recipients of the alcoholic
beverages transported through the centers. The commission concluded this addition
was unnecessary because industry members authorized to use regional forwarding
centers may, by law, only ship their product to licensees and permittees specifically
identified in the Alcoholic Beverage Code. Finally, the Wholesale Beer Distributors
of Texas requested that the rule state that reports filed under paragraph
(d) of the rule be public records and contain certain types of information.
The commission declined this suggestion because the industry reports to be
filed under this rule are automatically public records by operation of §5.48(a)
of the Alcoholic Beverage Code. Experience of the commission indicates that
it is inefficient to dictate the specific content of periodic reports in a
rule because the commission's need for information changes over time. When
governed by overly specific rules, both the agency and industry members are
bound to exchange of unnecessary information.
The Watkins Transportation Company and the E & J Gallo Winery offered
comment in support of the rule. No commenter was opposed to the rule.
This rule is adopted under the authority of §5.31 of the
Alcoholic Beverage Code.
Cross Reference: Alcoholic Beverage Code, §§37.01(2), 42.01(a),
62.08, and 63.01 are affected by this rule.
§35.6.Regional Forwarding Centers.
(a)
This rule relates to Alcoholic Beverage Code, §§37.01(2),
62.08, 63.01 and 42.01(a).
(b)
Members of the manufacturing tier who are transporting
alcoholic beverages into the state, or from point to point within the state
under the authority of §§37.01(2), 42.01(a), 62.08(a) and 63.01
may temporarily hold such alcoholic beverages in a regional forwarding center,
subject to the following conditions:
(1)
A regional forwarding center is a facility wherein alcoholic
beverages may be held under the control of the manufacturing tier member responsible
for shipping the alcoholic beverages.
(2)
The regional forwarding center may be operated by
a third party who acts as the agent of the manufacturing tier member in arranging
for interstate or intrastate shipments of alcoholic beverages to permittees
and licensees authorized to receive such beverages or for shipment to locations
outside the state.
(3)
No member of the wholesale or retail tiers of the
alcoholic beverage industry may, directly or indirectly, hold any interest
in, or right of operation of a regional forwarding center.
(4)
No sale of alcoholic beverages may be made to a person
or entity from a regional forwarding center. For purposes of this rule, a
"sale" occurs when an order is taken and/or payment is made.
(5)
No member of the retail tier may take delivery of
alcoholic beverages at a regional forwarding center.
(6)
A regional forwarding center must be located in an
area that is wet for the type of alcoholic beverages held therein.
(7)
A licensee or permittee, by using a regional forwarding
center under the authority of this rule, consents to inspection of such facility
by the commission, its agents or employees, or any peace officer, to the same
extent as consent is given for inspection of licensed premises by §101.04
of the Alcoholic Beverage Code.
(c)
Licensees and permittees using regional forwarding centers
under the authority of this rule shall, on forms provided by the commission,
make monthly reports to the commission of all alcoholic beverages received
in or transferred from the regional forwarding center and other information
as requested by the commission. Such reports shall be signed by the custodian
of the regional forwarding center and filed with the commission at its offices
in Austin, Texas, postmarked not later than the 15th day of the month following
the calendar month for which the report is submitted.
(d)
The information required by subsection (c) of this section
shall be maintained as a contemporaneous record at the regional forwarding
center with information relating to specific shipments entered into the record
on the day the shipment is received or sent.
(e)
Licensees and permittees using regional forwarding centers
under the authority of this rule shall pay an annual fee of $1,000 to the
commission.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on March
24, 1999.
TRD-9901764
Doyne Bailey
Administrator
Texas Alcoholic Beverage Commission
Effective date: April 13, 1999
Proposal publication date: February 12, 1999
For further information, please call: (512) 206-3204
16 TAC §50.4
The Texas Alcoholic Beverage Commission adopts amendments
to rule §50.4 with changes to the proposed text as published in the February
12, 1999, edition of the
Texas Register
, (24
TexReg 901). The rule governs the requirements placed on seller-server training
schools to report scheduled classes to the commission.
Prior to this amendment, schools were required to give the commission three
days notice of classes scheduled. The commission determined that this requirement
unnecessarily impaired the right of class providers to schedule classes on
short notice. Accordingly the commission proposed to amend the rule to allow
that one-fourth of all classes scheduled by a school within a month may be
scheduled with less than three days notice to the commission. The commission
concluded that this approach balanced the need of the schools to have flexibility
in class schedules and the need of the agency to be advised of school activities
with sufficient time to make plans to monitor selected programs.
A comment was received from the Select Concepts company agreeing with this
approach generally, but pointing out that the proposed amendment did not benefit
those schools that held very few classes within a given month. The commission
agreed with this comment and amended the text of the rule amendment as originally
proposed by adding the fourth sentence to paragraph (a) of the rule. The effect
of this addition is to allow schools that schedule a small number of classes
to calculate the one-fourth that may be scheduled without providing the commission
with three days notice on a quarterly, rather than a monthly, basis. No other
comments were received about this proposed amendment.
This amendment is adopted under the authority of §5.31 of
the Alcoholic Beverage Code.
Cross Reference: Alcoholic Beverage Code, §106.14, is affected by
this rule.
§50.4.Program Administration.
(a)
The Texas Alcoholic Beverage Commission shall receive written
notification, including electronic and otherwise, from each school to schedule
sessions. At least three-fourths of the session notices shall be received
at least three business days prior to the session date for classes held each
month. One-fourth of the session notices may be received less than three business
days but no later than the next business day after the session is held. Schools
which average four or less sessions per month may not exceed the one-fourth
of the session notices being late over any fiscal year quarter, September
through August. Said notice shall include the date, time, and location of
each class and shall be received in the headquarters of the Texas Alcoholic
Beverage Commission, P. O. Box 13127, Austin, Texas 78711 or local field office
on forms prescribed by the commission. The commission must be notified by
phone or fax of session cancellations prior to the actual session date except
when cancellation cannot be anticipated before the session's scheduled start.
When cancellation cannot be anticipated, the commission must be notified by
the tenth day of the month for each session cancelled during the previous
month.
(b)
All training facilities shall meet the requirements of
the Americans with Disabilities Act (ADA) and contain:
(1)
adequate seating facilities for all students;
(2)
appropriate space to ensure that visuals can be seen
from all seating positions;
(3)
private space to limit distractions; and
(4)
access to a restroom.
(c)
Sessions may be monitored unannounced to evaluate the program
content, trainer presentation and the classroom environment.
(d)
Programs approved for licensees/permittees or hotel management
companies shall be limited to employees of the said licensee, permittee, or
hotel management company.
(e)
No class may exceed 50 trainees. Trainees who arrive more
than 15 minutes after the start of the program session shall be denied admission
to the session.
(f)
The classroom presentation must be consistent with the
approved program.
(g)
Discussion must be pertinent to responsible alcoholic beverage
sale and service.
(h)
Each program session will be presented in a continuous
block of instruction. While instruction shall be interrupted for brief breaks,
these should be limited in number and duration. The program must be presented
in its entirety to each student in a language approved for use by the instructor.
(i)
Each trainee is to be tested immediately following the
conclusion of instruction at the program session he or she attends. Testing
of session participants at any other place or time is prohibited unless previously
approved as a part of the program.
(j)
Each trainee must correctly answer at least 70% of the
questions found on the test administered to him. Schools are encouraged to
set higher completion standards. Trainees who receive failing scores may be
immediately retested once. Otherwise, trainees must repeat the course in full.
(k)
All tests shall be administered on a closed book basis.
(l)
At the trainer's discretion the test may be offered in
a language best understood by the trainee. Bilingual instructors may, in response
to direct inquiries, clarify test questions using another language.
(m)
Each test must be maintained by the school for a period
of at least four years and be made available to the commission upon written
request.
(n)
Reports of Seller Training shall be made by the training
entity or school to the commission. Reports must be delivered or postmarked
within 30 calendar days of the date on which the session was held upon forms
prescribed and approved by the administrator.
(o)
Each Report of Seller Training shall contain the name,
social security number and date of birth of each student in that class who
has completed the training program and has passed the required test.
(p)
The certified trainer who actually conducted the program
shall personally sign the Report of Seller Training verifying that each designated
student has successfully completed the program approved by the commission
on the date indicated and shall verify such other facts as the administrator
may from time to time direct.
(q)
The Report of Seller Training shall be accompanied by a
payment in the amount of $2.00 per trainee.
(1)
Any payment under this subsection which is dishonored must
immediately be replaced by a cashier's check, certified check, or United States
postal money order.
(2)
Any training entity or school which has two dishonored
payments within a 12 month period must make subsequent payments of this fee
by a cashier's check, certified check, or United States postal money order
until twelve months have elapsed since the last payment was dishonored.
(r)
The administrator shall send the certificates to the school
which trained the trainees. Upon receipt, the school shall make a good faith
effort to promptly transmit each certificate to the appropriate trainee. Failure
to comply with this requirement is grounds for revoking or suspending approval
of the seller training program administered by that school.
This agency hereby certifies that the adoption has been reviewed
by legal counsel and found to be a valid exercise of the agency's legal authority.
Filed with the Office of the Secretary of State on March
24, 1999.
TRD-9901765
Doyne Bailey
Administrator
Texas Alcoholic Beverage Commission
Effective date: April 13, 1999
Proposal publication date: February 12, 1999
For further information, please call: (512) 206-3204
Chapter 65.
Boiler Division
Subchapter F. Quality of Service
Subchapter H. Telephone
Chapter 25.
Substantive Rules Applicable to Electric Service Providers
Subchapter K. Relationships With Affiliates
Chapter 26.
Substantive Rules Applicable to Telecommunications Service Providers
Subchapter L. Wholesale Market Provisions
Part III.
Texas Alcoholic Beverage Commission
Chapter 50.
Alcohol Awareness and Education
Part IV.
Texas Department of Licensing and Regulation