Part 2.
PUBLIC UTILITY COMMISSION OF TEXAS
Chapter 25.
SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS
Subchapter J. COSTS, RATES AND TARIFFS
2.
RECOVERY OF STRANDED COSTS
16 TAC §25.261
The Public Utility Commission of Texas (commission) proposes
new §25.261 relating to Stranded Cost Recovery of Environmental Cleanup
Costs and Redevelopment of Generating Sites. Project Number 21406 has been
assigned to this proceeding.
This rule sets out requirements and procedures for the implementation of
Public Utility Regulatory Act (PURA), Texas Utilities Code Annotated, §39.263.
PURA §39.263 allows recovery of capital costs incurred by an electric
utility or affiliated power generation company to improve air quality in accordance
with the provisions of PURA §39.264. PURA §39.263 also allows recovery
of capital costs incurred by an electric utility or affiliated power generation
company to achieve national ambient air quality standards. The implementation
of PURA §39.264 and regulatory programs designed to achieve compliance
with national ambient air quality standards fall under the auspices of the
Texas Natural Resource Conservation Commission (TNRCC). This rule also addresses
the manner in which stranded costs can be reduced through the redevelopment
of certain facilities in non-attainment and transmission constrained areas.
When commenting on specific subsections of the proposed rule or responding
to questions set forth in this preamble, parties are encouraged to describe
"best practice" examples of regulatory policies, and their rationale, that
have been proposed or implemented successfully in other states already undergoing
electric industry restructuring, if the parties believe that Texas would benefit
from application of the same policies. The commission is only interested in
receiving "leading edge" examples which are specifically related and directly
applicable to the Texas statute, rather than broad citations to other state
restructuring efforts.
In addition to comments on the proposed rule, the commission solicits input
on the following questions regarding the proposed rule:
1. Under the proposed rule, an application for approval of an electric
utility's or power generation company's determination regarding the most cost-effective
means of meeting the requirements of PURA §39.264 or achieving compliance
with national ambient air quality standards, or both, is deemed approved if
no objection is filed within 60-days of filing of a complete application and
completion of notice. Is the proposed 60-day period for objecting to an application
for a cost-effectiveness determination in proposed subsection (e)(3) a sufficient
period of time for an interested party to review the application and file
an objection, if needed?
2. In the event that an application for approval of a cost-effectiveness
determination is protested, the proposed rule requires that the commission
render a decision on the application within one year of filing. Should a different
time limit be placed on the cost-effectiveness determination than the one-year
period specified in proposed subsection (e)(4)?
3. The proposed rule does not allow recovery of costs associated with purchasing
emissions allowances, largely because an open market for purchasing allowances
does not presently exist. In the absence of an open market, verifying the
market value of an emission allowance is problematic. If the commission were
to allow recovery of capital costs associated with purchasing allowances,
what mechanisms could be used to determine whether allowance purchases are
prudent if spot market prices are not available for comparison? How could
the commission ensure that recovery is not allowed both for a utility (Utility
A) installing equipment to reduce emissions and another utility purchasing
allowances from Utility A? In other words, what methodologies could be used
to track traded allowances to ensure against double recovery?
4. Under the proposed rule, the cost of replacement generating capacity
is determined from the electric utility's average purchased power cost for
the three most current years and the average amount of generation for the
same three years. Should the replacement generating capacity be based on a
projected market price because the analysis deals with future costs? Included
in the commission-approved excess cost over market (ECOM) model are market
prices for power. Should these prices be used in the comparative analysis
instead of the average historical prices? Alternatively, should the commission
rely on market-price estimates proposed by the utility in its calculation
of ECOM for setting a competitive transition charge?
5. The commission recognizes that given the configuration of the electric
grid at present and in the near future, certain electric generating facilities
within the Electric Reliability Council of Texas (ERCOT) area need to operate
for the next three to seven years to maintain the reliability of the electric
system, despite their age and inefficient operating characteristics. Where
a facility is needed to maintain the reliability of the electric system and
is designated by the ERCOT Independent System Operator (ISO) as a reliability
must-run unit (RMR), the commission believes that a different analysis must
be employed that takes into consideration the benefits of the plant to electric
customers. One way of doing so is to explicitly consider customer benefits
when comparing retirement and retrofit options. It might also be reasonable
to simply assume that the customer benefits of RMR units are significant enough
that an explicit assessment of these benefits is not necessary. If this assumption
were used, only retrofit options for an RMR unit would be evaluated. How should
the commission analyze retirement/retrofit options for RMR units? If it uses
a customer benefit analysis, are there accepted values for the customer benefits
of electric service that could be incorporated into the rule?
6. After the electric utility has shown that retrofitting a facility is
more cost effective than retiring, is there a benchmark amount that can be
used to determine whether the level of expenditures are reasonable and prudent?
If a benchmark is appropriate, then should the benchmark be expressed in dollars
per kilowatt, dollars per kilowatt-hour, dollars per ton of nitrogen oxide
removed or some other measure? Industry data should be provided to substantiate
the comments made about the proper level of benchmarks. Provisions will be
made to handle proprietary information if a request is made in response to
this question.
7. What alternative procedure can be included in this rule to reduce the
reliance on after-the-fact review on the reasonableness and prudence of costs,
thereby providing customers and companies greater certainty of the costs to
be recovered for air emission reductions?
8. The commission recognizes that regulatory risk is limiting the installation
of new power generation in greenfield and brownfield sites in non-attainment
and transmission constrained areas, thereby reducing the market value of those
plant sites. The commission has been working with the TNRCC and ERCOT to reduce
these regulatory uncertainties and to increase the opportunities for the incumbent
utility to sell sites for redevelopment that would otherwise be slated for
retirement. The commission believes that these sales or redevelopments would
reduce ECOM, reduce concentration in the generation sector, and increase power
generation within the non-attainment and transmission constrained areas while
complying with the TNRCC air quality standards. In subsection (e)(1)(I) of
the proposed rule, the owners of the generating facilities in a non-attainment
and transmission constrained area will estimate the market value of redeveloping
each plant site that contains generating facilities where a retrofit would
not qualify for stranded cost recovery. The goal of this provision is to determine
the best option for these generating facilities from the perspective of electric
customers: retrofit of the facility, retirement, or the redevelopment as a
new power plant. This same subsection provides a set of criteria to estimate
the market value of redeveloping plant sites in a non-attainment and transmission
constrained area. Is using these criteria a reasonable approach? If not, please
suggest changes that allow the commission to better assess the market value
of redeveloping a plant site.
Brian Almon, Director for Engineering, Office of Regulatory Affairs, has
determined that for each year of the first five-year period the proposed section
is in effect there will be no fiscal implications for state or local government
as a result of enforcing or administering the section.
Mr. Almon has also determined that for each year of the first five years
the proposed section is in effect the public benefit anticipated as a result
of enforcing the section will be reliable electric service and improved air
quality. There will be no effect on small businesses or micro-businesses as
a result of enforcing this section. There is no anticipated economic cost
to such persons to comply with the section as proposed.
Mr. Almon has also determined that for each year of the first five years
the proposed section is in effect there should be no negative effect on a
local economy, and therefore no local employment impact statement is required
under Administrative Procedure §2001.022.
The commission staff will conduct a public hearing on this rulemaking under
Government Code §2001.029 at the commission's offices, located in the
William B. Travis Building, 1701 North Congress Avenue, Austin, Texas 78701,
on Thursday, June 22, 2000, at 9:30 a.m. in the Commissioners' Hearing Room
located on the 7th Floor.
Comments on the proposed new rule (16 copies) may be submitted to the Filing
Clerk, Public Utility Commission of Texas, 1701 North Congress Avenue, PO
Box 13326, Austin, Texas 78711-3326, within 30 days after publication. The
commission invites specific comments regarding the costs associated with,
and benefits that will be gained by, implementation of the proposed section.
The commission will consider the costs and benefits in deciding whether to
adopt the section. All comments should refer to Project Number 21406.
This new section is proposed under the Public Utility Regulatory
Act, Texas Utilities Code Annotated (Vernon 1998, Supplement 2000) (PURA) §14.002,
which provides the Public Utility Commission with the authority to make and
enforce rules reasonably required in the exercise of its powers and jurisdiction;
PURA §39.257, which requires the reduction of stranded costs through
the application of any positive difference between certain annual revenues
and annual costs; and specifically, PURA §39.263, which authorizes recovery
of certain capital costs incurred by an electric utility or affiliated power
generation company to improve air quality in accordance with PURA §39.264
or to achieve compliance with national ambient air quality standards and PURA §39.264,
which authorizes the TNRCC to adopt rules to improve air quality.
Cross Reference to Statutes: Public Utility Regulatory Act §§14.002,
39.257, 39.263 and 39.264.
§25.261. Stranded Cost Recovery of Environmental Cleanup Costs and Redevelopment of Generating Sites.
(a)
Purpose. The purpose of this section is to:
(1)
establish the procedures and criteria the commission shall
use to determine the amount of stranded cost recovery electric utilities and
affiliated power generation companies shall receive for environmental cleanup
costs incurred to improve air quality in the state pursuant to Public Utility
Regulatory Act (PURA) §39.263; and
(2)
reduce stranded costs through the redevelopment of
electric facilities.
(b)
Applicability. This section applies to:
(1)
electric utilities that seek to recover capital costs
incurred during the period January 1, 1999 to April 30, 2003 to improve air
quality;
(2)
affiliated power generation companies that seek to
recover capital costs incurred during the period January 1, 2002, to April
30, 2003 to improve air quality; and
(3)
any electric utility or affiliated power generating
company operating electric generating facilities in a non-attainment and transmission
constrained area that has stranded costs.
(c)
Definitions. The following words and terms, when used
in this chapter, shall have the following meanings unless the context clearly
indicates otherwise:
(1)
Conservation Commission -- The Texas Natural Resource
Conservation Commission.
(2)
Cost of replacement generating capacity -- The cost
of replacing generating capacity lost through retirement of an electric generating
facility. The annual cost of replacement generating capacity will be calculated
using the following equation:
Figure: 16 TAC §25.261(c)(2)
(3)
Electric generating facility -- A facility that generates
electric energy for compensation and is owned or operated by a person in this
state, including a municipal corporation, electric cooperative, or river authority.
(4)
Net book value -- The original cost of an asset less
accumulated depreciation.
(5)
Non-attainment area -- Any applicable ozone non-attainment
area as designated by the conservation commission at 30 TAC §117.10.
(6)
Offset -- The allocation of emission allowances or
credits from one facility to another facility in the same region.
(7)
Redevelopment -- The retirement of an existing electric
generating facility and the construction of a new electric generating facility
on the same site.
(8)
Region -- The East Region, West Region, or El Paso
Region, as defined by the conservation commission at 30 TAC §101.330.
(9)
Retirement -- The permanent removal from service
of an electric generating facility.
(10)
Retrofit -- The installation of control technology
on an electric generating facility to reduce the emissions of nitrogen oxide,
sulfur dioxide, or both.
(11)
Transmission constrained -- A limit in the transmission
system that prevents the reliable delivery of electricity from the source
generation selected by the load as determined by the independent organization
designated for the area under PURA §39.151.
(12)
Transportation equipment -- A rail spur at a lignite-fired
electric generating facility installed to receive deliveries of western coal.
Transportation equipment does not include rail cars and unloading facilities.
(d)
Requirements.
(1)
Qualifying costs. To qualify for recovery as invested
capital pursuant to PURA §39.263, a cost must be:
(A)
reasonable and prudent;
(B)
incurred in carrying out the most cost-effective alternative
for improving air quality that meets the requirements of this section;
(C)
incurred to reduce or offset emissions by an amount and
at a location that is consistent with the air quality goals and policies of
the conservation commission;
(D)
incurred to offset or reduce the emission of airborne
contaminants from an electric generating facility, where
(i)
the emission reduction or offset is determined by the
conservation commission to be an essential component in achieving compliance
with a national ambient air quality standard. For purposes of this section,
any emission reduction or offset achieved by an electric utility or affiliated
power generation company to comply with conservation commission regulations
at 30 TAC Chapter 117 is deemed to have been determined by the conservation
commission to be an essential component in achieving compliance with a national
ambient air quality standard; or
(ii)
the reduction or offset is necessary for an unpermitted
electric generating facility to obtain a permit in the manner provided by
PURA §39.264; and
(E)
associated with the engineering, procurement, or installation
of pollution control equipment or transportation equipment, or the retirement
of an electric generating facility.
(2)
When costs incurred. For purposes of this section,
the electric utility or affiliated power generation company has incurred costs
if it has expended funds or has committed to expend funds under the terms
of a written agreement.
(3)
Operating and maintenance costs. This section does
not authorize the recovery of operating and maintenance costs, the capital
cost of a new electric generating facility, or for the purchase of allowances
or credits.
(4)
Apportionment of reductions. As provided in this
paragraph, the commission may apportion the capital invested to reduce emissions
of nitrogen oxides, sulfur dioxide, or both, among one or more entities owning
facilities located in the same region. The capital investments for which recovery
is sought must have been incurred pursuant to a written agreement between
the entities executed prior to the date any such costs were incurred. The
commission may not apportion capital costs under this provision unless the
criteria of paragraph (1) of this subsection are met for each electric generating
facility seeking capital cost recovery. Capital costs shall be apportioned
by prorating the total capital invested between entities on the basis of reductions
of nitrogen oxides, sulfur dioxide, or both, realized at each participating
entity's facilities in the region.
(e)
Request for approval of cost-effectiveness determination.
(1)
Application. On or before January 1, 2003, each electric
utility or affiliated power generation company that seeks recovery of capital
costs pursuant to this section shall file an application for a determination
that its plan for meeting the requirements of PURA §39.264 and the regulatory
programs designed to achieve compliance with national ambient air quality
standards are cost-effective under this section. No more than one application
may be filed for generating facilities owned by the same electric utility
or affiliated power generation company in the same region. The application
shall include the information specified in subparagraphs (A) - (I) of this
paragraph.
(A)
Description. A general description of the generating facility,
including but not limited to:
(i)
net generating capacity in megawatts;
(ii)
type of fuel used for electric generation;
(iii)
the county and region in which each facility addressed
in the application is located;
(iv)
average capacity factor for the three most current calendar
years as reported to the commission; and
(v)
average generation in megawatt-hours for the three most
current calendar years, as reported to the commission.
(B)
Total emissions. The total annual emissions (in tons)
of nitrogen oxides and sulfur dioxide:
(i)
for the year 1997;
(ii)
for the most recent calendar year for which data is available;
(iii)
that is expected for the first calendar year after the
implementation of the air quality improvement strategies for which cost recovery
will be requested; and
(iv)
for the calendar years 2003 through 2005.
(C)
Allocated emissions allowances. The number of emission
allowances allocated to the electric generating facility by the conservation
commission.
(D)
Capital cost estimate. The total amount of qualifying
capital costs for each option evaluated by the electric utility or affiliated
power generation company.
(E)
Alternatives. A decision analysis for all electric generating
facilities owned by a utility or affiliated power generation company in the
same region comparing the cost-effectiveness of the retirement option with
retrofit options and other possible options considered by the electric utility
or affiliated power company. Other options shall include:
(i)
offsetting emissions at the electric generating facility
by installing control technology at another facility; and
(ii)
switching fuel used for electricity generation at the
electric generating facility.
(F)
Comparative cost analysis. The net present value of the
cost of each option considered pursuant to subparagraph (E) of this paragraph.
The period of the analysis shall begin on May 1, 2003, and extend for a period
of 15 years. The discount rate used in the analysis and the cost of capital
associated with each option shall be calculated differently. Both shall start
with the capital structure and cost of capital as they are reported for the
end of 1999 in the utility's annual report made pursuant to PURA §39.257.
The discount rate shall be the after-tax weighted cost of capital, while the
cost of capital associated with each option shall be taken directly from the
annual report, except for the cost of debt. The cost of debt for this purpose
shall be the average cost of debt for the months of October, November, and
December 1999 as reported by Moody's Investors Service for utilities with
the same Moody's bond rating as the utility making the filing. All assumptions
used in the analysis shall be provided. If the lowest-cost alternative is
not selected as the most cost-effective, an explanation of why it was not
selected shall be provided.
(G)
Retrofit. The retrofit alternative analysis shall include
a calculation of the net present value of the capital and operating costs,
and an estimate of the total cost per ton of pollutant reduced. The operating
costs shall be the average of the historical operating costs for the particular
generating facility for the three most recent calendar years plus the additional
incremental operating costs associated with the control technology, adjusted
for inflation using an appropriate factor for each year of the analysis. The
capital costs shall be an estimate for each control technology as of May 1,
2003.
(H)
Retirement. The retirement analysis shall include the
net present value of all relevant costs of retirement for each electric generating
facility, including:
(i)
the cost of replacement generating capacity in dollars
per megawatt-hour as defined in subsection (c)(2) of this section; and
(ii)
the net book value of the facility, including retirement
costs and offsetting salvage value, which includes but is not limited to the
market value of the land after the facility is retired, and the value of water
rights, pollution credits or benefits associated with the facility, and other
infrastructure.
(I)
Redevelopment. If retirement of the electric generating
facility is determined to be the more cost-effective alternative than retrofit
and if the facility is located in a non-attainment area as designated by the
conservation commission, and in an area of constrained transmission, as determined
by the independent organization designated for the area under PURA §39.151,
then the utility or affiliated power generation company shall perform a redevelopment
analysis. The utility or affiliated power generation company shall make reasonable
effort to facilitate a sale of the redevelopment site before April 30, 2003.
To determine the value of redevelopment, the utility or affiliated power generation
company shall assume the following in its analysis for each site and the electric
generating facilities located on the site:
(i)
The physical configuration of the site and the maximum
number of emission credits obtained for closing the existing facility will
be used to optimize the size of the new facility in megawatts.
(ii)
Capacity factors for the new facility will be consistent
with the size and function of a new plant on the site and shall be 10% for
peaking units; 50% for intermediate units; and 80% for baseload units.
(iii)
Any costs for transmission upgrades at the sites that
are designated for potential redevelopment may be excluded from the estimated
redevelopment costs.
(iv)
The site will have sufficient access to natural gas pipeline
capacity at competitive prices.
(v)
Full assessment of the potential environmental cleanup
cost at each facility site.
(2)
Notice. Notice of an application for approval
of a cost-effectiveness determination shall be provided through newspaper
publication once a week for two consecutive weeks in a newspaper of general
circulation throughout the service area of each electric generating facility
addressed in the application. Such newspaper notice shall state in plain language:
(A)
the purpose of the application;
(B)
the electric generating facilities addressed in the application;
(C)
the air quality improvement strategy proposed for each
electric generating facility addressed in the application; and
(D)
the date the application will be deemed approved if no
objection is filed with the commission.
(3)
Approval of an application for determination
of cost-effectiveness. An application shall be deemed approved without further
commission action if no objection to the application is filed with the commission
within 60 days after the application was filed and adequate notice has been
completed.
(4)
Decision. If an application is not approved by the
method provided in paragraph (3) of this subsection, the commission shall
render a decision approving or denying an application for a cost-effectiveness
determination within one year from the date of filing of a complete application.
(f)
Reconciliation of environmental cleanup costs during the
true-up proceedings. Capital invested for environmental cleanup in accordance
with the provisions of this section shall be considered for inclusion as net
invested capital under PURA §39.263 during the true-up proceedings under
PURA §39.262, subject to the provisions of this paragraph:
(1)
Burden of proof.
(A)
Recovery of costs. In determining the amount of environmental
cleanup costs that the electric utility may recover as invested capital under
PURA §39.263, the electric utility or affiliated power generation company
has the burden of showing that its qualifying costs during the period were
prudent, reasonable, and necessary and were incurred to implement the most
cost-effective alternative as determined by the commission pursuant to the
provisions of subsection (e) of this section. For those electric generating
facilities where their owners can show that retrofitting the facilities is
more cost effective than retiring them, the commission presumes that costs
for retrofitting a natural gas-fired electric generating facility that are
no more than $10 per kilowatt for combustion control technology and $25 per
kilowatt for technology that reduces emissions by 80% or more are reasonable
and prudent. Likewise, the commission presumes that costs for retrofitting
a coal-fired electric generating facility that are no more than $20 per kilowatt
for combustion control technology and $80 per kilowatt for technology that
reduces emissions by 80% or more are reasonable and prudent.
(B)
Excess cost over market (ECOM) savings. The market value
of plant sites estimated in the redevelopment analysis as described in subsection
(e)(1)(I) of this section will be compared to the actual sales price of the
sites by the utility at the time of the true-up in 2004. If the commission
determines the sales price is not an accurate reflection of the redevelopment
potential of these sites, the commission retains the right to reduce ECOM
by an appropriate amount to reflect the redevelopment value of those sites.
(2)
Scope. Any issue related to determining the
prudence and reasonableness of the environmental clean-up costs which the
electric utility or affiliated power generation company is seeking recovery
as invested capital or the value of the redeveloped sites shall be within
the scope of the proceeding. The prudence and reasonableness of the alternative
selected for each electric generating facility is not within the scope of
this proceeding.
This agency hereby certifies that the proposal has been
reviewed by legal counsel and found to be within the agency's legal authority
to adopt.
Filed with the Office of
the Secretary of State, on April 28, 2000.
TRD-200003026
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Earliest possible date of adoption: June 11, 2000
For further information, please call: (512) 936-7308
Subchapter R. PROVISIONS RELATING TO MUNICIPAL REGULATION AND RIGHTS-OF-WAY MANAGEMENT
16 TAC §26.467
The Public Utility Commission of Texas (commission) proposes
an amendment to §26.467 relating to Rates, Allocation, Compensation,
Adjustments and Reporting.
The commission amends subsection (k) to correct an inadvertent error in
the calculation of the due date for the first-time filing of the quarterly
access line count report. Section 26.467 implements the provisions of House
Bill 1777 (HB 1777), Act of May 25, 1999, 76th Legislature, Regular Session,
chapter 840, 1999 Texas Session Law Service 3499 (Vernon) (to be codified
as an amendment to Local Government Code §283.001, et. seq.). In order
to provide the 45-day implementation period mandated in Local Government Code,
Chapter 283, the commission extends the time for certificated telecommunications
providers (CTPs) to file this report from October 15, 2000 to November 15,
2000. Project Number 20935 is assigned to this proceeding.
D. Diane Parker, Senior Attorney, Office of Policy Development, and Elango
Rajagopal, Senior Policy Analyst, Office of Regulatory Affairs, have determined
that for each year of the first five-year period the proposed section is in
effect there will be no fiscal implications for state or local government
as a result of enforcing or administering the section.
Mr. Rajagopal and Ms. Parker have determined that for each year of the
first five years the proposed section is in effect the public benefit anticipated
as a result of enforcing the section will be that CTPs will have more time
to provide an accurate quarterly access line count report. There will be no
effect on small businesses or micro-businesses as a result of enforcing this
section. There is no anticipated economic cost to persons who are required
to comply with the section as proposed.
Mr. Rajagopal and Ms. Parker have also determined that for each year of
the first five years the proposed section is in effect there should be no
effect on a local economy, and therefore no local employment impact statement
is required under Administrative Procedure Act §2001.022.
Comments on the proposed amendment (16 copies) may be submitted to the
Filing Clerk, Public Utility Commission of Texas, 1701 North Congress Avenue,
PO Box 13326, Austin, Texas 78711-3326, within 30 days after publication.
The commission invites specific comments regarding the costs associated with,
and benefits that will be gained by, implementation of the proposed section.
The commission will consider the costs and benefits in deciding whether to
adopt the section. All comments should refer to Project Number 20935.
This amendment is proposed 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,
including rules of practice and procedure. This proposed rule is also authorized
by House Bill 1777, 76th Legislature, Regular Session (1999), Local Government
Code §283.055 and §283.058.
Cross Reference to Statutes: Public Utility Regulatory Act §14.002,
Local Government Code §283.055 and §283.058.
§26.467. Rates, Allocation, Compensation, Adjustments and Reporting.
(a) - (j)
(No change.)
(k)
CTP implementation of commission-established rates. CTPs
shall continue to compensate municipalities at the rates required under the
terms of the expired or terminated agreements or ordinances until the CTP
implements the commission established initial and/or updated rates. A CTP
not subject to an existing franchise agreement or ordinance that wants to
construct facilities to offer telecommunications services in the municipality
shall pay fees that are competitively neutral and non-discriminatory, consistent
with the charges of the most recent agreement or ordinance between the municipality
and the CTP serving the largest number of access lines within the municipality
until the right-of-way fees established by the commission take effect.
(1) - (2)
(No change.)
(3)
Subsequent quarterly compensation and reporting.
All CTPs shall implement commission-established initial and updated rates
(as applicable) no later than July 1, 2000, and revised rates (as applicable)
for the subsequent quarters.
(A)
Quarterly access line count report. No later than
November 15, 2000
[
(B)
Compensation. Beginning July 1, 2000, CTPs shall apply
the most recent commission-established rates to access line in a municipality.
The municipal compensation shall be an amount equal to the rate per category
of access line multiplied by the number of access lines in that category in
that municipality at the end of each month in a
calendar
quarter
as reflected in reports filed pursuant to subparagraph (A) of this paragraph.
All CTPs shall pay to municipalities the compensation for the third calendar
quarter of 2000, no later than
November 15, 2000
[
(4)
(No change.)
(l) - (n)
(No change.)
This agency hereby certifies that the proposal has been reviewed
by legal counsel and found to be within the agency's legal authority to adopt.
Filed with the Office of
the Secretary of State, on April 28, 2000.
TRD-200003012
Rhonda Dempsey
Rules Coordinator
Public Utility Commission of Texas
Earliest possible date of adoption: June 11, 2000
For further information, please call: (512) 936-7308
Chapter 45.
MARKETING PRACTICES
Subchapter D. ADVERTISING AND PROMOTION--ALL BEVERAGES
Chapter 26.
SUBSTANTIVE RULES APPLICABLE TO TELECOMMUNICATIONS SERVICE PROVIDERS
October 15, 2000
], a CTP shall file a
quarterly access line count report for the preceding calendar quarter with
the commission. All subsequent quarterly access line count reports shall be
due no later than 45 days from the end of the preceding calendar quarter.
The quarterly access line count report shall include a count of the number
of access lines, by category, by municipality, for the end of each month of
the preceding quarter. The report shall exclude lines that are resold or leased
to other CTPs unless an intercarrier agreement has been reached pursuant to
subsection (l) of this section. The CTP shall include with the report a certified
statement from an authorized officer or duly authorized representative of
the CTP certifying that the information contained in the report is true and
correct to the best of the officer's or representative's knowledge and belief
after inquiry. On request and subject to the confidentiality protections of
the Local Government Code, §283.005, each CTP shall provide each affected
municipality with a copy of the report required by this subsection.
October
15, 2000
]. All payments for subsequent
calendar
quarters
shall be made no later than 45 days from the end of that quarter.
Part 3.
TEXAS ALCOHOLIC BEVERAGE COMMISSION