Texas Administrative Code
Title 16 - ECONOMIC REGULATION
Part 2 - PUBLIC UTILITY COMMISSION OF TEXAS
Chapter 25 - SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS
Subchapter H - ELECTRICAL PLANNING
Division 2 - ENERGY EFFICIENCY AND CUSTOMER-OWNED RESOURCES
Section 25.181 - Energy Efficiency Goal
Universal Citation: 16 TX Admin Code § 25.181
Current through Reg. 50, No. 13; March 28, 2025
(a) Purpose. The purpose of this section is to ensure that:
(1) electric utilities administer energy
efficiency incentive programs in a market-neutral, nondiscriminatory manner and
do not offer competitive services, except as permitted in §
25.343 of this title (relating to
Competitive Energy Services) or this section;
(2) all customers, in all eligible customer
classes and all areas of an electric utility's service area, have a choice of
and access to the utility's portfolio of energy efficiency programs that allow
each customer to reduce energy consumption, summer and winter peak demand, or
energy costs; and
(3) each electric
utility annually provides, through market-based standard offer programs,
targeted market-transformation programs, or utility self-delivered programs,
incentives sufficient for residential and commercial customers, retail electric
providers, and energy efficiency service providers to acquire additional
cost-effective energy efficiency, subject to EECRF caps established in §
25.182(d)(7) of
this title (relating to Energy Efficiency Cost Recovery Factor), for the
utility to achieve the goals in subsection (e) of this
section.
(b) Application. This section applies to electric utilities and the Electric Reliability Council of Texas, Inc. (ERCOT).
(c) Definitions. The following terms, when used in this section and in § 25.182 of this title, shall have the following meanings unless the context indicates otherwise:
(1) Affiliate --
(A) A person who directly or indirectly owns
or holds at least 5.0% of the voting securities of an energy efficiency service
provider;
(B) A person in a chain
of successive ownership of at least 5.0% of the voting securities of an energy
efficiency service provider;
(C) A
corporation that has at least 5.0% of its voting securities owned or
controlled, directly or indirectly, by an energy efficiency service
provider;
(D) A corporation that
has at least 5.0% of its voting securities owned or controlled, directly or
indirectly, by:
(i) a person who directly or
indirectly owns or controls at least 5.0% of the voting securities of an energy
efficiency service provider; or
(ii) a person in a chain of successive
ownership of at least 5.0% of the voting securities of an energy efficiency
service provider; or
(E)
A person who is an officer or director of an energy efficiency service provider
or of a corporation in a chain of successive ownership of at least 5.0% of the
voting securities of an energy efficiency service provider;
(F) A person who actually exercises
substantial influence or control over the policies and actions of an energy
efficiency service provider;
(G) A
person over which the energy efficiency service provider exercises the control
described in subparagraph (F) of this paragraph;
(H) A person who exercises common control
over an energy efficiency service provider, where "exercising common control
over an energy efficiency service provider" means having the power, either
directly or indirectly, to direct or cause the direction of the management or
policies of an energy efficiency service provider, without regard to whether
that power is established through ownership or voting of securities or any
other direct or indirect means; or
(I) A person who, together with one or more
persons with whom the person is related by ownership, marriage or blood
relationship, or by action in concert, actually exercises substantial influence
over the policies and actions of an energy efficiency service provider even
though neither person may qualify as an affiliate individually.
(2) Baseline--A relevant condition
that would have existed in the absence of the energy efficiency project or
program being implemented, including energy consumption that would have
occurred. Baselines are used to calculate program-related demand and energy
savings. Baselines can be defined as either project-specific baselines or
performance standard baselines (e.g., building codes).
(3) Claimed savings--Values reported by an
electric utility after the energy efficiency activities have been completed,
but prior to the time an independent, third-party evaluation of the savings is
performed. As with projected savings estimates, these values may utilize
results of prior evaluations and/or values in technical reference manuals.
However, they are adjusted from projected savings estimates by correcting for
any known data errors and actual installation rates and may also be adjusted
with revised values for factors such as per-unit savings values, operating
hours, and savings persistence rates. Can be indicated as first year, annual
demand or energy savings, and/or lifetime energy or demand savings values. Can
be indicated as gross savings and/or net savings values.
(4) Commercial customer--A non-residential
customer taking service at a point of delivery at a distribution voltage under
an electric utility's tariff during the prior program year or a non-profit
customer or government entity, including an educational institution. For
purposes of this section, each point of delivery shall be considered a separate
customer.
(5) Competitive energy
efficiency services--Energy efficiency services that are defined as competitive
under §
25.341 of this title (relating to
Definitions).
(6) Conservation load
factor--The ratio of the annual energy savings goal, in kilowatt hours (kWh),
to the peak demand goal for the year, measured in kilowatts (kW) and multiplied
by the number of hours in the year.
(7) Deemed savings calculation--An
industry-wide engineering algorithm used to calculate energy and/or demand
savings of the installed energy efficiency measure that has been developed from
common practice that is widely considered acceptable for the measure and
purpose, and is applicable to the situation being evaluated. May include
stipulated assumptions for one or more parameters in the algorithm, but
typically requires some data associated with actual installed measure. An
electric utility may use the calculation with documented measure-specific
assumptions, instead of energy and peak demand savings determined through
measurement and verification activities or the use of deemed savings.
(8) Deemed savings value--An estimate of
energy or demand savings for a single unit of an installed energy efficiency
measure that has been developed from data sources and analytical methods that
are widely considered acceptable for the measure and purpose, and is applicable
to the situation being evaluated. An electric utility may use deemed savings
values instead of energy and peak demand savings determined through measurement
and verification activities.
(9)
Demand--The rate at which electric energy is used at a given instant, or
averaged over a designated period, usually expressed in kW or megawatts
(MW).
(10) Demand savings--A
quantifiable reduction in demand.
(11) Eligible customers--Residential and
commercial customers. In addition, to the extent that they meet the criteria
for participation in load management standard offer programs developed for
industrial customers and implemented prior to May 1, 2007, industrial customers
are eligible customers solely for the purpose of participating in such
programs.
(12) Energy
efficiency--Improvements in the use of electricity that are achieved through
customer facility or customer equipment improvements, devices, processes, or
behavioral or operational changes that produce reductions in demand or energy
consumption with the same or higher level of end-use service and that do not
materially degrade existing levels of comfort, convenience, and
productivity.
(13) Energy
Efficiency Cost Recovery Factor (EECRF)--An electric tariff provision,
compliant with §
25.182 of this title, ensuring
timely and reasonable cost recovery for utility expenditures made to satisfy
the goal of PURA §39.905 that provide for a portfolio of cost-effective
energy efficiency programs under this section.
(14) Energy efficiency measures--Equipment,
materials, and practices, including practices that result in behavioral or
operational changes, implemented at a customer's site on the customer's side of
the meter that result in a reduction at the customer level and/or on the
utility's system in electric energy consumption, measured in kWh, or peak
demand, measured in kW, or both. These measures may include thermal energy
storage and removal of an inefficient appliance so long as the customer need
satisfied by the appliance is still met.
(15) Energy efficiency program--The aggregate
of the energy efficiency activities carried out by an electric utility under
this section or a set of energy efficiency projects carried out by an electric
utility under the same name and operating rules.
(16) Energy efficiency project--An energy
efficiency measure or combination of measures undertaken in accordance with a
standard offer, market transformation program, or self-delivered
program.
(17) Energy efficiency
service provider--A person or other entity that installs energy efficiency
measures or performs other energy efficiency services under this section. An
energy efficiency service provider may be a retail electric provider or
commercial customer, provided that the commercial customer has a peak load
equal to or greater than 50 kW. An energy efficiency service provider may also
be a governmental entity or a non-profit organization, but may not be an
electric utility.
(18) Energy
savings--A quantifiable reduction in a customer's consumption of energy that is
attributable to energy efficiency measures, usually expressed in kWh or
MWh.
(19) Estimated useful life
(EUL)--The number of years until 50% of installed measures are still operable
and providing savings, and is used interchangeably with the term "measure
life". The EUL determines the period of time over which the benefits of the
energy efficiency measure are expected to accrue.
(20) Evaluated savings--Savings estimates
reported by the EM&V contractor after the energy efficiency activities and
an impact evaluation have been completed. Differs from claimed savings in that
the EM&V contractor has conducted some of the evaluation and/or
verification activities. These values may rely on claimed savings for factors
such as installation rates and the Technical Reference Manual for values such
as per unit savings values and operating hours. These savings estimates may
also include adjustments to claimed savings for data errors, per unit savings
values, operating hours, installation rates, savings persistence rates, or
other considerations. Can be indicated as first year, annual demand or energy
savings, and/or lifetime energy or demand savings values. Can be indicated as
gross savings and/or net savings values.
(21) Evaluation--The conduct of any of a wide
range of assessment studies and other activities aimed at determining the
effects of a program; or aimed at understanding or documenting program
performance, program or program-related markets and market operations,
program-induced changes in energy efficiency markets, levels of demand or
energy savings, or program cost-effectiveness. Market assessment, monitoring,
and evaluation, and measurement and verification (M&V) are aspects of
evaluation.
(22) Evaluation,
measurement, and verification (EM&V) contractor--One or more independent,
third-party contractors selected and retained by the commission to plan,
conduct, and report on energy efficiency evaluation activities, including
verification.
(23) Free
driver--Customers who do not directly participate in an energy efficiency
program, but who undertake energy efficiency actions in response to program
activity.
(24) Free rider--A
program participant who would have implemented the program measure or practice
in the absence of the program. Free riders can be total, in which the
participant's activity would have completely replicated the program measure;
partial, in which the participant's activity would have partially replicated
the program measure; or deferred, in which the participant's activity would
have completely replicated the program measure, but at a time after the time
the program measure was implemented.
(25) Growth in demand--The annual increase in
demand in the Texas portion of an electric utility's service area at time of
peak demand, as measured in accordance with this section.
(26) Gross savings--The change in energy
consumption and/or demand that results directly from program-related actions
taken by participants in an efficiency program, regardless of why they
participated.
(27) Hard-to-reach
customers--Residential customers with an annual household income at or below
200% of the federal poverty guidelines.
(28) Impact evaluation--An evaluation of the
program-specific, directly induced changes (e.g., energy and/or demand
reduction) attributable to an energy efficiency program.
(29) Incentive payment--Payment made by a
utility to an energy efficiency service provider, an end-use customer, or
third-party contractor to implement and/or attract customers to energy
efficiency programs, including standard offer, market transformation and
self-delivered programs.
(30)
Industrial customer--A for-profit entity engaged in an industrial process
taking electric service at transmission voltage, or a for-profit entity engaged
in an industrial process taking electric service at distribution voltage that
qualifies for a tax exemption under Tax Code §
151.317 and has submitted an
identification notice under subsection (u) of this section.
(31) Inspection--Examination of a project to
verify that an energy efficiency measure has been installed, is capable of
performing its intended function, and is producing an energy savings or demand
reduction equivalent to the energy savings or demand reduction reported towards
meeting the energy efficiency goals of this section.
(32) Installation rate--The percentage of
measures that receive incentives under an energy efficiency program that are
actually installed in a defined period of time. The installation rate is
calculated by dividing the number of measures installed by the number of
measures that receive incentives under an efficiency program in a defined
period of time.
(33) International
performance measurement and verification protocol (IPMVP)--A guidance document
issued by the Efficiency Valuation Organization with a framework and
definitions describing the M&V approaches.
(34) Lifetime energy (demand) savings--The
energy (demand) savings over the lifetime of an installed measure(s),
project(s), or program(s). May include consideration of measure estimated
useful life, technical degradation, and other factors. Can be gross or net
savings.
(35) Load
control--Activities that place the operation of electricity-consuming equipment
under the control or dispatch of an energy efficiency service provider, an
independent system operator, or other transmission organization or that are
controlled by the customer, with the objective of producing energy or demand
savings.
(36) Load management--Load
control activities that result in a reduction in peak demand, or a shifting of
energy usage from a peak to an off-peak period or from high-price periods to
lower price periods.
(37) Market
transformation program--Strategic programs intended to induce lasting
structural or behavioral changes in the market that result in increased
adoption of energy efficient technologies, services, and practices, as
described in this section.
(38)
Measurement and verification--A subset of program impact evaluation that is
associated with the documentation of energy or demand savings at individual
sites or projects using one or more methods that can involve measurements,
engineering calculations, statistical analyses, and/or computer simulation
modeling. M&V approaches are defined in the IPMVP.
(39) Net savings--The total change in load
that is attributable to an energy efficiency program. This change in energy
and/or demand use shall include, implicitly or explicitly, consideration of
appropriate factors. These factors may include free ridership, participant and
non-participant spillover, induced market effects, changes in the level of
energy service, and/or other non-program causes of changes in energy use and/or
demand.
(40) Net-to-gross--A factor
representing net program savings divided by gross program savings that is
applied to gross program impacts to convert them into net program impacts. The
factor may be made up of a variety of factors that create differences between
gross and net savings, commonly considering the effects of free riders and
spillover.
(41) Non-participant
spillover--Energy savings that occur when a program non-participant installs
energy efficiency measures or applies energy savings practices as a result of a
program's influence.
(42) Off-peak
period--Period during which the demand on an electric utility system is not at
or near its maximum. For the purpose of this section, the off-peak period
includes all hours that are not in the peak period.
(43) Participant spillover--The additional
energy savings that occur when a program participant independently installs
incremental energy efficiency measures or applies energy savings practices
after having participated in the efficiency program as a result of the
program's influence.
(44) Peak
demand--Electrical demand at the times of highest annual demand on the
utility's system at the source. Peak demand refers to Texas retail peak demand
and, therefore, does not include demand of retail customers in other states or
wholesale customers.
(45) Peak
demand reduction--Reduction in demand on the utility's system at the times of
the utility's summer peak period or winter peak period.
(46) Peak period--For the purpose of this
section, the peak period consists of the hours from one p.m. to seven p.m.
during the months of June, July, August, and September, and the hours of six
a.m. to ten a.m. and six p.m. to ten p.m. during the months of December,
January, and February, excluding weekends and Federal holidays.
(47) Program year--A year in which an energy
efficiency incentive program is implemented, beginning January 1 and ending
December 31.
(48) Projected
savings--Values reported by an electric utility prior to the time the energy
efficiency activities are implemented. Are typically estimates of savings
prepared for program and/or portfolio design or planning purposes. These values
are based on pre-program or portfolio estimates of factors such as per-unit
savings values, operating hours, installation rates, and savings persistence
rates. These values may utilize results of prior evaluations and/or values in
the Technical Reference Manual. Can be indicated as first year, annual demand
or energy savings, and/or lifetime energy or demand savings values. Can be
indicated as gross savings and/or net savings values.
(49) Renewable demand side management (DSM)
technologies--Equipment that uses a renewable energy resource (renewable
resource), as defined in §
25.173(c) of
this title (relating to Goal for Renewable Energy), a geothermal heat pump, a
solar water heater, or another natural mechanism of the environment, that when
installed at a customer site, reduces the customer's net purchases of energy,
demand, or both.
(50)
Savings-to-Investment Ratio (SIR)--The ratio of the present value of a
customer's estimated lifetime electricity cost savings from energy efficiency
measures to the present value of the installation costs, inclusive of any
incidental repairs, of those energy efficiency measures.
(51) Self-delivered program--A program
developed by a utility in an area in which customer choice is not offered that
provides incentives directly to customers. The utility may use internal or
external resources to design and administer the program.
(52) Spillover--Reductions in energy
consumption and/or demand caused by the presence of an energy efficiency
program, beyond the program-related gross savings of the participants and
without financial or technical assistance from the program. There can be
participant and/or non-participant spillover.
(53) Spillover rate--Estimate of energy
savings attributable to spillover expressed as a percent of savings installed
by participants through an energy efficiency program.
(54) Standard offer contract--A contract
between an energy efficiency service provider and a participating utility or
between a participating utility and a commercial customer specifying standard
payments based upon the amount of energy and peak demand savings achieved
through energy efficiency measures, the measurement and verification protocols,
and other terms and conditions, consistent with this section.
(55) Standard offer program--A program under
which a utility administers standard offer contracts between the utility and
energy efficiency service providers.
(56) Technical reference manual (TRM)--A
resource document compiled by the commission's EM&V contractor that
includes information used in program planning and reporting of energy
efficiency programs. It can include savings values for measures, engineering
algorithms to calculate savings, impact factors to be applied to calculated
savings (e.g., net-to-gross values), protocols, source documentation, specified
assumptions, and other relevant material to support the calculation of measure
and program savings.
(57)
Verification--An independent assessment that a program has been implemented in
accordance with the program design. The objectives of measure installation
verification are to confirm the installation rate, that the installation meets
reasonable quality standards, and that the measures are operating correctly and
have the potential to generate the predicted savings. Verification activities
are generally conducted during on-site surveys of a sample of projects. Project
site inspections, participant phone and mail surveys and/or implementer and
participant documentation review are typical activities associated with
verification. Verification is also a subset of evaluation.
(d) Cost-effectiveness standard. An energy efficiency program is deemed to be cost-effective if the cost of the program to the utility is less than or equal to the benefits of the program. Utilities are encouraged to achieve demand reduction and energy savings through a portfolio of cost-effective programs that exceed each utility's energy efficiency goals while staying within the cost caps established in § 25.182(d)(7) of this title.
(1) The cost of a program
includes the cost of incentives, EM&V contractor costs, any shareholder
bonus awarded to the utility, and actual or allocated research and development
and administrative costs. The benefits of the program consist of the value of
the demand reductions and energy savings, measured in accordance with the
avoided costs prescribed in this subsection. The present value of the program
benefits shall be calculated over the projected life of the measures installed
or implemented under the program.
(2) The avoided cost of capacity shall be
established in accordance with this paragraph.
(A) By November 1 of each year, commission
staff shall file the avoided cost of capacity for the upcoming year, including
supporting data, in the commission's central records under the control number
for the energy efficiency implementation project.
(i) Staff shall calculate the avoided cost of
capacity from the base overnight cost using the lower of a new conventional
combustion turbine or a new advanced combustion turbine, as reported by the
United States Department of Energy's Energy Information Administration's (EIA)
Cost and Performance Characteristics of New Central Station Electricity
Generating Technologies associated with EIA's Annual Energy Outlook. If EIA
cost data that reflects current conditions in the industry does not exist,
staff may establish an avoided cost of capacity using another data
source.
(ii) If the EIA base
overnight cost of a new conventional or an advanced combustion turbine,
whichever is lower, is less than $700 per kW, the avoided cost of capacity
shall be $80 per kW-year. If the base overnight cost of a new conventional or
advanced combustion turbine, whichever is lower, is at or between $700 and
$1,000 per kW, the avoided cost of capacity shall be $100 per kW-year. If the
base overnight cost of a new conventional or advanced combustion turbine,
whichever is lower, is greater than $1,000 per kW, the avoided cost of capacity
shall be $120 per kW-year.
(iii)
The avoided cost of capacity calculated by staff may be challenged only by the
filing of a petition within 45 days of the date the avoided cost of capacity is
filed in the commission's central records under the control number for the
energy efficiency implementation project described by paragraph (2)(A) of this
subsection. The petition must clearly describe the reasons commission's staff's
avoided cost calculation is incorrect, include supporting data and
calculations, and state the relief sought.
(B) A utility in an area in which customer
choice is not offered may petition the commission for authorization to use an
avoided cost of capacity different from the avoided cost determined according
to subparagraph (A) of this paragraph by filing a petition no later than 45
days after the date the avoided cost of capacity calculated by staff is filed
in the commission's central records under the control number for the energy
efficiency implementation project described by paragraph (2)(A) of this
subsection. The petition must clearly describe the reasons a different avoided
cost should be used, include supporting data and calculations, and state the
relief sought. The avoided cost of capacity proposed by the utility shall be
based on a generating resource or purchase in the utility's resource
acquisition plan and the terms of the purchase or the cost of the resource
shall be disclosed in the filing.
(3) The avoided cost of energy shall be
established in accordance with this paragraph.
(A) By November 1 of each year, ERCOT shall
file the avoided cost of energy for the upcoming year for the ERCOT region, as
defined in §
25.5(48) of this
title (relating to Definitions), in the commission's central records under the
control number for the energy efficiency implementation project. ERCOT shall
calculate the avoided cost of energy by determining the load-weighted average
of the competitive load zone settlement point prices for the peak periods
covering the two previous winter and summer peaks. The avoided cost of energy
calculated by ERCOT may be challenged only by the filing of a petition within
45 days of the date the avoided cost of capacity is filed by ERCOT in the
commission's central records under the control number for the energy efficiency
implementation project described by paragraph (2)(A) of this subsection. The
petition must clearly describe the reasons ERCOT's avoided cost of energy
calculation is incorrect, include supporting data and calculations, and state
the relief sought.
(B) A utility in
an area in which customer choice is not offered may petition the commission for
authorization to use an avoided cost of energy other than that otherwise
determined according to this paragraph. The avoided cost of energy may be based
on peak period energy prices in an energy market operated by a regional
transmission organization if the utility participates in that market and the
prices are reported publicly. If the utility does not participate in such a
market, the avoided cost of energy may be based on the expected heat rate of
the gas-turbine generating technology specified in this subsection, multiplied
by a publicly reported cost of natural gas.
(e) Annual energy efficiency goals.
(1) An electric utility shall administer a
portfolio of energy efficiency programs to acquire, at a minimum, the
following:
(A) Beginning with the 2013 program
year, until the trigger described in subparagraph (B) of this paragraph is
reached, the utility shall acquire a 30% reduction of its annual growth in
demand of residential and commercial customers.
(B) If the demand reduction goal to be
acquired by a utility under subparagraph (A) of this paragraph is equivalent to
at least four-tenths of 1% of its summer weather-adjusted peak demand for the
combined residential and commercial customers for the previous program year,
the utility shall meet the energy efficiency goal described in subparagraph (C)
of this paragraph for each subsequent program year.
(C) Once the trigger described in
subparagraph (B) of this paragraph is reached, the utility shall acquire
four-tenths of 1% of its summer weather-adjusted peak demand for the combined
residential and commercial customers for the previous program year.
(D) Except as adjusted in accordance with
subsection (u) of this section, a utility's demand reduction goal in any year
shall not be lower than its goal for the prior year, unless the commission
establishes a goal for a utility under paragraph (2) of this
subsection.
(2) The
commission may establish for a utility a lower goal than the goal specified in
paragraph (1) of this subsection, a higher administrative spending cap than the
cap specified under subsection (g) of this section, or an EECRF greater than
the cap specified in §
25.182(d)(7) of
this title, if the utility demonstrates that compliance with that goal,
administrative spending cap, or EECRF cost cap is not reasonably possible and
that good cause supports the lower goal, higher administrative spending cap, or
higher EECRF cost cap. To be eligible for a lower goal, higher administrative
spending cap, or a higher EECRF cost cap, the utility must request a good cause
exception as part of its EECRF application under §
25.182 of this title. If approved,
the good cause exception is limited to the program year associated with the
EECRF application.
(3) Each
utility's demand-reduction goal shall be calculated as follows:
(A) Each year's historical demand for
residential and commercial customers shall be adjusted for weather
fluctuations, using weather data for the most recent ten years. The utility's
growth in residential and commercial demand is based on the average growth in
retail load in the Texas portion of the utility's service area, measured at the
utility's annual system peak. The utility shall calculate the average growth
rate for the prior five years.
(B)
The demand goal for energy-efficiency savings for a year under paragraph (1)(A)
of this subsection is calculated by applying the percentage goal to the average
growth in peak demand, calculated in accordance with subparagraph (A) of this
paragraph. The annual demand goal for energy efficiency savings under paragraph
(1)(C) of this subsection is calculated by applying the percentage goal to the
utility's summer weather-adjusted five-year average peak demand for the
combined residential and commercial customers. This annual peak demand goal at
the source is then converted to an equivalent goal at the meter by applying
reasonable line loss factors.
(C) A
utility may submit for commission approval an alternative method to calculate
its growth in demand, for good cause.
(D) If a utility's prior five-year average
load growth, calculated under subparagraph (A) of this paragraph, is negative,
the utility shall use the demand reduction goal calculated using the
alternative method approved by the commission beginning with the 2013 program
year or, if the commission has not approved an alternative method, the utility
shall use the previous year's demand reduction goal.
(E) A utility shall not claim savings
obtained from energy efficiency measures funded through settlement orders or
count towards the bonus calculation any savings obtained from grant incentives
that have been awarded directly to the utility for energy efficiency
programs.
(F) Savings achieved
through programs for hard-to-reach customers shall be no less than 5.0% of the
utility's total demand reduction goal.
(G) Utilities may apply peak savings on a per
project basis to summer or winter peak, but not to both summer and winter
peaks.
(4) An electric
utility shall administer a portfolio of energy efficiency programs designed to
meet an energy savings goal calculated from its demand savings goal, using a
20% conservation load factor.
(5)
Electric utilities shall administer a portfolio of energy efficiency programs
to effectively and efficiently achieve the goals set out in this section.
(A) Incentive payments may be made under
standard offer contracts, market transformation contracts, or as part of a
self-delivered program for energy savings and demand reductions. Each electric
utility shall establish standard incentive payments to achieve the objectives
of this section.
(B) Projects or
measures under a standard offer, market transformation, or self-delivered
program are not eligible for incentive payments or compensation if:
(i) A project would achieve demand or energy
reduction by eliminating an existing function, shutting down a facility or
operation, or would result in building vacancies or the re-location of existing
operations to a location outside of the area served by the utility conducting
the program, except for an appliance recycling program consistent with this
section.
(ii) A measure would be
adopted even in the absence of the energy efficiency service provider's
proposed energy efficiency project, except in special cases, such as
hard-to-reach and weatherization programs, or where free riders are accounted
for using a net to gross adjustment of the avoided costs, or another method
that achieves the same result.
(iii) A project results in negative
environmental or health effects, including effects that result from improper
disposal of equipment and materials.
(C) Ineligibility under subparagraph (B) of
this paragraph does not apply to standard offer, market transformation, and
self-delivered programs aimed at energy code adoption, implementation,
compliance, and enforcement under subsection (k) of this section, nor does it
preclude standard offer, market transformation, or self-delivered programs
promoting energy efficiency measures also required by energy codes to the
degree such codes do not achieve full compliance rates.
(D) A utility in an area in which customer
choice is not offered may achieve the goals of paragraphs (1) and (2) of this
subsection by:
(i) providing rebate or
incentive funds directly to eligible residential and commercial customers for
programs implemented under this section; or
(ii) developing, subject to commission
approval, new programs other than standard offer programs and market
transformation programs, to the extent that the new programs satisfy the same
cost-effectiveness standard as standard offer programs and market
transformation programs using the process outlined in subsection (q) of this
section.
(E) For a
utility in an area in which customer choice is offered, the utility may achieve
the goal of this section in rural areas by providing rebate or incentive funds
directly to customers after demonstrating to the commission in a contested case
hearing that the goal requirement cannot be met through the implementation of
programs by retail electric providers or energy efficiency service providers in
the rural areas.
(f) Incentive payments. The incentive payments for each customer class shall not exceed 100% of avoided cost, as determined in accordance with this section. The incentive payments shall be set by each utility with the objective of achieving its energy and demand savings goals at the lowest reasonable cost per program. Different incentive levels may be established for areas that have historically been underserved by the utility's energy efficiency programs or for other appropriate reasons. Utilities may adjust incentive payments during the program year, but such adjustments must be clearly publicized in the materials used by the utility to set out the program rules and describe the programs to participating energy efficiency service providers.
(g) Utility administration. The cost of administration in a program year shall not exceed 15% of a utility's total program costs for that program year. The cost of research and development in a program year shall not exceed 10% of a utility's total program costs for that program year. The cumulative cost of administration and research and development shall not exceed 20% of a utility's total program costs, unless a good cause exception filed under subsection (e)(2) of this section is granted. Any portion of these costs that is not directly assignable to a specific program shall be allocated among the programs in proportion to the program incentive costs. Any bonus awarded by the commission shall not be included in program costs for the purpose of applying these limits.
(1) Administrative costs
include all reasonable and necessary costs incurred by a utility in carrying
out its responsibilities under this section, including:
(A) conducting informational activities
designed to explain the standard offer programs and market transformation
programs to energy efficiency service providers, retail electric providers, and
vendors;
(B) for a utility offering
self-delivered programs, internal utility costs to conduct outreach activities
to customers and energy efficiency service providers will be considered
administration;
(C) providing
informational programs to improve customer awareness of energy efficiency
programs and measures;
(D)
reviewing and selecting energy efficiency programs in accordance with this
section;
(E) providing regular and
special reports to the commission, including reports of energy and demand
savings;
(F) a utility's costs for
an EECRF proceeding conducted under §
25.182(d) of
this title;
(G) the costs paid by a
utility pursuant to PURA §33.023(b) for an EECRF proceeding conducted
under §
25.182(d) of
this title; however, these costs are not included in the administrative caps
applied in this paragraph; and
(H)
any other activities that are necessary and appropriate for successful program
implementation.
(2) A
utility shall adopt measures to foster competition among energy efficiency
service providers for standard offer, market transformation, and self-delivered
programs, such as limiting the number of projects or level of incentives that a
single energy efficiency service provider and its affiliates is eligible for
and establishing funding set-asides for small projects.
(3) A utility may establish funding
set-asides or other program rules to foster participation in energy efficiency
programs by municipalities and other governmental entities.
(4) Electric utilities offering standard
offer, market transformation, and self-delivered programs shall use
standardized forms, procedures, and program templates. The electric utility
shall file any standardized materials, or any change to it, with the commission
at least 60 days prior to its use. In filing such materials, the utility shall
provide an explanation of changes from the version of the materials that was
previously used. For standard offer, market transformation, and self-delivered
programs, the utility shall provide relevant documents to retail electric
providers and energy efficiency service providers and work collaboratively with
them when it changes program documents, to the extent that such changes are not
considered in the energy efficiency implementation project described in
subsection (q) of this section.
(5)
Each electric utility in an area in which customer choice is offered shall
conduct programs to encourage and facilitate the participation of retail
electric providers and energy efficiency service providers in the delivery of
efficiency and demand response programs, including:
(A) Coordinating program rules, contracts,
and incentives to facilitate the statewide marketing and delivery of the same
or similar programs by retail electric providers;
(B) Setting aside amounts for programs to be
delivered to customers by retail electric providers and establishing program
rules and schedules that will give retail electric providers sufficient time to
plan, advertise, and conduct energy efficiency programs, while preserving the
utility's ability to meet the goals in this section; and
(C) Working with retail electric providers
and energy efficiency service providers to evaluate the demand reductions and
energy savings resulting from time-of-use prices; home-area network devices,
such as in-home displays; and other programs facilitated by advanced meters to
determine the demand and energy savings from such programs.
(h) Standard offer programs. A utility's standard offer program shall be implemented through program rules and standard offer contracts that are consistent with this section. Standard offer contracts will be available to any energy efficiency service provider that satisfies the contract requirements prescribed by the utility under this section and demonstrates that it is capable of managing energy efficiency projects under an electric utility's energy efficiency program.
(i) Market transformation programs. Market transformation programs are strategic efforts, including, but not limited to, incentives and education designed to reduce market barriers for energy efficient technologies and practices. Market transformation programs may be designed to obtain energy savings or peak demand reductions beyond savings that are reasonably expected to be achieved as a result of current compliance levels with existing building codes applicable to new buildings and equipment efficiency standards or standard offer programs. Market transformation programs may also be specifically designed to express support for early adoption, implementation, and enforcement of the most recent version of the International Energy Conservation Code for residential or commercial buildings by local jurisdictions, express support for more effective implementation and enforcement of the state energy code and compliance with the state energy code, and encourage utilization of the types of building components, products, and services required to comply with such energy codes. The existence of federal, state, or local governmental funding for, or encouragement to utilize, the types of building components, products, and services required to comply with such energy codes does not prevent utilities from offering programs to supplement governmental spending and encouragement. Utilities should cooperate with the retail electric providers, and, where possible, leverage existing industry-recognized programs that have the potential to reduce demand and energy consumption in Texas and consider statewide administration where appropriate. Market transformation programs may operate over a period of more than one year and may demonstrate cost-effectiveness over a period longer than one year.
(j) Self-delivered programs. A utility may use internal or external resources to design, administer, and deliver self-delivered programs. The programs shall be tailored to the unique characteristics of the utility's service area in order to attract customer and energy efficiency service provider participation. The programs shall meet the same cost effectiveness requirements as standard offer and market transformation programs.
(k) Requirements for standard offer, market transformation, and self-delivered programs. A utility's standard offer, market transformation, and self-delivered programs shall meet the requirements of this subsection. A utility may conduct information and advertising campaigns to foster participation in standard offer, market transformation, and self-delivered programs.
(1) Standard offer, market transformation,
and self-delivered programs:
(A) shall
describe the eligible customer classes and allocate funding among the classes
on an equitable basis;
(B) may
offer standard incentive payments and specify a schedule of payments that are
sufficient to meet the goals of the program, which shall be consistent with
this section, or any revised payment formula adopted by the commission. The
incentive payments may include both payments for energy and demand savings, as
appropriate;
(C) shall not permit
the provision of any product, service, pricing benefit, or alternative terms or
conditions to be conditioned upon the purchase of any other good or service
from the utility, except that only customers taking transmission and
distribution services from a utility can participate in its energy efficiency
programs;
(D) shall provide for a
complaint process that allows:
(i) an energy
efficiency service provider to file a complaint with the commission against a
utility; and
(ii) a customer to
file a complaint with the utility against an energy efficiency service
provider;
(E) may permit
the use of distributed renewable generation, geothermal, heat pump, solar water
heater and combined heat and power technologies, involving installations of ten
megawatts or less;
(F) may factor
in the estimated level of enforcement and compliance with existing energy codes
in determining energy and peak demand savings; and
(G) may require energy efficiency service
providers to provide the following:
(i) a
description of how the value of any incentive will be passed on to
customers;
(ii) evidence of
experience and good credit rating;
(iii) a list of references;
(iv) all applicable licenses required under
state law and local building codes;
(v) evidence of all building permits required
by governing jurisdictions; and
(vi) evidence of all necessary
insurance.
(2)
Standard offer and self-delivered programs:
(A) shall require energy efficiency service
providers to identify peak demand and energy savings for each project in the
proposals they submit to the utility;
(B) shall be neutral with respect to specific
technologies, equipment, or fuels. Energy efficiency projects may lead to
switching from electricity to another energy source, provided that the energy
efficiency project results in overall lower energy costs, lower energy
consumption, and the installation of high efficiency equipment. Utilities may
not pay incentives for a customer to switch from gas appliances to electric
appliances except in connection with the installation of high efficiency
combined heating and air conditioning systems;
(C) shall require that all projects result in
a reduction in purchased energy consumption, or peak demand, or a reduction in
energy costs for the end-use customer;
(D) shall encourage comprehensive projects
incorporating more than one energy efficiency measure;
(E) shall be limited to projects that result
in consistent and predictable energy or peak demand savings over an appropriate
period of time based on the life of the measure; and
(F) may permit a utility to use poor
performance, including customer complaints, as a criterion to limit or
disqualify an energy efficiency service provider or its affiliate from
participating in a program.
(3) A market transformation program shall
identify:
(A) program goals;
(B) market barriers the program is designed
to overcome;
(C) key intervention
strategies for overcoming those barriers;
(D) estimated costs and projected energy and
capacity savings;
(E) a baseline
study that is appropriate in time and geographic region. In establishing a
baseline, the study shall consider the level of regional implementation and
enforcement of any applicable energy code;
(F) program implementation timeline and
milestones;
(G) a description of
how the program will achieve the transition from extensive market intervention
activities toward a largely self-sustaining market;
(H) a method for measuring and verifying
savings; and
(I) the period over
which savings shall be considered to accrue, including a projected date by
which the market will be sufficiently transformed so that the program should be
discontinued.
(4) A
market transformation program shall be designed to achieve energy or peak
demand savings, or both, and lasting changes in the way energy efficient goods
or services are distributed, purchased, installed, or used over a defined
period of time. A utility shall use fair competitive procedures to select
energy efficiency service providers to conduct a market transformation program,
and shall include in its annual report the justification for the selection of
an energy efficiency service provider to conduct a market transformation
program on a sole-source basis.
(5)
A load-control standard-offer program shall not permit an energy efficiency
service provider to receive incentives under the program for the same demand
reduction benefit for which it is compensated under a capacity-based demand
response program conducted by an independent organization, independent system
operator, or regional transmission operator. The qualified scheduling entity
representing an energy efficiency service provider is not prohibited from
receiving revenues from energy sold in ERCOT markets in addition to any
incentive for demand reduction offered under a utility load-control standard
offer program.
(6) Utilities
offering load management programs shall work with ERCOT and energy efficiency
service providers to identify eligible loads and shall integrate such loads
into the ERCOT markets to the extent feasible. Such integration shall not
preclude the continued operation of utility load management programs that
cannot be feasibly integrated into the ERCOT markets or that continue to
provide separate and distinct benefits.
(l) Energy efficiency plans and reports (EEPR). Each electric utility shall file by April 1 of each year an energy efficiency plan and report in a project annually designated for this purpose, as described in this subsection and § 25.183(d) of this title. The plan and report shall be filed as a searchable pdf document.
(1) Each electric utility's energy efficiency
plan and report shall describe how the utility intends to achieve the goals set
forth in this section and comply with the other requirements of this section.
The plan and report shall be based on program years. The plan and report shall
propose an annual budget sufficient to reach the goals specified in this
section.
(2) Each electric
utility's plan and report shall include:
(A)
the utility's total actual and weather-adjusted peak demand and actual and
weather-adjusted peak demand for residential and commercial customers for the
previous five years, measured at the source;
(B) the demand goal calculated in accordance
with this section for the current year and the following year, including
documentation of the demand, weather adjustments, and the calculation of the
goal;
(C) the utility's customers'
total actual and weather-adjusted energy consumption and actual and
weather-adjusted energy consumption for residential and commercial customers
for the previous five years;
(D)
the energy goal calculated in accordance with this section, including
documentation of the energy consumption, weather adjustments, and the
calculation of the goal;
(E) a
description of existing energy efficiency programs and an explanation of the
extent to which these programs will be used to meet the utility's energy
efficiency goals;
(F) a description
of each of the utility's energy efficiency programs that were not included in
the previous year's plan, including measurement and verification plans if
appropriate, and any baseline studies and research reports or analyses
supporting the value of the new programs;
(G) an estimate of the energy and peak demand
savings to be obtained through each separate energy efficiency
program;
(H) a description of the
customer classes targeted by the utility's energy efficiency programs,
specifying the size of the hard-to-reach, residential, and commercial classes,
and the methodology used for estimating the size of each customer
class;
(I) the proposed annual
budget required to implement the utility's energy efficiency programs, broken
out by program for each customer class, including hard-to-reach customers, and
any set-asides or budget restrictions adopted or proposed in accordance with
this section. The proposed budget shall detail the incentive payments and
utility administrative costs, including specific items for research and
information and outreach to energy efficiency service providers, and other
major administrative costs, and the basis for estimating the proposed
expenditures;
(J) a discussion of
the types of informational activities the utility plans to use to encourage
participation by customers, energy efficiency service providers, and retail
electric providers to participate in energy efficiency programs, including the
manner in which the utility will provide notice of energy efficiency programs,
and any other facts that may be considered when evaluating a program;
(K) the utility's performance in achieving
its energy goal and demand goal for the prior five years, as reported in annual
energy efficiency reports filed in accordance with this section;
(L) a comparison of projected savings (energy
and demand), reported savings, and verified savings for each of the utility's
energy efficiency programs for the prior two years;
(M) a description of the results of any
market transformation program, including a comparison of the baseline and
actual results and any adjustments to the milestones for a market
transformation program;
(N) a
description of self-delivered programs;
(O) expenditures for the prior five years for
energy and demand incentive payments and program administration, by program and
customer class;
(P) funds that were
committed but not spent during the prior year, by program;
(Q) a comparison of actual and budgeted
program costs, including an explanation of any increase or decreases of more
than 10% in the cost of a program;
(R) information relating to energy and demand
savings achieved and the number of customers served by each program by customer
class;
(S) the utility's most
recent EECRF, the revenue collected through the EECRF, the utility's forecasted
annual energy efficiency program expenditures in excess of the actual energy
efficiency revenues collected from base rates as described in §
25.182(d)(2) of
this title, and the control number under which the most recent EECRF was
established;
(T) the amount of any
over- or under-recovery of energy efficiency program costs whether collected
through base rates or the EECRF;
(U) a list of any counties that in the prior
year were under-served by the energy efficiency program;
(V) a description of new or discontinued
programs, including pilot programs that are planned to be continued as full
programs. For programs that are to be introduced or pilot programs that are to
be continued as full programs, the description shall include the budget and
projected demand and energy savings;
(W) a link to the program manuals for the
current program year; and
(X) the
calculations supporting the adjustments to restate the demand goal from the
source to the meter and to restate the energy efficiency savings from the meter
to the source.
(m) Review of programs. Commission staff may initiate a proceeding to review a utility's energy efficiency programs. In addition, an interested entity may request that the commission initiate a proceeding to review a utility's energy efficiency programs.
(n) Inspection, measurement and verification. Each standard offer, market transformation, and self-delivered program shall include use of an industry-accepted evaluation and/or measurement and verification protocol, such as the International Performance Measurement and Verification Protocol or a protocol approved by the commission, to document and verify energy and peak demand savings to ensure that the goals of this section are achieved. A utility shall not provide an energy efficiency service provider final compensation until the provider establishes that the work is complete and evaluation and/or measurement and verification in accordance with the protocol verifies that the savings will be achieved. However, a utility may provide an energy efficiency service provider that offers behavioral programs incremental compensation as work is performed. If inspection of one or more measures is a part of the protocol, a utility shall not provide an energy efficiency service provider final compensation until the utility has conducted its inspection on at least a sample of measures and the inspections confirm that the work has been done. A utility shall provide inspection reports to commission staff within 20 days of staff's request.
(1) The
energy efficiency service provider, or for self-delivered programs, the
utility, is responsible for the determination and documentation of energy and
peak demand savings using the approved evaluation and/or measurement and
verification protocol, and may utilize the services of an independent third
party for such purposes.
(2)
Commission-approved deemed energy and peak demand savings may be used in lieu
of the energy efficiency service provider's measurement and verification, where
applicable. The deemed savings approved by the commission before December 31,
2007 are continued in effect, unless superseded by commission action.
(3) Where installed measures are employed, an
energy efficiency service provider shall verify that the measures contracted
for were installed before final payment is made to the energy efficiency
service provider, by obtaining the customer's signature certifying that the
measures were installed, or by other reasonably reliable means approved by the
utility.
(4) For projects involving
over 30 installations, a statistically significant sample of installations will
be subject to on-site inspection in accordance with the protocol for the
project to verify that measures are installed and capable of performing their
intended function. Inspection shall occur within 30 days of notification of
measure installation.
(5) Projects
of less than 30 installations may be aggregated and a statistically significant
sample of the aggregate installations will be subject to on-site inspection in
accordance with the protocol for the projects to ensure that measures are
installed and capable of performing their intended function. Inspection shall
occur within 30 days of notification of measure installation.
(6) Where installed measures are employed,
the sample size for on-site inspections may be adjusted for an energy
efficiency service provider under a particular contract, based on the results
of prior inspections.
(o) Evaluation, measurement, and verification (EM&V). The following defines the evaluation, measurement, and verification (EM&V) framework. The goal of this framework is to ensure that the programs are evaluated, measured, and verified using a consistent process that allows for accurate estimation of energy and demand impacts.
(1) EM&V
objectives include:
(A) Documenting the
impacts of the utilities' individual energy efficiency and load management
portfolios, comparing their performance with established goals, and determining
cost-effectiveness;
(B) Providing
feedback for the commission, commission staff, utilities, and other
stakeholders on program portfolio performance; and
(C) Providing input into the utilities' and
ERCOT's planning activities.
(2) The principles that guide the EM&V
activities in meeting the primary EM&V objectives are:
(A) Evaluators follow ethical
guidelines.
(B) Important and
relevant assumptions used by program planners and administrators are reviewed
as part of the EM&V efforts.
(C) All important and relevant EM&V
assumptions and calculations are documented and the reliability of results is
indicated in evaluation reports.
(D) The majority of evaluation expenditures
and efforts are in areas of greatest importance or uncertainty.
(3) The commission shall select an
entity to act as the commission's EM&V contractor and conduct evaluation
activities. The EM&V contractor shall operate under the commission's
supervision and oversight, and the EM&V contractor shall offer independent
analysis to the commission in order to assist in making decisions in the public
interest.
(A) Under the oversight of the
commission staff and with the assistance of utilities and other parties, the
EM&V contractor will evaluate specific programs and the portfolio of
programs for each utility.
(B) The
EM&V contractor shall have the authority to request data it considers
necessary to fulfill its evaluation, measurements, and verification
responsibilities from the utilities. A utility shall make good faith efforts to
provide complete, accurate, and timely responses to all EM&V contractor
requests for documents, data, information and other materials. The commission
may on its own volition or upon recommendation by staff require that a utility
provide the EM&V contractor with specific information.
(4) Evaluation activities will be conducted
by the EM&V contractor to meet the evaluation objectives defined in this
section. Activities shall include, but are not limited to:
(A) Providing appropriate planning
documents.
(B) Impact evaluations
to determine and document appropriate metrics for each utility's individual
evaluated programs and portfolio of all programs, annual portfolio evaluation
reports, and additional reports and services as defined by commission staff to
meet the EM&V objectives.
(C)
Preparation of a statewide technical reference manual (TRM), including updates
to such manual as defined in this subsection.
(5) The impact evaluation activities may
include the use of one or more evaluation approaches. Evaluation activities may
also include, or just include, verification activities on a census or sample of
projects implemented by the utilities. Evaluations may also include the use of
due-diligence on utility-provided documentation as well as surveys of program
participants, non-participants, contractors, vendors, and other market
actors.
(6) The following apply to
the development of a statewide TRM by the EM&V contractor.
(A) The EM&V contractor shall use
existing Texas, or other state, deemed savings manual(s), protocols, and the
work papers used to develop the values in the manual(s), as a foundation for
developing the TRM. The TRM shall include applicability requirements for each
deemed savings value or deemed savings calculation. The TRM may also include
standardized EM&V protocols for determining and/or verifying energy and
demand savings for particular measures or programs. Utilities may apply TRM
deemed savings values or deemed savings calculations to a measure or program if
the applicability criteria are met.
(B) The TRM shall be reviewed by the EM&V
contractor at least annually, under a schedule determined by commission staff,
with the intention of preparing an updated TRM, if needed. In addition, any
utility or other stakeholder may request additions to or modifications to the
TRM at any time with the provision of documentation for the basis of such an
addition or modification. At the discretion of commission staff, the EM&V
contractor may review such documentation to prepare a recommendation with
respect to the addition or modification.
(C) Commission staff shall approve any
updated TRMs through the energy efficiency implementation project. The approval
process for any TRM additions or modifications, not made during the regular
review schedule determined by commission staff, shall include a review by
commission staff to determine if an addition or modification is appropriate
before an annual update. TRM changes approved by staff may be challenged only
by the filing of a petition within 45 days of the date that staff's approval is
filed in the commission's central records under the control number for the
energy efficiency implementation project described by subsection (d)(2)(A) of
this section. The petition must clearly describe the reasons commission staff
should not have approved the TRM changes, include supporting data and
calculations, and state the relief sought.
(D) Any changes to the TRM shall be applied
prospectively to programs offered in the appropriate program year.
(E) The TRM shall be publicly
available.
(F) Utilities shall
utilize the values contained in the TRM, unless the commission indicates
otherwise.
(7) The
utilities shall prepare projected savings estimates and claimed savings
estimates. The utilities shall conduct their own EM&V activities for
purposes such as confirming any incentive payments to customers or contractors
and preparing documentation for internal and external reporting, including
providing documentation to the EM&V contractor. The EM&V contractor
shall prepare evaluated savings for preparation of its evaluation reports and a
realization rate comparing evaluated savings with projected savings estimates
and/or claimed savings estimates.
(8) Baselines for preparation of TRM deemed
savings values or deemed savings calculations or for other evaluation
activities shall be defined by the EM&V contractor and commission staff
shall review and approve them. When common practice baselines are defined for
determining gross energy and/or demand savings for a measure or program, common
practice may be documented by market studies. Baselines shall be defined by
measure category as follows (deviations from these specifications may be made
with justification and approval of commission staff):
(A) Baseline is existing conditions for the
estimated remaining lifetime of existing equipment for early replacement of
functional equipment still within its current useful life. Baseline is
applicable code, standard or common practice for remaining lifetime of the
measure past the estimated remaining lifetime of existing equipment;
(B) Baseline is applicable code, standard or
common practice for replacement of functional equipment beyond its current
useful life;
(C) Baseline is
applicable code, standard or common practice for unplanned replacements of
failed equipment; and
(D) Baseline
is applicable code, standard or common practice for new construction or major
tenant improvements.
(9)
Relevant recommendations of the EM&V contractor related to program design
and reporting should be addressed in the Energy Efficiency Implementation
Project (EEIP) and considered for implementation in future program years. The
commission may require a utility to implement the EM&V contractor's
recommendations in a future program year.
(10) The utilities shall be assigned the
EM&V costs in proportion to their annual program costs and shall pay the
invoices approved by the commission. The commission shall at least biennially
review the EM&V contractor's costs and establish a budget for its services
sufficient to pay for those services that it determines are economic and
beneficial to be performed.
(A) The funding of
the EM&V contractor shall be sufficient to ensure the selection of an
EM&V contractor in accordance with the scope of EM&V activities
outlined in this subsection.
(B)
EM&V costs shall be itemized in the utilities' annual reports to the
commission as a separate line item. The EM&V costs shall not count against
the utility's cost caps or administration spending caps.
(11) For the purpose of analysis, the utility
shall grant the EM&V contractor access to data maintained in the utilities'
data tracking systems, including, but not limited to, the following proprietary
customer information: customer identifying information, individual customer
contracts, and load and usage data in accordance with §
25.272(g)(1)(A)
of this title (relating to Code of Conduct for Electric Utilities and Their
Affiliates). Such information shall be treated as confidential information.
(A) The utility shall maintain records for
three years that include the date, time, and nature of proprietary customer
information released to the EM&V contractor.
(B) The EM&V contractor shall aggregate
data in such a way as to protect customer, retail electric provider, and energy
efficiency service provider proprietary information in any non-confidential
reports or filings the EM&V contractor prepares.
(C) The EM&V contractor shall not utilize
data provided or received under commission authority for any purposes outside
the authorized scope of work the EM&V contractor performs for the
commission.
(D) The EM&V
contractor providing services under this section shall not release any
information it receives related to the work performed unless directed to do so
by the commission.
(p) Targeted low-income energy efficiency program. Each unbundled transmission and distribution utility shall include in its energy efficiency plan a targeted low-income energy efficiency program. A utility in an area in which customer choice is not offered may include in its energy efficiency plan a targeted low-income energy efficiency program that utilizes the cost-effectiveness methodology provided in paragraph (2) of this subsection. Savings achieved by the program shall count toward the utility's energy efficiency goal.
(1) Each utility
shall ensure that annual expenditures for the targeted low-income energy
efficiency program are not less than 10% of the utility's energy efficiency
budget for the program year.
(2)
The utility's targeted low-income program shall incorporate a whole-house
assessment that will evaluate all applicable energy efficiency measures for
which there are commission-approved deemed savings. The cost-effectiveness of
measures eligible to be installed and the overall program shall be evaluated
using the Savings-to-Investment ratio (SIR).
(3) Any funds that are not obligated after
July of a program year may be made available for use in the hard-to-reach
program.
(q) Energy Efficiency Implementation Project - EEIP. The commission shall use the EEIP to develop best practices in standard offer market transformation, self-directed, pilot, or other programs, modifications to programs, standardized forms and procedures, protocols, deemed savings estimates, program templates, and the overall direction of the energy efficiency program established by this section. Utilities shall provide timely responses to questions posed by other participants relevant to the tasks of the EEIP. Any recommendations from the EEIP process shall relate to future years as described in this subsection.
(1) The following functions may also be
undertaken in the EEIP:
(A) development,
discussion, and review of new statewide standard offer programs;
(B) identification, discussion, design, and
review of new market transformation programs;
(C) determination of measures for which
deemed savings are appropriate and participation in the development of deemed
savings estimates for those measures;
(D) review of and recommendations on the
commission EM&V contractor's reports;
(E) review of and recommendations on
incentive payment levels and their adequacy to induce the desired level of
participation by energy efficiency service providers and customers;
(F) review of and recommendations on a
utility's annual energy efficiency plans and reports;
(G) utility program portfolios and proposed
energy efficiency spending levels for future program years;
(H) periodic reviews of the
cost-effectiveness methodology; and
(I) other activities as identified by
commission staff.
(2) The
EEIP projects shall be conducted by commission staff. The commission's EM&V
contractor's reports shall be filed in the project at a date determined by
commission staff.
(3) A utility
that intends to launch a program that is substantially different from other
programs previously implemented by any utility affected by this section shall
file a program template and shall provide notice of such to EEIP participants.
Notice to EEIP participants need not be provided if a program description or
program template for the new program is provided through the utility's annual
energy efficiency report. Following the first year in which a program was
implemented, the utility shall include the program results in the utility's
annual energy efficiency report.
(4) Participants in the EEIP may submit
comments and reply comments in the EEIP on dates established by commission
staff.
(5) Any new programs or
program redesigns shall be submitted to the commission in a petition in a
separate proceeding. The approved changes shall be available for use in the
utilities' next EEPR and EECRF filings. If the changes are not approved by the
commission by November 1 in a particular year, the first time that the changes
shall be available for use is the second EEPR and EECRF filings made after
commission approval.
(6) Any
interested entity that participates in the EEIP may file a petition to the
commission for consideration regarding changes to programs.
(r) Retail providers. Each utility in an area in which customer choice is offered shall conduct outreach and information programs and otherwise use its best efforts to encourage and facilitate the involvement of retail electric providers as energy efficiency service companies in the delivery of efficiency and demand response programs.
(s) Customer protection. Each energy efficiency service provider that provides energy efficiency services to end-use customers under this section shall provide the disclosures and include the contractual provisions required by this subsection, except for commercial customers with a peak load exceeding 50 kW. Paragraph (1) of this subsection does not apply to behavioral energy efficiency programs that do not require a contract with a customer.
(1) Clear
disclosure to the customer shall be made of the following:
(A) the customer's right to a cooling-off
period of three business days, in which the contract may be canceled, if
applicable under law;
(B) the name,
telephone number, and street address of the energy efficiency service provider
and any subcontractor that will be performing services at the customer's home
or business;
(C) the fact that
incentives are made available to the energy efficiency services provider
through a program funded by utility customers, manufacturers or other entities
and the amount of any incentives provided by the utility;
(D) the amount of any incentives that will be
provided to the customer;
(E)
notice of provisions that will be included in the customer's contract,
including warranties;
(F) the fact
that the energy efficiency service provider must measure and report to the
utility the energy and peak demand savings from installed energy efficiency
measures;
(G) the liability
insurance to cover property damage carried by the energy efficiency service
provider and any subcontractor;
(H)
the financial arrangement between the energy efficiency service provider and
customer, including an explanation of the total customer payments, the total
expected interest charged, all possible penalties for non-payment, and whether
the customer's installment sales agreement may be sold;
(I) the fact that the energy efficiency
service provider is not part of or endorsed by the commission or the utility;
and
(J) a description of the
complaint procedure established by the utility under this section, and toll
free numbers for the Customer Protection Division of the Public Utility
Commission of Texas, and the Office of Attorney General's Consumer Protection
Hotline.
(2) The energy
efficiency service provider's contract with the customer, where such a contract
is employed, shall include:
(A) work
activities, completion dates, and the terms and conditions that protect
residential customers in the event of non-performance by the energy efficiency
service provider;
(B) provisions
prohibiting the waiver of consumer protection statutes, performance warranties,
false claims of energy savings and reductions in energy costs;
(C) a disclosure notifying the customer that
consumption data may be disclosed to the EM&V contractor for evaluation
purposes; and
(D) a complaint
procedure to address performance issues by the energy efficiency service
provider or a subcontractor.
(3) When an energy efficiency service
provider completes the installation of measures for a customer, it shall
provide the customer an "All Bills Paid" affidavit to protect against claims of
subcontractors.
(t) Grandfathered programs. An electric utility that offered a load management standard offer program for industrial customers prior to May 1, 2007 shall continue to make the program available, at 2007 funding and participation levels, and may include additional customers in the program to maintain these funding and participation levels.
(u) Identification notice. An industrial customer taking electric service at distribution voltage may submit a notice identifying the distribution accounts for which it qualifies under subsection (c)(30) of this section. The identification notice shall be submitted directly to the customer's utility. An identification notice submitted under this section must be renewed every three years. Each identification notice must include the name of the industrial customer, a copy of the customer's Texas Sales and Use Tax Exemption Certification (under Tax Code § 151.317), a description of the industrial process taking place at the consuming facilities, and the customer's applicable account number(s) or ESID number(s). The identification notice is limited solely to the metered point of delivery of the industrial process taking place at the consuming facilities. The account number(s) or ESID number(s) identified by the industrial customer under this section shall not be charged for any costs associated with programs provided under this section, including any shareholder bonus awarded; nor shall the identified facilities be eligible to participate in utility-administered energy efficiency programs during the term. Notices shall be submitted not later than February 1 to be effective for the following program year. A utility's demand reduction goal shall be adjusted to remove any load that is lost as a result of this subsection.
(v) Administrative penalty. The commission may impose an administrative penalty or other sanction if the utility fails to meet a goal for energy efficiency under this section. Factors, to the extent they are outside of the utility's control, that may be considered in determining whether to impose a sanction for the utility's failure to meet the goal include:
(1) the
level of demand by retail electric providers and energy efficiency service
providers for program incentive funds made available by the utility through its
programs;
(2) changes in building
energy codes; and
(3) changes in
government-imposed appliance or equipment efficiency standards.
Disclaimer: These regulations may not be the most recent version. Texas may have more current or accurate information. We make no warranties or guarantees about the accuracy, completeness, or adequacy of the information contained on this site or the information linked to on the state site. Please check official sources.
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