Current through Register Vol. 49, No. 6, March 15, 2024
PURPOSE: This rule specifies the principles by which
potential demand-side resource options shall be developed and analyzed for cost
effectiveness, with the goal of achieving all cost-effective demand-side
savings. It also requires the selection of demand-side candidate resource
options that are passed on to integrated resource analysis in
4 CSR
240-22.060 and an assessment of their maximum
achievable potentials, technical potentials, and realistic achievable
potentials.
(1) The utility
shall identify a set of potential demand-side resources from which demand-side
candidate resource options will be identified for the purposes of developing
the alternative resource plans required by
4 CSR
240-22.060(3). A potential
demand-side resource consists of a demand-side program designed to deliver one
(1) or more energy efficiency and energy management measures or a demand-side
rate. The utility shall select the set of potential demand-side resources and
describe and document its selection-
(A) To
provide broad coverage of-
1. Appropriate
market segments within each major class;
2. All significant decision-makers, including
at least those who choose building design features and thermal integrity
levels, equipment and appliance efficiency levels, and utilization levels of
the energy-using capital stock; and
3. All major end uses, including at least the
end uses which are to be considered in the utility's load analysis as listed in
4 CSR
240-22.030(4)(A)
1.;
(B) To fulfill the
goal of achieving all cost-effective demand-side savings, the utility shall
design highly effective potential demand-side programs consistent with
subsection (1)(A) that broadly cover the full spectrum of cost-effective
end-use measures for all customer market segments;
(C) To include demand-side rates for all
customer market segments;
(D) To
consider and assess multiple designs for demand-side programs and demand-side
rates, selecting the optimal designs for implementation, and modifying them as
necessary to enhance their performance; and
(E) To include the effects of improved
technologies expected over the planning horizon to-
1. Reduce or manage energy use; or
2. Improve the delivery of demand-side
programs or demand-side rates.
(2) The utility shall conduct, describe, and
document market research studies, customer surveys, pilot demand-side programs,
pilot demand-side rates, test marketing programs, and other activities as
necessary to estimate the maximum achievable potential, technical potential,
and realistic achievable potential of potential demand-side resource options
for the utility and to develop the information necessary to design and
implement cost-effective demand-side programs and demand-side rates. These
research activities shall be designed to provide a solid foundation of
information applicable to the utility about how and by whom energy-related
decisions are made and about the most appropriate and cost-effective methods of
influencing these decisions in favor of greater long-run energy efficiency and
energy management impacts. The utility may compile existing data or adopt data
developed by other entities, including government agencies and other utilities,
as long as the utility verifies the applicability of the adopted data to its
service territory. The utility shall provide copies of completed market
research studies, pilot programs, pilot rates, test marketing programs, and
other studies as required by this rule and descriptions of those studies that
are planned or in progress and the scheduled completion dates.
(3) The utility shall develop potential
demand-side programs that are designed to deliver an appropriate selection of
end-use measures to each market segment. The utility shall describe and
document its potential demand-side program planning and design process which
shall include at least the following activities and elements:
(A) Review demand-side programs that have
been implemented by other utilities with similar characteristics and identify
programs that would be applicable for the utility;
(B) Identify, describe, and document market
segments that are numerous and diverse enough to provide relatively complete
coverage of the major classes and decision-makers identified in subsection
(1)(A) and that are specifically defined to reflect the primary market
imperfections that are common to the members of the market segment;
(C) Identify a comprehensive list of end-use
measures and demand-side programs considered by the utility and develop menus
of end-use measures for each demand-side program. The demand-side programs
shall be appropriate to the shared characteristics of each market segment. The
end-use measures shall reflect technological changes in end-uses that may be
reasonably anticipated to occur during the planning horizon;
(D) Assess how advancements in metering and
distribution technologies that may be reasonably anticipated to occur during
the planning horizon affect the ability to implement or deliver potential
demand-side programs;
(E) Design a
marketing plan and delivery process to present the menu of end-use measures to
the members of each market segment and to persuade decision-makers to implement
as many of these measures as may be appropriate to their situation. When
appropriate, consider multiple approaches such as rebates, financing, and
direct installations for the same menu of end-use measures;
(F) Evaluate, describe, and document the
feasibility, cost-reduction potential, and potential benefits of statewide
marketing and outreach programs, joint programs with natural gas utilities,
upstream market transformation programs, and other activities. In the event
that statewide marketing and outreach programs are preferred, the utilities
shall develop joint programs in consultation with the stakeholder
group;
(G) Estimate the
characteristics needed for the twenty (20)-year planning horizon to assess the
cost effectiveness of each potential demand-side program, including:
1. An assessment of the demand and energy
reduction impacts of each stand-alone end-use measure contained in each
potential demand-side program;
2.
An assessment of how the interactions between end-use measures, when bundled
with other end-use measures in the potential demand-side program, would affect
the stand-alone end-use measure impact estimates;
3. An estimate of the incremental and
cumulative number of program participants and end-use measure installations due
to the potential demand-side program;
4. For each year of the planning horizon, an
estimate of the incremental and cumulative demand reduction and energy savings
due to the potential demand-side program; and 5. For each year of the planning
horizon, an estimate of the costs, including:
A. The incremental cost of each stand-alone
end-use measure;
B. The cost of
incentives paid by the utility to customers or utility financing to encourage
participation in the potential demand-side program. The utility shall consider
multiple levels of incentives paid by the utility for each end-use measure
within a potential demand-side program, with corresponding adjustments to the
maximum achievable potential and the realistic achievable potential of that
potential demand-side program;
C.
The cost of incentives to customers to participate in the potential demand-side
program paid by the entities other than the utility;
D. The cost to the customer and to the
utility of technology to implement a potential demand-side program;
E. The utility's cost to administer the
potential demand-side program; and
F. Other costs identified by the
utility;
(H) A
tabulation of the incremental and cumulative number of participants, load
impacts, utility costs, and program participant costs in each year of the
planning horizon for each potential demand-side program; and
(I) The utility shall describe and document
how it performed the assessments and developed the estimates pursuant to
subsection (3)(G) and shall provide documentation of its sources and quality of
information.
(4) The
utility shall develop potential demand-side rates designed for each market
segment to reduce the net consumption of electricity or modify the timing of
its use. The utility shall describe and document its demand-side rate planning
and design process and shall include at least the following activities and
elements:
(A) Review demand-side rates that
have been implemented by other utilities and identify whether similar
demand-side rates would be applicable for the utility taking into account
factors such as similarity in electric prices and customer makeup;
(B) Identify demand-side rates applicable to
the major classes and decision-makers identified in subsection (1)(A). When
appropriate, consider multiple demand-side rate designs for the same major
classes;
(C) Assess how
technological advancements that may be reasonably anticipated to occur during
the planning horizon, including advanced metering and distribution systems,
affect the ability to implement demand-side rates;
(D) Estimate the input data and other
characteristics needed for the twenty (20)-year planning horizon to assess the
cost effectiveness of each potential demand-side rate, including:
1. An assessment of the demand and energy
reduction impacts of each potential demand-side rate;
2. An assessment of how the interactions
between multiple potential demand-side rates, if offered simultaneously, would
affect the impact estimates;
3. An
assessment of how the interactions between potential demand-side rates and
potential demand-side programs would affect the impact estimates of the
potential demand-side programs and potential demand-side rates;
4. For each year of the planning horizon, an
estimate of the incremental and cumulative demand reduction and energy savings
due to the potential demand-side rate; and
5. For each year of the planning horizon, an
estimate of the costs of each potential demand-side rate, including:
A. The cost of incentives to customers to
participate in the potential demand-side rate paid by the utility. The utility
shall consider multiple levels of incentives to achieve customer participation
in each potential demand-side rate, with corresponding adjustments to the
maximum achievable potential and the realistic achievable potentials of that
potential demand-side rate;
B. The
cost to the customer and to the utility of technology to implement the
potential demand-side rate;
C. The
utility's cost to administer the potential demand-side rate; and
D. Other costs identified by the
utility;
(E) A
tabulation of the incremental and cumulative number of participants, load
impacts, utility costs, and program participant costs in each year of the
planning horizon for each potential demand-side program;
(F) Evaluate how each demand-side rate would
be considered by the utility's Regional Transmission Organization (RTO) in
resource adequacy determinations, eligibility to participate as a demand
response resource in RTO markets for energy, capacity, and ancillary services;
and
(G) The utility shall describe
and document how it performed the assessments and developed the estimates
pursuant to subsection (4)(D) and shall document its sources and quality of
information.
(5) The
utility shall describe and document its evaluation of the cost effectiveness of
each potential demand-side program developed pursuant to section (3) and each
potential demand-side rate developed pursuant to section (4). All costs and
benefits shall be expressed in nominal dollars.
(A) In each year of the planning horizon, the
benefits of each potential demand-side program and each potential demand-side
rate shall be calculated as the cumulative demand reduction multiplied by the
avoided demand cost plus the cumulative energy savings multiplied by the
avoided energy cost. These calculations shall be performed both with and
without the avoided probable environmental costs. The utility shall describe
and document the methods, data, and assumptions it used to develop the avoided
costs.
1. The utility avoided demand cost
shall include the capacity cost of generation, transmission, and distribution
facilities, adjusted to reflect reliability reserve margins and capacity losses
on the transmission and distribution systems, or the corresponding market-based
equivalents of those costs. The utility shall describe and document how it
developed its avoided demand cost, and the capacity cost chosen shall be
consistent throughout the triennial compliance filing.
2. The utility avoided energy cost shall
include the fuel costs, emission allowance costs, and other variable operation
and maintenance costs of generation facilities, adjusted to reflect energy
losses on the transmission and distribution systems, or the corresponding
market-based equivalents of those costs. The utility shall describe and
document how it developed its avoided energy cost, and the energy costs shall
be consistent throughout the triennial compliance filing.
3. The avoided probable environmental costs
include the effects of the probable environmental costs calculated pursuant to
4 CSR
240-22.040(2)(B) on the utility
avoided demand cost and the utility avoided energy cost. The utility shall
describe and document how it developed its avoided probable environmental
cost.
(B) The total
resource cost test shall be used to evaluate the cost effectiveness of the
potential demand-side programs and potential demand-side rates. In each year of
the planning horizon-
1. The costs of each
potential demand-side program shall be calculated as the sum of all incremental
costs of end-use measures that are implemented due to the program (including
both utility and participant contributions) plus utility costs to administer,
deliver, and evaluate each potential demand-side program;
2. The costs of each potential demand-side
rate shall be calculated as the sum of all incremental costs that are due to
the rate (including both utility and participant contributions) plus utility
costs to administer, deliver, and evaluate each potential demand-side rate; and
3. For purposes of this test, the
costs of potential demand-side programs and potential demand-side rates shall
not include lost revenues or utility incentive payments to
customers.
(C) The
utility cost test shall also be performed for purposes of comparison. In each
year of the planning horizon-
1. The costs of
each potential demand-side program and potential demand-side rate shall be
calculated as the sum of all utility incentive payments plus utility costs to
administer, deliver, and evaluate each potential demand-side program or
potential demand-side rate;
2. For
purposes of this test, the costs of potential demand-side programs and
potential demand-side rates shall not include lost revenues; and
3. The costs shall include, but separately
identify, the costs of any rate of return or incentive included in the
utility's recovery of demand-side program costs.
(D) The present value of program benefits
minus the present value of program costs over the planning horizon must be
positive or the ratio of annualized benefits to annualized costs must be
greater than one (1) for a potential demand-side program or potential
demand-side rate to pass the utility cost test or the total resource cost test.
The utility may relax this criterion for programs that are judged to have
potential benefits that are not captured by the estimated load impacts or
avoided costs, including programs required to comply with legal
mandates.
(E) The utility shall
provide results of the total resource cost test and the utility cost test for
each potential demand-side program evaluated pursuant to subsection (5)(B) and
for each potential demand-side rate evaluated pursuant to subsection (5)(C) of
this rule, including a tabulation of the benefits (avoided costs), demand-side
resource costs, and net benefits or costs.
(F) If the utility calculates values for
other tests to assist in the design of demand-side programs or demand-side
rates, the utility shall describe and document the tests and provide the
results of those tests.
(G) The
utility shall describe and document how it performed the cost effectiveness
assessments pursuant to section (5) and shall describe and document its methods
and its sources and quality of information.
(6) Potential demand-side programs and
potential demand-side rates that pass the total resource cost test including
probable environmental costs shall be considered as demand-side candidate
resource options and must be included in at least one (1) alternative resource
plan developed pursuant to
4 CSR
240-22.060(3).
(A) The utility may bundle demand-side
candidate resource options into portfolios, as long as the requirements
pursuant to section (1) are met and as long as multiple demand-side candidate
resource options and portfolios advance for consideration in the integrated
resource analysis in 4 CSR 240-22.060. The utility
shall describe and document how its demand-side candidate resource options and
portfolios satisfy these requirements.
(B) For each demand-side candidate resource
option or portfolio, the utility shall describe and document the
time-differentiated load impact estimates over the planning horizon at the
level of detail required by the supply system simulation model that is used in
the integrated resource analysis, including a tabulation of the estimated
annual change in energy usage and in diversified demand for each year in the
planning horizon due to the implementation of the candidate demand-side
resource option or portfolio.
(C)
The utility shall describe and document its assessment of the potential
uncertainty associated with the load impact estimates of the demand-side
candidate resource options or portfolios. The utility shall estimate-
1. The impact of the uncertainty concerning
the customer participation levels by estimating and comparing the maximum
achievable potential and realistic achievable potential of each demand-side
candidate resource option or portfolio; and
2. The impact of uncertainty concerning the
cost effectiveness by identifying uncertain factors affecting which end-use
resources are cost effective. The utility shall identify how the menu of
cost-effective end-use measures changes with these uncertain factors and shall
estimate how these changes affect the load impact estimates associated with the
demand-side candidate resource options.
(7) For each demand-side candidate resource
option identified in section (6), the utility shall describe and document the
general principles it will use to develop evaluation plans pursuant to
4 CSR
240-22.070(8). The utility shall
verify that the evaluation costs in subsections (5)(B) and (5)(C) are
appropriate and commensurate with these evaluation plans and
principles.
(8) Demand-side
resources and load-building programs shall be separately designed and
administered, and all costs shall be separately classified to permit a clear
distinction between demand-side resource costs and the costs of load-building
programs. The costs of demand-side resource development that also serve other
functions shall be allocated between the functions served.
*Original authority: 386.040, RSMo 1939; 386.250, RSMo
1939, amended 1963, 1967, 1977, 1980, 1987, 1988, 1991, 1993, 1995, 1996;
386.610, RSMo 1939; and 393.140, RSMo 1939, amended 1949,
1967.
