Current through Register Vol. 49, No. 6, March 15, 2024
(1) The definitions of terms used in this
section can be found in
4 CSR
240-20.092 Definitions for Demand-Side Programs and
Demand-Side Programs Investment Mechanisms.
(2) Guideline to Review Progress Toward an
Expectation that the Electric Utility's Demand-Side Programs Can Achieve a Goal
of All Cost-Effective Demand-Side Savings. The goals established in this
section are not mandatory and no penalty or adverse consequence will accrue to
a utility that is unable to achieve the listed annual energy and demand savings
goals.
(A) The commission shall use the
greater of the annual realistic amount of achievable energy savings and demand
savings as determined through a market potential study or the following
incremental annual demand-side savings goals as a guideline to review and
determine whether the utility's demand-side programs can achieve a goal of all
cost-effective demand-side savings:
1. For the
utility's approved first program year: three-tenths percent (0.3%) of total
annual energy and one percent (1.0%) of annual peak demand;
2. For the utility's approved second program
year: five-tenths percent (0.5%) of total annual energy and one percent (1.0%)
of annual peak demand;
3. For the
utility's approved third program year: seven-tenths percent (0.7%) of total
annual energy and one percent (1.0%) of annual peak demand;
4. For the utility's approved fourth program
year: nine-tenths percent (0.9%) of total annual energy and one percent (1.0%)
of annual peak demand;
5. For the
utility's approved fifth program year: one-and-one-tenth percent (1.1%) of
total annual energy and one percent (1.0%) of annual peak demand;
6. For the utility's approved sixth program
year: one-and-three-tenths percent (1.3%) of total annual energy and one
percent (1.0%) of annual peak demand;
7. For the utility's approved seventh program
year: one-and-five-tenths percent (1.5%) of total annual energy and one percent
(1.0%) of annual peak demand;
8.
For the utility's approved eighth program year: one-and-seven-tenths percent
(1.7%) of total annual energy and one percent (1.0%) of annual peak demand;
and
9. For the utility's approved
ninth and subsequent program years, unless additional energy savings and demand
savings goals are established by the commission: one-and-nine-tenths percent
(1.9%) of total annual energy and one percent (1.0%) of annual peak demand each
year.
(B) The commission
shall also use the greater of the cumulative annual realistic amount of
achievable energy savings and demand savings as determined through a market
potential study or the following cumulative demand-side savings goals as a
guideline to review and determine whether the utility's demand-side programs
can achieve a goal of all cost-effective demand-side savings:
1. For the utility's approved first program
year: three-tenths percent (0.3%) of total annual energy and one percent (1.0%)
of annual peak demand;
2. For the
utility's approved second program year: eight-tenths percent (0.8%) of total
annual energy and two percent (2.0%) of annual peak demand;
3. For the utility's approved third program
year: one-and-five-tenths percent (1.5%) of total annual energy and three
percent (3.0%) of annual peak demand;
4. For the utility's approved fourth program
year: two-and-four-tenths percent (2.4%) of total annual energy and four
percent (4.0%) of annual peak demand;
5. For the utility's approved fifth program
year: three-and-five-tenths percent (3.5%) of total annual energy and five
percent (5.0%) of annual peak demand;
6. For the utility's approved sixth program
year: four-and-eight-tenths percent (4.8%) of total annual energy and six
percent (6.0%) of annual peak demand;
7. For the utility's approved seventh program
year: six-and-three-tenths percent (6.3%) of total annual energy and seven
percent (7.0%) of annual peak demand;
8. For the utility's approved eighth program
year: eight percent (8.0%) of total annual energy and eight percent (8.0%) of
annual peak demand; and
9. For the
utility's approved ninth year and subsequent program years, unless additional
energy savings and demand savings goals are established by the commission:
nine-and-nine-tenths percent (9.9%) of total annual energy and nine percent
(9.0%) of annual peak demand for the approved ninth year, and then increasing
by one-and-nine-tenths percent (1.9%) of total annual energy and by one percent
(1.0%) of annual peak demand each year thereafter.
(3) Utility Market Potential
Studies.
(A) The market potential study
shall-
1. Consider both primary data and
secondary data and analysis for the utility's service territory;
2. Be updated with primary data and analysis
no less frequently than every three (3) years. To the extent that primary data
for each utility service territory is unavailable or insufficient, the market
potential study may also rely on or be supplemented by data from secondary
sources and relevant data from other geographic regions;
3. Be prepared by an independent third party.
The utility shall provide oversight and guidance to the independent market
potential contractor, but shall not influence the independent market potential
study contractor's reports; and
4.
Include an estimate of the achievable potential, regardless of
cost-effectiveness, of energy savings from low-income demand-side programs.
Energy savings from multifamily buildings that house low-income households may
count toward this target.
(B) The utility shall provide an opportunity
for commission staff and stakeholder review and input in the planning stages of
the potential study including review of assumptions and methodology in advance
of the performance of the study.
(4) Applications for Approval of Electric
Utility Demand-Side Programs or Portfolio. Pursuant to the provisions of this
rule, 4 CSR
240-2.060, and section
393.1075,
RSMo, an electric utility may file an application with the commission for
approval of a demand-side portfolio.
(A)
Prior to filing for demand-side programs approval, the electric utility shall
hold a stakeholder advisory meeting to receive input on the major components of
its filing.
(B) As part of its
application for approval of demand-side programs, the electric utility shall
file or provide a reference to the commission case that contains any of the
following information. All models and spreadsheets shall be provided as
executable versions in native format with all links and formulas intact:
1. A current market potential study. If the
market potential study of the electric utility that is filing for approval of
demand-side programs or a demand-side portfolio encompasses more than just the
utility's service territory, the sampling methodology shall reflect the
utility's service territory and shall provide statistically significant results
for that utility:
A. Complete documentation
of all assumptions, definitions, methodologies, sampling techniques, and other
aspects of the current market potential study;
B. Clear description of the process used to
identify the broadest possible list of measures and groups of measures for
consideration;
2. Clear
description of the process and assumptions used to determine technical
potential, economic potential, maximum achievable potential, and realistic
achievable potential for a twenty- (20-) year planning horizon for major
end-use groups (e.g., lighting, space heating, space cooling, refrigeration,
motor drives, etc.) for each customer class; and
3. Identification and discussion of the
twenty- (20-) year baseline energy and demand forecasts. If the baseline energy
and demand forecasts in the current market potential study differ from the
baseline forecasts in the utility's most recent 4 CSR 240-22 triennial
compliance filing, the current market potential study shall provide a
comparison of the two (2) sets of forecasts and a discussion of the reasons for
any differences between the two (2) sets of forecasts. The twenty- (20-) year
baseline energy and demand forecasts shall account for the following:
A. Discussion of the treatment of all of the
utility's customers who have opted out;
B. Future changes in building codes and/or
appliance efficiency standards;
C.
Changes in naturally occurring customer combined heat and power
applications;
D. Third party and
other naturally occurring demand-side savings; and
E. The increasing efficiency of advanced
technologies.
(C) Demonstration of cost-effectiveness for
each demand-side program and for the total of all demand-side programs of the
utility. At a minimum, the electric utility shall provide all workpapers, with
all models and spreadsheets provided as executable versions in native format
with all links and formulas intact, and include:
1. The total resource cost (TRC) test and a
detailed description of the utility's avoided costs calculations and all
assumptions used in the calculation;
2. The utility shall also include
calculations for the utility cost test, the participant test, the RIM test, and
the societal cost test;
3. The
impacts on annual revenue requirements and net present value of annual revenue
requirements as a result of the integration analysis in accordance with
4 CSR
240-22.060 over the twenty- (20-) year planning
horizon; and
4. The impacts from
all demand-side programs included in the application on any postponement of new
supply-side resources and the early retirement of existing supply-side
resources, including annual and net present value of any lost utility earnings
related thereto.
(D)
Detailed description of each proposed demand-side program, including all
workpa-pers with all models and spreadsheets provided as executable versions in
native format with all links and formulas intact, to include at least:
1. Customers targeted;
2. Measures and services included;
3. Customer incentives ranges;
4. Proposed promotional techniques;
5. Specification of whether the demand-side
program will be administered by the utility or a contractor;
6. Projected gross and net annual and
lifetime energy savings;
7.
Proposed energy savings targets;
8.
Projected gross and net annual demand savings;
9. Proposed demand savings targets;
10. Net-to-gross factors;
11. Size of the potential market and
projected penetration rates;
12.
Any market transformation elements included in the demand-side program and an
evaluation, measurement, and verification (EM&V) plan for estimating,
measuring, and verifying the energy and demand savings that the market
transformation efforts are expected to achieve;
13. EM&V plan including at least the
proposed evaluation schedule and the proposed approach to achieving the
evaluation goals pursuant to
4 CSR
240-20.093(7);
14. Budget information in the following
categories:
A. Administrative costs listed
separately for the utility and/or program administrator;
B. Demand-side program incentive
costs;
C. Estimated equipment and
installation costs, including any customer contributions;
D. EM&V costs; and
E. Miscellaneous itemized costs, some of
which may be an allocation of total costs for overhead items such as the market
potential study or the statewide technical reference manual;
15. Description of all strategies
used to minimize free riders;
16.
Description of all strategies used to maximize spillover; and
17. For demand-side program plans, the
proposed implementation schedule of individual demand-side programs.
(E) Demonstration and explanation
in quantitative and qualitative terms of how the utility's demand-side programs
are expected to make progress towards a goal of achieving all cost-effective
demand-side savings over the life of the demand-side programs. Should the
expected demand-side savings fall short of the incremental annual demand-side
savings goals and/or the cumulative demand-side savings goals in section (2),
the utility shall provide detailed explanation of why the incremental annual
demand-side savings goals and/or the cumulative demand-side savings goals
cannot be expected to be achieved, and the utility shall bear the burden of
proof.
(F) Identification of
demand-side programs which are supported by the electric utility and at least
one (1) other electric or gas utility (joint demand-side programs).
(G) Designation of Program Pilots. For
demand-side programs designed to operate on a limited basis for evaluation
purposes before full implementation (program pilot), the utility shall provide
as much of the information required under subsections (2)(C) through (E) of
this rule as is practical and shall include explicit questions that the program
pilot will address, the means and methods by which the utility proposes to
address the questions the program pilot is designed to address, a provisional
cost-effectiveness evaluation if the program is subject to a cost-effectiveness
test under section 393.1075.4, RSMo, the proposed geographic area, and duration
for the program pilot.
(H) Any
existing demand-side program with tariff sheets in effect prior to the
effective date of this rule shall be included in the initial application for
approval of demand-side programs if the utility intends for unrecovered and/or
new costs related to the existing demand-side program be included in the DSIM.
The commission shall approve, approve with modification acceptable to the
electric utility, or reject such applications for approval of demand-side
program plans within one hundred twenty (120) days of the filing of an
application under this section only after providing the opportunity for a
hearing. In the case of a utility filing an application for approval of an
individual demand-side program, the commission shall approve, approve with
modification acceptable to the electric utility, or reject applications within
sixty (60) days of the filing of an application under this section only after
providing the opportunity for a hearing.
(I) The commission shall consider the TRC
test a preferred cost-effectiveness test. For demand-side programs and program
plans that have a TRC test ratio greater than one (1), the commission shall
approve demand-side programs or program plans, budgets, and demand and energy
savings targets for each demand-side program it approves, provided it finds
that the utility has met the filing and submission requirements of this rule
and the demand-side programs-
1. Are
consistent with a goal of achieving all cost-effective demand-side
savings;
2. Have reliable
evaluation, measurement, and verification plans; and
3. Are included in the electric utility's
preferred plan or have been analyzed through the integration process required
by 4 CSR
240-22.060 to determine the impact of the demand-side
programs and program plans on the net present value of revenue requirements of
the electric utility.
(J) The commission shall approve demand-side
programs targeted to low-income customers or general education campaigns, if
the commission determines that the utility has met the filing and submission
requirements of this rule, the demand-side programs are in the public interest,
and the demand-side programs meet the requirements stated in subsection (4)(I).
If a demand-side program is targeted to low-income customers, the electric
utility must also state how the electric utility will assess the expected and
actual effect of the demand-side program on the utility's bad debt expenses,
customer arrearages, and disconnections.
(K) The commission shall approve demand-side
programs which have a TRC test ratio less than one (1), if the commission finds
the utility has met the filing and submission requirements of this rule and the
costs of such demand-side programs above the level determined to be
cost-effective are funded by the customers participating in the demand-side
programs or through tax or other governmental credits or incentives
specifically designed for that purpose and meet the requirements as stated in
subsection (4)(I).
(L) Utilities
shall file and receive approval of associated tariff sheets prior to
implementation of approved demand-side programs.
(M) The commission shall simultaneously
approve, approve with modification acceptable to the utility, or reject the
utility's DSIM proposed pursuant to
4 CSR
240-20.093.
(5) Applications for Approval of
Modifications to Electric Utility Demand-Side Programs.
(A) Pursuant to the provisions of this rule,
4 CSR
240-2.060, and section
393.1075,
RSMo, an electric utility-
1. Shall file an
application with the commission for modification of demand-side programs when
there is a variance of twenty percent (20%) or more in the budget approved by
the commission under subsection (4)(I) or other commission order(s) and/or any
demand-side program design modification which is no longer covered by the
approved tariff sheets for the demand-side program;
2. The application shall include a complete,
reasonably detailed, explanation for and documentation of the proposed
modifications to each of the filing requirements in section (3). All models and
spreadsheets shall be provided as executable versions in native format with all
links and formulas intact;
3. The
electric utility shall serve a copy of its application to all parties to the
case under which the demand-side programs were approved;
4. The parties shall have thirty (30) days
from the date of filing of an application to object to the application to
modify;
5. If no objection is
raised within thirty (30) days, the commission shall approve, approve with
modification acceptable to the electric utility, or reject such applications
for approval of modification of demand-side programs within forty-five (45)
days of the filing of an application under this section, subject to the same
guidelines as established in subsection (4)(I);
6. If objections to the application are
raised, the commission shall provide the opportunity for a hearing.
(B) For any demand-side program
design modifications approved by the commission, the utility shall file for and
receive approval of associated tariff sheets prior to implementation of
approved modifications.
(6) Applications for Approval to Discontinue
Electric Utility Demand-Side Programs. Pursuant to the provisions of this rule,
4 CSR
240-2.060, and section
393.1075,
RSMo, an electric utility may file an application with the commission to
discontinue demand-side programs.
(A) The
application shall include the following information. All models and
spreadsheets shall be provided as executable versions in native format with all
links and formulas intact.
1. Complete,
reasonably detailed explanation for the utility's decision to request to
discontinue a demand-side program.
2. EM&V reports for the demand-side
program in question, if available.
3. Date by which a final EM&V report for
the demand-side program in question will be filed.
(B) If the TRC calculated for a demand-side
program not targeted to low-income customers or a general education campaign is
not cost-effective, the electric utility shall identify the causes why and
present possible demand-side program modifications that could make the
demand-side program cost-effective. If analysis of these modified demand-side
program designs suggests that none would be cost-effective, the demand-side
program may be discontinued. In this case, the utility shall describe how it
intends to end the demand-side program and how it intends to achieve the energy
and demand savings initially estimated for the discontinued demand-side
program. Nothing herein requires utilities to end any demand-side program which
is subject to a cost-effectiveness test deemed not cost-effective immediately.
Utilities proposal for any discontinuation of a demand-side program should
consider, but not be limited to: the potential impact on the market for energy
efficiency services in its territory; the potential impact to vendors and the
utilities relationship with vendors; the potential disruption to the market and
to customer outreach efforts from immediate starting and stopping of
demand-side programs; and whether the long term prospects indicate that
continued pursuit of a demand-side program will result in a long-term
cost-effective benefit to ratepayers.
(C) The commission shall approve or reject
such applications for discontinuation of utility demand-side programs within
thirty (30) days of the filing of an application under this section only after
providing an opportunity for a hearing.
(7) Provisions for Customers to Opt-Out of
Participation in Utility Demand-Side Programs.
(A) Any customer meeting one (1) or more of
the following criteria shall be eligible to opt-out of participation in
utility-offered demand-side programs:
1. The
customer has one (1) or more accounts within the service territory of the
electric utility that has a demand of five thousand (5,000) kW or
more;
2. The customer operates an
interstate pipeline pumping station, regardless of size; or
3. The customer has accounts within the
service territory of the electric utility that have, in aggregate across its
accounts, a coincident demand of two thousand five hundred (2,500) kW or more
in the previous twelve (12) months, and the customer has a comprehensive
demand-side or energy efficiency program and can demonstrate an achievement of
savings at least equal to those expected from utility-provided demand-side
programs. The customer shall submit to commission staff sufficient
documentation to demonstrate compliance with these criteria, including, but not
limited to:
A. Lists of all energy efficiency
measures with work papers to show energy savings and demand savings. This can
include engineering studies, cost benefit analysis, etc.;
B. Documentation of anticipated lifetime of
installed energy efficiency measures;
C. Invoices and payment requisition
papers;
(B)
For utilities with automated meter reading and/or advanced metering
infrastructure capability, the measure of demand is the customer coincident
highest billing demand of the individual accounts during the twelve (12) months
preceding the opt-out notification.
(C) Any confidential business information
submitted as documentation shall be clearly designated as such in accordance
with 4 CSR
240-2.135.
(D) Opt-out in accordance with paragraphs
(7)(A)1., 2., and 3. shall be in effect for ten years, beginning with the
calendar year subsequent to the submission of the opt-out.
(E) Written notification of opt-out from
customers meeting the criteria under paragraph (7)(A)1. or 2. shall be sent to
the utility serving the customer. Written notification of opt-out from
customers meeting the criteria under paragraph (7)(A)3. shall be sent to the
utility serving the customer and the manager of the energy resources department
of the commission or submitted through the commission's electronic filing and
information system (EFIS) as a non-case-related filing. In instances where only
the utility is provided notification of opt-out from customers meeting the
criteria under paragraph (7)(A)3., the utility shall forward a copy of the
written notification to the manager of the energy resources department of the
commission and submit the notice of opt-out through EFIS as a non-case-related
filing.
(F) Written notification of
opt-out from customer shall include at a minimum:
1. Customer's legal name;
2. Identification of location(s) and utility
account number(s) of accounts for which the customer is requesting to opt-out
from demand-side program's benefits and costs; and
3. Demonstration that the customer qualifies
for opt-out.
(G) For
customers filing notification of opt-out under paragraph (7)(A)1. or 2.,
notification of the utility's acknowledgement or plan to dispute a customer's
notification to opt-out of participation in demand-side programs shall be
delivered in writing to the customer and to the staff within thirty (30) days
of when the utility received the written notification of opt-out from the
customer.
(H) For customers filing
notification of opt-out under paragraph (7)(A)3., the staff will make the
determination of whether the customer meets the criteria of paragraph (7)(A)3.
Notification of the staff's acknowledgement or disagreement with customer's
qualification to opt-out of participation in demand-side programs shall be
delivered to the customer and to the utility within thirty (30) days of when
the staff received complete documentation of compliance with paragraph (7) (A)
3.
(I) Timing and Effect of Opt-Out
Provisions.
1. A customer notice of opt-out
shall be received by the utility no earlier than September 1 and not later than
October 30 to be effective for the following calendar year.
2. For that calendar year in which the
customer receives acknowledgement of opt-out and each successive calendar year
until the customer revokes the notice pursuant to subsection (7)(K), or the
customer is notified that it no longer satisfies the requirements of paragraphs
(7)(A)1., 2., or 3., none of the costs of approved demand-side programs of an
electric utility offered pursuant to
4 CSR
240-20.093,
4 CSR
240-20.094, or by other authority and no other charges
implemented in accordance with section
393.1075,
RSMo, shall be assigned to any account of the customer, including its
affiliates and subsidiaries listed on the customer's written notification of
opt-out.
(J) Dispute
Notices. If the utility or staff provides notice that a customer does not meet
the opt-out criteria to qualify for opt-out or renewal of opt-out, the customer
may file a complaint with the commission. The commission shall provide notice
and an opportunity for a hearing to resolve any dispute.
(K) Revocation. A customer may revoke an
opt-out by providing written notice to the utility and commission two to four
(2-4) months in advance of the calendar year for which it will become eligible
for the utility's demand-side programs' costs and benefits. Any customer
revoking an opt-out to participate in demand-side programs will be required to
remain in the demand-side program(s) for the number of years over which the
cost of that demand-side program(s) is being recovered, or until the cost of
their participation in the demand-side program(s) has been recovered.
(L) A customer who participates in
demand-side programs initiated after August 1, 2009, shall be required to
participate in demand-side programs funding for a period of three (3) years
following the last date when the customer received a demand-side incentive or a
service. Participation shall be determined based on premise location regardless
of the ownership of the premise.
(M) A customer electing not to participate in
an electric utility's demand-side programs under this section shall still be
allowed to participate in interruptible or curtailable rate schedules or
tariffs offered by the electric utility.
(8) Database of Participants.
(A) The electric utility shall maintain a
database of participants of all demand-side programs offered by the utility
when such demand-side programs offer a monetary incentive to the customer
including the following information:
1. The
name of the participant, or the names of the principals if for a
company;
2. The service property
address; and
3. The date of and
amount of the monetary incentive received.
(B) Upon request by the commission or staff,
the utility shall disclose participant information in subsection (8)(A) to the
commission and/or staff.
(9) Collaborative Guidelines.
(A) Utility-Specific Collaboratives. Each
electric utility and its stakeholders shall form a utility-specific advisory
collaborative for input on the design, implementation, and review of
demand-side programs as well as input on the preparation of market potential
studies. This collaborative process may take place simultaneously with the
collaborative process related to demand-side programs for 4 CSR 240-22.
Collaborative meetings are encouraged to occur at least once each calendar
quarter. In order to provide appropriate and informed input on the design,
implementation, and review of demand-side programs, the stakeholders will be
provided drafts of all plans and documents prior to meeting with adequate time
to review and provide comments. In addition, all stakeholders will be provided
opportunity to inform and suggest agenda items for each meeting and to present
presentations and proposals. All participants shall be given a reasonable
period of time to propose agenda items and prepare for any
presentations.
(B) State-Wide
Collaborative.
1. Electric utilities and
their stakeholders shall formally establish a state-wide advisory
collaborative. The collaborative shall-
A.
Develop statewide protocols for evaluation, measurement, and verification of
energy efficiency savings, no later than December 31, 2018, and update those
protocols annually thereafter;
B.
Establish individual working groups to address the creation of the specific
deliverables of the collaborative; and
C. Create a semi-annual forum for discussing
and resolving statewide policy issues, wherein utilities may share lessons
learned from demand-side program planning and implementation, and wherein
stakeholders may provide input on how to implement the recommendations of the
individual working groups;
D.
Explore other opportunities.
2. Within sixty (60) days of the effective
date of this rule, commission staff shall file, with the commission, a charter
for the statewide advisory collaborative.
3. Collaborative meetings shall occur at
least semi-annually. Additional meetings or conference calls will be scheduled
as needed. Staff shall schedule the meetings, provide notice of the meetings,
and any interested persons may attend such meetings.
(10) Statewide Technical Reference
Manual (statewide TRM).
(A) The statewide TRM
shall be submitted to the commission for review.
1. The commission may either approve or
reject the proposed statewide TRM.
2. If the commission rejects the proposed
statewide TRM, stakeholders may propose solutions to address the commission
concerns and, the commission may approve the solution(s) that shall be
incorporated in the statewide TRM. Stakeholders may submit a revised statewide
TRM within ninety (90) days of an order providing direction on the solution(s)
to be incorporated in the statewide TRM.
(B) Upon approval of the initial statewide
TRM, the commission may begin the process of securing a vendor to provide an
electronic, web-based platform that will facilitate annual updates and the
tracking of the updates.
1. Funding for the
electronic platform and annual updates shall be provided by investor-owned
utilities without MEEIA programs through their Public Service Commission
assessment and by investor-owned utilities with MEEIA programs through their
cost recovery component of a DSIM.
(C) The statewide TRM shall be updated by
December 31 of each year following commission approval of the initial statewide
TRM.
1. Staff shall be responsible for
coordinating the process to update the statewide TRM.
A. No later than July 1 of each year, staff
shall convene one (1) or more stakeholder meetings to seek input on revisions
to the TRM.
2. Annual
updates shall be submitted to the commission for review no later than September
1 of each year.
A. The commission may either
approve or reject the proposed revisions no later than October 1 of each
year.
B. If the commission rejects
the proposed statewide TRM, stakeholders shall propose solutions to address the
commission concerns, and the commission may approve the solution(s) that shall
be incorporated in the annual update. Stakeholders shall submit a revised
statewide TRM within thirty (30) days of an order providing directions on the
solution(s) to be incorporated in the annual update.
(D) The commission may consider
the appropriateness of using an approved statewide TRM in each utility's
application for approval of demand-side programs.
(11) Variances. Upon request and for good
cause shown, the commission may grant a variance from any provision of this
rule.
*Original authority: 393.1075, RSMo
2009.