Mo. Code Regs. tit. 20 § 4240-20.094

Current through Register Vol. 49, No. 21, November 1, 2024.

Section 20 CSR 4240-20.094 - Demand-Side Programs

PURPOSE: This rule sets forth the definitions, requirements, and procedures for filing and processing applications for approval, modification, and discontinuance of electric utility demand-side programs. This rule also sets forth requirements and procedures related to customer opt-out, tax credits, monitoring customer incentives, and collaborative guidelines for demand-side programs.

(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.

20 CSR 4240-20.094

AUTHORITY: sections 393.1075.11 and 393.1075.15, RSMo 2016.* This rule originally filed as 4 CSR 240-20.094. Original rule filed Oct. 4, 2010, effective May 30, 2011 . Amended: Filed Dec. 27, 2016, effective Oct. 30, 2017. Moved to 20 CSR 4240-20.094, effective Aug. 28, 2019.

*Original authority: 393.1075, RSMo 2009.