4 N.C. Admin. Code 11R01-17B

Current through Register Vol. 39, No. 11, December 2, 2024

Section 11 R01-17B - PROCEDURE FOR PERFORMANCE-BASED REGULATION FOR ELECTRIC PUBLIC UTILITIES UNDER G.S. 62-133.16

(a) Purpose. - This rule provides the procedures for the approval and administration of Performance-Based Regulation authorized under G.S. 62-133.16.

(b) Definitions. - As used in this rule, the following definitions shall apply:

(1) "Cost Causation Principle"; "Decoupling Ratemaking Mechanism"; "Earnings Sharing Mechanism"; "Multiyear Rate Plan" or "MYRP"; "Performance Incentive Mechanism" or "PIM"; "Performance-Based Regulation" or "PBR"; "Policy Goal"; and "Tracking Metric" shall have the same definitions as provided in G.S. 62-133.16(a).

(2) "Plan Period" shall mean the period of not more than 36 months covered by an approved PBR application.

(3) "Rate Year" shall mean each 12-month period of the MYRP for which base rates as established by G.S. 62-133 and modified by G.S. 62-133.16, are effective.

(c) Technical Conference. - No later than 90 days before an electric public utility gives notice that it intends to file a general rate case that includes a PBR application, the electric public utility shall file a request with the Commission to initiate a technical conference regarding the projected transmission and distribution projects to be included in the PBR application. The Commission will schedule one or more sessions of the technical conference to be conducted within 60 days of receiving a request for a technical conference. The following apply to the technical conference process:

(1) Any party that desires to participate in the technical conference process shall provide notice to the Commission no later than 15 days prior to the first session of the technical conference. All parties will be provided an opportunity to provide comment and feedback on the electric public utility's technical conference information in the manner prescribed in the Commission order scheduling the technical conference process.

(2) No later than ten business days before the first session of the technical conference, the electric public utility must file the following information on projected transmission and distribution projects to be included in the PBR application:

a. A comprehensive list of programs and major projects accompanied by, for each program and project, the purpose (e.g., capacity increase or reliability), a timeline for construction including the estimated placed in-service date, projected costs, cost-benefit analyses, and any other information, justifying each program and project. Cost benefit analyses shall not be required if a program or project is required by law; and

b. An explanation of the need for the proposed transmission and distribution expenditures and how the overall proposal advances system efficiency, reliability, or is necessary to comply with applicable federal operational or design requirements.

(d) Filing Requirements. - An application for a PBR must be filed with a general rate case proceeding initiated under G.S. 62-133, and must comply with Rule R1-17 unless otherwise provided in this Rule. Supporting data and work papers for the information provided by this section shall be provided to the Commission, Public Staff, and any other party to the proceeding. An electric public utility seeking approval of PBR must file the following:

(1) A proposed Decoupling Ratemaking Mechanism that includes the following:

a. The applicable residential rate schedules and riders eligible to be affected by the decoupling.

b. The proposed target annual revenue requirement per residential customer unit for each Rate Year, with weather normalization, along with the electric public utility's underlying assumptions, calculations, and methodology.

c. Proposed distribution of the weather normalized per residential revenue requirement for each month in each Rate Year, along with the electric public utility's underlying assumptions, calculations, and methodology.

d. The projected number of residential customers for each Rate Year, along with the projected number of residential customers for each month of each Rate Year, and an explanation of the calculation or methodology for determining the projected number of residential customers for each month.

e. The proposed method for calculating and deferring differences realized between the estimated and actual revenue per customer, including the proposed accounting entries for decoupling true-up entries.

f. A method for distinguishing kWh sales associated with EVs and the residential class as a whole and an explanation of how those EV sales will be treated, including the EV rate schedules or riders that have been excluded from the mechanism, along with the projected number of EV customers and kWh for each month of each Rate Year, along with the electric public utility's underlying assumptions, calculations, and methodology.

(2) A proposed MYRP that includes the following:

a. A concise, plain statement of the changes in base rates and the time when the change in rates will go into effect with schedules for each Rate Year of the MYRP in the same manner required pursuant to G.S. § 62-134(a).

b. A forecast of the weather-normalized revenues and costs for each Rate Year of the MYRP including detailed supporting workpapers.

c. A forecast of the required overall return, return on common equity (or its equivalent), and revenue requirement for each Rate Year of the MYRP, including detailed supporting workpapers.

d. A forecast, for each year of the MYRP, of the kWh sales, kilowatt (kW) load (coincident peak demand, non-coincident peak demand), electric vehicle kWh sales, and the number of expected customers, with weather normalization, including detailed supporting workpapers.

e. The electric public utility's forecasting methodology used for each of its forecasts, including its forecasts for all costs, energy sales, peak demand, and number of expected customers for each year of the MYRP.

f. A detailed description of and detailed workpapers supporting all adjustments increasing or decreasing, for each year of the MYRP, operating revenue deductions and capital expenditures above or below the amounts proposed for the general rate case in accordance with G.S. § 62-133.

g. A calculation of the proposed percent increase in revenue requirements for Rate Years 2 and 3, if applicable, of the MYRP calculated as set forth in the Statute.

h. A fully adjusted jurisdictional and class cost of service study that includes:

i. Total electric cost of service and rates of return on rate base under present rates per books, present rates annualized, and proposed rates for each year of a MYRP annualized;

ii. Functionalization and classification of all revenues, rate base, and expenses related to the base year and each subsequent year of a MYRP;

iii. A unit cost study for the base year and each subsequent year of a MYRP; and

iv. Jurisdictional and customer class allocation factors and accompanying workpapers.

i. The electric public utility's financing plan for the capital spending projects for each year of the MYRP.

j. Projected costs, including AFUDC, if applicable, and related workpapers associated with the discrete and identifiable capital spending projects to be placed into service for each Rate Year of the MYRP, including:

i. The reason for each capital spending project;

ii. The scope of each capital spending project;

iii. The timing of each capital spending project, including projected in-service month and year for each capital spending project;

iv. The depreciation life of each capital spending project by year;

v. Changes expected in the depreciable life of each capital spending project for two years after the conclusion of the MYRP; and

vi. The impacts on (a) operating expenses (including operations and maintenance, depreciation, and taxes other than income expenses), and (b) the itemized rate base, related to the construction, and placement into service, of the capital spending projects for each Rate Year of the MYRP.

k. Projected operating benefits associated with the capital spending projects to be placed in service during each Rate Year of the MYRP, including the methodology, modeling, or other analyses used to determine the projected operating benefits.

l. A reconciliation, accompanied by detailed workpapers, of the capital expenditures and expenses associated with the capital spending projects set forth in response to subsection j. above with the increases in annual expenses and capital investments set forth in subsections b. and c. above.

m. A proposed Earnings Sharing Mechanism that provides for the refund to customers of any annual revenues collected from the ratepayers associated with weather-normalized earnings 50 basis points or more above the Commission authorized rate of return on equity. The proposal must include the following:

i. The projected, weather-normalized earnings for each Rate Year.

ii. The electric public utility's weather normalization methodology, along with all underlying assumptions and calculations.

iii. Proposed revenue requirements for each Rate Year of the MYRP.

n. Proposed base rates and pro forma revenues for each of the years that a MYRP is in effect or a method for calculating the same, accompanied by exhibits that illustrate base rate changes (exclusive of all riders applicable to the electric public utility's service), and workpapers similar in form to those provided for the general rate case pursuant to G.S. § 62-133, with exhibits including the base revenues and associated rates for the NC retail jurisdiction, each customer class and rate schedule.

o. A proposed allocation of the electric public utility's total revenue requirement among customer classes for each Rate Year of the MYRP based upon the Cost Causation Principle, including the use of minimum system methodology by an electric public utility that allocates distribution costs between customer classes. Interclass subsidization of ratepayers should be minimized to the greatest extent practicable by the conclusion of the MYRP period.

p. A new depreciation study prepared within 180 days of the filing of the PBR application. However, an electric public utility serving fewer than 150,000 customers in North Carolina may file a new depreciation study that was prepared within two years of the PBR application date.

(3) One or more clearly defined PIMs that include the following:

a. Identification of the Policy Goal targeted by the PIM;

b. A detailed explanation of how the proposed PIM supports or advances the Policy Goal;

c. An estimate of the impact to annual and total revenue requirements (NC retail jurisdiction and customer classes) that would result from supporting or advancing the Policy Goal;

d. Identifiable and measurable metrics that will be used to assess compliance, including but not limited to projections of costs to be incurred, along with information on how the electric public utility intends to evaluate, measure, and verify compliance or achievement, and the proposed resources (labor, contractors, materials, etc.) the electric public utility plans to use to support or advance the Policy Goal; and

e. The penalty to be refunded to or the reward to be collected from customers for the proposed PIM accompanied by one or more of the following:

i. An explanation of how any savings achieved by meeting or exceeding a specific Policy Goal will be shared with customers.

ii. A proposal for differentiated authorized rates of return on common equity (or its equivalent) to encourage utility investments or operational changes to meet a specific Policy Goal; or

iii. Proposed fixed financial rewards or penalties based on achievement of specific Policy Goals. To the extent possible, the proposed PIMs should reward the electric public utility for achieving specific outcomes or penalize the electric public utility for not achieving specific outcomes.

iv. A detailed explanation of:

a) How the proposed penalty or reward will minimize any duplication of other rewards or penalties created by other ratemaking mechanisms authorized by statute or Commission rule; and

b) How the electric public utility will distinguish the achievements that are rewarded through the incentives earned by the utility related to its DSM/EE portfolio approved pursuant to Rules R8-68 and 8-69 from those that it proposes to be measured for purposes of any performance incentive pursuant to § 62-133.16.

(4) The electric public utility may include in its PBR application proposed Tracking Metrics with or without targets or benchmarks to measure electric public utility achievement.

(e) General Procedures. - The following general procedures apply to a proceeding to consider a PBR application:

(1) Any PBR application approved by the Commission shall remain in effect for the Plan Period of not more than 36 months.

(2) The Commission, on its own motion or at the request of the Commission Staff, Public Staff, or any party of interest in the PBR application proceeding or related general rate case proceeding, may review the sufficiency of the PBR application under the procedures set forth in Rule R1-17(f).

(3) The electric public utility shall provide notice of the PBR application to the same extent as provided in G.S. 62-134(a). The notice to customers shall include the proposed tariff rates for each Rate Year in the Plan Period.

(4) During the Plan Period, the Commission, with good cause and upon its own motion or petition by the Public Staff, may examine the reasonableness of an electric public utility's rates under a plan, conduct periodic reviews with opportunities for public hearings and comments from interested parties, and initiate a proceeding to adjust base rates or PIMs as necessary. This examination may be consolidated with the Annual Review process under subsection (g) of this Rule.

(5) An electric public utility may not file a general rate case application to be effective during the Plan Period of an approved PBR application unless the weather-normalized earnings fall below the authorized rate of return on equity. If an electric public utility files a rate case due to weather-normalized earnings falling below the authorized rate of return on equity, the rates in effect under the approved PBR at the time of that rate case filing remain in effect until further order of the Commission.

(6) The order approving or modifying a PBR application shall address the process for annual adjustments to the ESM Rider, Decoupling Rider, and PIM Rider. Any adjustment ordered by the Commission in the ESM Rider, Decoupling Rider, and PIM Rider shall be effective for a 12-month period.

(7) The rates in effect at the end of the final Rate Year of the approved PBR shall remain in effect, and the utility shall continue to file the reports required under subsection (h) of this Rule, until further order of the Commission. Unless otherwise provided by Commission Order, the ESM Rider, Decoupling Rider, and PIM Rider shall be reset to $0 at the end of the Plan Period, after the 12-month period of recovery of the final year adjustment authorized by the Commission under subsection (g) of this Rule.

(f) Rejection of a PBR Application. - In an order of the Commission rejecting a PBR application, the Commission shall establish the electric public utility's base rates under G.S. 62-133 and provide an explanation of any deficiency in the PBR application. The order shall provide a period for the electric public utility to provide notice of its intent to file a proposed cure of the deficiencies, and a time period for the utility to file the proposed cure. The period for the electric public utility to file its proposed cure of the deficiencies will be based on the magnitude of the deficiencies outlined in the order but shall not exceed 90 days.

(g) Annual Review. - The Commission shall evaluate the Decoupling Rider, ESM Rider, and PIM Rider for each of the three Rate Years of the Plan Period. The Commission will establish the procedure for the annual review and issue an order setting forth the procedure based on requirements of this Rule. The Commission's order setting forth the procedure for the annual review will require the utility to provide notice of the Annual Review and will schedule a public hearing. The public hearing may be canceled if no significant protests are received.

(1) Decoupling Rider. - Within 45 days of the end of each quarter of a Plan Period, the electric public utility shall file a status report outlining its calculation of its proposed adjustment to the Decoupling Rider. Within 60 days of the end of each Rate Year, the electric public utility shall file its proposed adjustment to the Decoupling Rider for the Rate Year. The Public Staff shall file its analysis of the electric public utility's proposed adjustment to the Decoupling Rider for the Rate Year within 60 days of the utility's filing. The quarterly status reports and annual proposed adjustments to the Decoupling Rider filed by the electric public utility must include the following:

a. The final applicable residential rate schedules and riders eligible to be affected by the decoupling.

b. The finalized proposed target annual revenue requirement per residential customer unit for the preceding Rate Year, with weather normalization, along with the utility's underlying assumptions, calculations, and methodology.

c. The proposed distribution of the weather-normalized per residential revenue requirement for each month in the preceding Rate Year, along with the utility's underlying assumptions, calculations, and methodology.

d. The number of residential customers for the preceding Rate Year, along with the number of residential customers for each month of the preceding Rate Year, or calculation or methodology for determining the projected number of residential customers for each month.

e. The calculation of the total deferred differences between the estimated and actual revenue per customer, and the proposed billing factors to collect or refund the deferred differences, along with detailed supporting workpapers.

f. A method for distinguishing kWh sales associated with EVs and the residential class as a whole and an explanation of how those EV sales will be treated; and EV rate schedules or riders that have been excluded from the mechanism, along with the projected number of EV customers and kWh for each month of each Rate Year, along with the utility's underlying assumptions, calculations, and methodology.

(2) ESM Rider. - The Commission shall examine the earnings of the electric public utility at the end of each Rate Year, as adjusted for weather normalization and any other pro forma adjustments found reasonable and appropriate by the Commission in the PBR proceeding, to determine if the earnings exceeded the authorized rate of return on equity determined by the Commission in the proceeding establishing the PBR. If the adjusted earnings exceed the authorized rate of return on equity plus 50 basis points, the excess earnings above the authorized rate of return on equity plus 50 basis points shall be shared with customers in the ESM Rider. Any penalty or reward from a PIM approved in the PBR, and any incentives related to demand-side management and energy efficiency measures pursuant to G.S. 62-133.9(f) shall be excluded from the calculation used to determine the ESM Rider. Within 60 days of the end of each Rate Year, the electric public utility shall file its proposed adjustment to the ESM Rider for the Rate Year. The Public Staff shall file its analysis of the electric public utility's proposed adjustment to the ESM Rider for the Rate Year within 60 days of the utility's filing.

(3) PIM Rider. - The Commission shall evaluate the performance of the electric public utility with respect to a PIM approved in an approved PBR application. Any financial rewards shall be collected from customers and any penalties shall be distributed to customers through the PIM Rider. Within 60 days of the end of each Rate Year, the electric public utility shall file its calculations of all increment and decrement billing factors for the PIM Rider for the Rate Year. The electric public utility shall also file all workpapers and documentation verifying and supporting the results of the metrics used to quantify the results of any PIM. The Public Staff shall file its analysis of the electric public utility's calculations for the PIM Rider for the Rate Year within 60 days of the electric public utility's filing.

(h) Reporting Requirements. - An electric public utility with an approved PBR shall file quarterly reports for each three-month period of the Plan Period. The first filing shall be made no later than 60 days after the first three-month period, and subsequent reports shall be made every three months thereafter. Each filing shall contain the following:

(1) An earnings report consisting of the following:

a. A balance sheet as of the report date and an income statement for the three months and MYRP year-to-date for the electric public utility;

b. A statement of the per books net operating income for the three months and Rate Year-to-date for the electric public utility based on the most recent cost of service allocation study filed with the Commission, and on North Carolina ratemaking;

c. A statement of rate base at the end of the three months for the electric public utility based on the most recent cost of service allocation study filed with the Commission, and on North Carolina ratemaking;

d. The number of customers, kWh and kW sold, and service revenue for the three months for each rate division by rate type; and

e. A report of refunds or credits disbursed to customers during the three months by rate class by rate schedule.

(2) A construction status report which includes the following information for each capital spending project:

a. The costs incurred during the three months;

b. The cumulative amount incurred;

c. The original and revised estimated total cost;

d. The in-service date estimated in the MYRP; and

e. The actual date placed in service or, if not yet placed in service, the current estimated in-service date.

(3) A report tracking the changes to any capital spending project, approved by the Commission for inclusion in the MYRP. The quarterly report shall include at a minimum, the following items:

a. List of projects impacted by the change, including the project name as originally approved, any change in the scope of the project, and any other projects (new or original) that are impacted by the change.

b. For each project identified in subparagraph a. above, provide:

1. The original and revised estimated in-service dates;

2. A statement explaining the purpose/reason for the change;

3. The original and revised cost estimates; and

4. The actual spending in each quarter, year-to-date, and project-to-date.

04 N.C. Admin. Code 11 R01-17B

NCUC Docket No. E-100 Sub 178, 2/10/2022

NCUC Docket No. E-100 Sub 178, 2/10/2022