PURPOSE: This rule sets forth the definitions, structure, operation, and procedures relevant to the filing and processing of applications to reflect prudently incurred fuel and purchased power costs through an interim energy charge or a fuel adjustment clause which allows periodic rate adjustments outside general rate proceedings.

1. (1) The following subsections define various terms as used in this rule:

   1. (A) Accumulation period means the time period set by the commission in the general rate proceeding over which historical fuel and purchased power costs and fuel-related revenues are accumulated for purposes of determining the actual net energy costs (ANEC). An accumulation period may be a time period from three (3) to twelve (12) months with the timing and number of accumulation periods to be determined in the general rate proceeding establishing, continuing, or modifying the FAC;
   2. (B) Actual net energy costs (ANEC) means prudently incurred fuel and purchased power costs net of fuel-related revenues of a rate adjustment mechanism (RAM) during the accumulation period;
   3. (C) Base energy costs means the fuel and purchased power costs net of fuel-related revenues determined by the commission to be included in a RAM that are also included in the revenue requirement used to set base rates in a general rate case;
   4. (D) Base factor (BF) means base energy costs rate or rates that are established in a general rate proceeding and are included in the utility’s fuel adjustment clause (FAC). The base factor rates may vary within a year;
   5. (E) Base rates means the tariffed rates that do not change between general rate proceedings;
   6. (F) Electric utility or utility means electrical corporation as defined in section 386.020, RSMo, subject to commission regulation pursuant to Chapters 386 and 393, RSMo;
   7. (G) EFIS means the electronic filing and information system of the commission;
   8. (H) FAC charge means the positive or negative dollar amount on each utility customer’s bill, which in the aggregate is to recover from or return to customers the fuel and purchased power adjustment (FPA) amount;
   9. (I) Fuel adjustment clause (FAC) means a mechanism established in a general rate proceeding which is designed to recover from or return to customers the fuel and purchased power adjustment (FPA) amounts through periodic changes to the fuel adjustment rates (FAR) made outside a general rate proceeding;
   10. (J) Fuel adjustment rate (FAR) means the rate used to determine the FAC charge on each utility customer’s bill during a recovery period of a FAC. The FAR shall be designed to recover from or return to customers the recovery period FPA. The FAR may be positive or negative;

   11. (K) Fuel and purchased power adjustment (FPA) amount means the dollar amount intended to be recovered from or returned to customers during a given recovery period of a FAC. The FPA may be positive or negative. It includes:

       1. 1. The difference between the ANEC and NBEC of the

corresponding accumulation period taking into account any incentive ordered by the commission;

1. 2. True-up amount(s) ordered by the commission prior to

or on the same day as commission approval of the FAR adjustment;

1. 3. Prudence adjustment amount(s) ordered by the com-

mission since the last adjustment to the FAR;

1. 4. Interest; and
2. 5. Any other adjustment amount(s) ordered by the com-

mission;

1. (L) Fuel and purchased power costs means prudently incurred and used fuel and purchased power costs, including transportation costs. Prudently incurred costs do not include any increased costs resulting from negligent or wrongful acts or omissions by the utility.

   1. 1. If off-system sales revenues are not reflected in the rate

adjustment mechanism (RAM), fuel and purchased power costs shall only reflect the prudently incurred fuel and purchased power costs necessary to serve the electric utility’s Missouri retail customers.

1. 2. Unless otherwise approved by the commission, fuel and

purchased power costs do not include environmental costs as defined in 4 CSR 240-20.091(1) or renewable energy standard compliance costs as defined in 4 CSR 240-20.100(1). If such costs are included in fuel and purchased power costs, they shall not be included in another rate adjustment mechanism.

1. (M) Fuel-related revenues means those revenues related to the generation, sale, or purchase of energy or capacity. Fuelrelated revenues may include, but are not limited to, off-system sales, emission allowance sales, and renewable energy credits or certificates whenever such renewable energy credits or certificates are not included in a Renewable Energy Standard Rate Adjustment Mechanism (RESRAM) in compliance with 4 CSR 240-20.100;
2. (N) General rate proceeding means a general rate increase proceeding or complaint proceeding before the commission in which all relevant factors that may affect the costs, or rates and charges of the electric utility are considered by the commission;
3. (O) Interest means monthly interest at the utility’s short-term borrowing rate to accurately and appropriately remedy any overor under-billing of the FPA amount during an accumulation period and recovery period, and any commission ordered refund of imprudently incurred costs;
4. (P) Interim energy charge (IEC) means a mechanism that includes a refundable fixed amount billed through an interim energy rate (IER) established in a general rate proceeding that permits an electric utility to recover some or all of its fuel and purchased power costs separate from the fuel and purchased power costs included in its base rates. Base energy cost in the base rates is the floor of the IEC. The base energy cost plus the fuel and purchased power costs billed through the IER is the ceiling of the IEC. An IEC may or may not include fuel-related revenues and costs related to those revenues;
5. (Q) Megawatt (MW) is one million (1,000,000) watts;
6. (R) Megawatt hour (MWh) is one million (1,000,000) watt hours or one thousand (1,000) kilowatt hours (kWh);
7. (S) MCF is one thousand (1,000) cubic feet of natural gas;
8. (T) MMBtu is one million (1,000,000) British thermal units (Btus);
9. (U) Net base energy costs (NBEC) means the fuel and purchased power costs net of fuel-related revenues billed during the accumulated period in base rates;
10. (V) Other parties means any party to the applicant’s most recent general rate proceeding in which the RAM at issue was established, continued, or modified;
11. (W) Rate adjustment mechanism (RAM) refers to either a commission-approved fuel adjustment clause (FAC) or a commission-approved interim energy charge (IEC);
12. (X) Rebase base energy costs means the base energy cost as reset in each general rate proceeding in which the FAC is continued or modified;
13. (Y) Recovery period means the period over which the FAR is applied to retail customers’ bills to recover the FPA. A recovery period is determined in a general rate case and shall not be longer than twelve (12) billing months;
14. (Z) Staff means the staff of the Public Service Commission; and

15. (AA) True-up amount means—

    1. 1. For a FAC, the true-up amount shall be the difference

between the FPA and the utility’s aggregate FAC charges billed for a recovery period.

1. A. If the aggregate FAC charges billed for recovery period

are more than the FPA, the true-up amount will be negative.

1. B. If the aggregate FAC charges billed for a recovery pe-

riod are less than the FPA, the true-up amount will be positive.

1. C. The electric utility may request in its general rate

case to use the final Regional Transmission Organization (RTO) determinants to update the FPA for its true-up if the electric utility belongs to an RTO where the RTO may, after the beginning of the recovery period, finalize the determinants used to calculate the FPA for the recovery period.

1. 2. For an IEC, the true-up amount shall be determined as

follows for each consecutive twelve- (12-) month period—

1. A. If the actual fuel and purchased power cost is greater

than the IEC ceiling, the true-up amount shall be zero;

1. B. If the actual fuel and purchased power cost is less

than the IEC ceiling and greater than the IEC floor, the true-up amount shall be the difference between the actual fuel and purchased power cost and the combined IEC billed plus the base energy cost. The customers will be credited/refunded this amount; or

1. C. If the actual fuel and purchased power cost is less

than the IEC floor, the true-up amount shall be the aggregate IEC billed. The customers will be credited/refunded this amount.

1. (2) Establishment, Continuance, or Modification of a RAM. An electric utility may only file a request with the commission to establish, continue, or modify a RAM in a general rate proceeding and must rebase base energy costs in each general rate proceeding in which the FAC is continued or modified. Any party in a general rate proceeding may seek to continue, modify, or oppose the RAM. The commission shall approve, modify, or reject such request only after providing the opportunity for a full hearing in a general rate proceeding. The commission shall consider all relevant factors that may affect the costs or overall rates and charges of the petitioning electric utility.

   1. (A) The electric utility shall file the following supporting information, in electronic format, where available, with all links and formulas intact, as part of, or in addition to, its direct testimony:

      1. 1. An example of the notice to be provided to customers

during the pendency of the general rate proceeding where the RAM is under consideration, which shall be approved by the commission. The notice shall include a description of how its proposed RAM shall be applied to monthly bills, the amount of the proposed change in base rates caused by the rebase of energy costs, and the estimated impact on a typical residential customer’s bill resulting from the rebase of energy costs;

1. 2. An example customer bill(s) covering all of the electric

utility’s rate classes showing how the proposed RAM shall be separately identified on affected customers’ bills in accordance with section (12);

1. 3. Proposed RAM tariff sheets;
2. 4. A detailed description of the design and intended oper-

ation of the proposed RAM;

1. 5. A detailed explanation of how the proposed RAM is

reasonably designed to provide the electric utility a sufficient opportunity to earn a fair return on equity;

1. 6. A detailed explanation of how the proposed FAC shall

be trued-up for overand under-billing, or how and when the refundable portion of the proposed IEC shall be trued-up;

1. 7. A detailed description of how the electric utility’s

monthly short-term borrowing rate will be defined and how it will be applied, during the accumulation period and the recovery period, to overand under-billed amounts and prudence disallowances;

1. 8. A detailed description of how the proposed RAM is com-

patible with the requirement for prudence reviews in section (11);

1. 9. A detailed explanation of the fuel and purchased power

costs, including transportation, that are to be considered in determining the amount to be recovered under the proposed RAM with identification of the specific account and any other designation ordered by the commission where that cost will be recorded on the electric utility’s book and records.

1. 10. A detailed explanation of the fuel-related revenues

that are to be considered in determining the amount to be recovered under the proposed RAM with identification of the specific account and any other designation ordered by the commission where that revenue will be recorded on the electric utility’s books and records;

1. 11. A detailed explanation of any incentive feature in the

proposed RAM with the expected benefit and cost each feature is intended to produce for both the electric utility and its Missouri retail customers;

1. 12. A detailed explanation of any rate volatility mitigation

feature in the proposed RAM;

1. 13. A detailed explanation of any feature of the proposed

RAM and any existing electric utility policy, procedure, or practice that ensures only prudent fuel and purchased power costs and fuel-related revenues are recovered through the proposed RAM, including, but not limited to, utilization of competitive bidding or other sourcing or sales practices;

1. 14. A detailed explanation of any change to the electric

utility’s business risk resulting from implementation of the proposed RAM, in addition to any other changes in business risk the electric utility may experience;

1. 15. A level of efficiency for each of the electric utility’s gen-

erating units determined by the results of heat rate/efficiency tests or monitoring that were conducted or obtained on each of the electric utility’s steam generators, including nuclear steam generators, heat recovery steam generators, steam turbines and combustion turbines within twenty-four (24) months preceding the filing of the general rate increase case.

1. A. The results should be filed in a table format by gen-

erating unit type, rated megawatt (MW) output rating, the numerical value of the latest result and the date of the latest result;

1. B. The electric utility shall provide documentation of the

actual test/monitoring procedures. The electric utility may, in lieu of filing the documentation of these procedures with the commission, provide them to the staff, OPC, and to other parties as part of the workpapers it provides in connection with its direct case filing. If the electric utility submits the results in workpapers, it will provide a statement in its testimony as to where the results can be found in workpapers;

1. 16. Information that shows that the electric utility has in

place a long-term resource planning process;

1. 17. If the electric utility proposes to include emissions al-

lowances costs or sales revenue in the proposed FAC and not in an environmental cost recovery mechanism, a detailed explanation of its emissions management policy, and its forecasted environmental investments, emissions allowances purchases, and emissions allowances sales;

1. 18. For each power generating unit the electric utility

owns or controls, in whole or in part, the electric utility shall file graphs, accompanied by the data supporting the graphs, for each month over the immediately preceding five (5) years, showing the monthly equivalent availability factor, the monthly equivalent forced outage rate, and the length and timing of each planned outage of that unit; and

1. 19. Authorization for the staff to release to all parties to the

general rate proceeding in which the establishment, continuation, or modification of a RAM is requested, the previous five (5) years of historical surveillance monitoring reports the electric utility submitted in EFIS.

1. (B) In lieu of providing copies of information, an electric utility filing for modification or continuance of a RAM in which the information required in subsection (2)(A) has been previously filed with the commission as part of a general rate proceeding and has not changed in any manner, may certify that the information has not changed and provide to all parties the general rate case number and location in EFIS, including the EFIS item and page number where the information can be found. If there are parties to the RAM proceeding that would not have access to the rate case information, the electric utility must provide copies of the information to that party.
2. (C) An electric utility filing to continue or modify a RAM must also provide to all parties any additional information the commission ordered the electric utility to provide when seeking to continue or modify its RAM.

3. (D) The commission may approve the establishment, continuation, or modification of a RAM and associated tariff sheets provided that it finds that the RAM is reasonably designed to provide the electric utility with a sufficient opportunity to earn a fair return on equity and so long as the tariff sheets that implement the RAM conform to the RAM approved by the commission. In its determination, the commission may consider, but is not limited to, considering—

   1. 1. Fuel and purchased power costs, fuel-related revenues

that would flow through the RAM, or other factors it deems appropriate;

1. 2. Any change in business risk of the utility resulting from

establishment, continuation, or modification of the RAM in setting the electric utility’s allowed return on equity in any general rate proceeding, in addition to any other changes in business risk experienced by the electric utility; and

1. 3. In determining which fuel and purchased power cost

types and fuel-related revenue types to include in a RAM, the commission may consider the magnitude of each cost or revenue type, the ability of the utility to manage each cost or revenue type, the volatility of each cost or revenue type and the incentive provided to the utility as a result of the inclusion or exclusion of each cost or revenue type. The commission may, in its discretion, determine what portion of prudently incurred fuel and purchased power costs and fuel-related revenues may be recovered from and/or returned to customers through a RAM and what portion shall be included in the determination.

1. (E) Any party to the general rate proceeding may oppose any RAM and/or may propose alternative RAMs for the commission’s consideration.
2. (F) The RAM, and any adjustments to the FARs if a FAC is approved, shall be based on historical fuel and purchased power costs and fuel-related revenues.

3. (G) For an electric utility requesting a FAC, the utility shall include in its proposed tariff sheets provisions which shall accurately and appropriately remedy any true-up amount as part of the electric utility’s determination of its FPA for a change to its FARs. The proposed tariff sheets shall include, at a minimum:

   1. 1. When the electric utility will file for a true-up;
   2. 2. How the true-up amount will be determined including,

but not limited to, any recalculation of the FPA; and

1. 3. How and when the true-up amount will be recovered.
2. (H) For an electric utility with an IEC mechanism, a true-up must be filed within sixteen (16) months of the operation of law date of the IEC and be filed annually thereafter.
3. (I) Any party to the general rate proceeding may propose a cap on the periodic changes to the fuel adjustment rate (FAR), to mitigate volatility in rates, provided it proposes a method for the utility to recover all of the costs it would be entitled to recover in the FAC, together with interest thereon.

1. (3) Discontinuance of a RAM. The tariff sheets that define and implement a RAM shall only be discontinued and withdrawn after the opportunity for a full hearing in a general rate proceeding. The commission shall consider all relevant factors which may affect the costs or overall rates and charges of the petitioning electric utility.

   1. (A) When an electric utility files a general rate proceeding in which it requests that its RAM be discontinued, the electric utility shall file with the commission, and serve on the parties, the following supporting information, in electronic format, where available, with all links and formulas intact, as part of, or in addition to, its direct testimony:

      1. 1. An example of the notice to be provided to customers

during the pendency of the general rate proceeding in which discontinuation is being proposed. The notice shall be approved by the commission and should include a description of why the utility believes the RAM should be discontinued;

1. 2. A detailed explanation of how the electric utility pro-

poses to discontinue its RAM.

1. A. If requesting to discontinue its FAC, the electric utility

shall include the following in its explanation:

1. (I) The ending date of the last FAC accumulation pe-

riod;

1. (II) The beginning and ending dates of the recovery

period for that accumulation period; and

1. (III) The procedure for the true-up associated with the

recovery period for that accumulation period.

1. B. If requesting to discontinue its IEC, the electric utility

shall include a detailed explanation of how any over-billing will be returned to the electric utility’s retail customers;

1. 3. A detailed explanation of why the RAM is no longer nec-

essary to provide the electric utility a sufficient opportunity to earn a fair return on equity;

1. 4. A detailed explanation of any impact on setting the

electric utility’s allowed return on equity in any rate proceeding as a result of the change to the electric utility’s business risk resulting from discontinuation of its RAM, in addition to any other changes in business risk experienced by the electric utility; and

1. 5. Any additional information that the commission or-

dered the electric utility to provide when seeking to discontinue its RAM.

1. (B) Any party to the general rate proceeding may oppose the discontinuation of a RAM on the grounds that the utility is opportunistically discontinuing the RAM due to declining fuel or purchased power costs and/or increasing fuel-related revenues. If the commission finds that the utility is opportunistically seeking to discontinue the RAM for any of these reasons, the commission shall not allow the RAM to be discontinued, and shall order its continuation or modification. In addition to other remedies provided by law, the commission may reject the utility’s request for discontinuance of a RAM if it finds that the utility has not complied with this rule in its request to discontinue its RAM. To continue or modify the RAM under such circumstances, the commission must find that it provides the electric utility with a sufficient opportunity to earn a fair rate of return on equity and the tariff sheets filed to implement the RAM must conform to the RAM approved by the commission. Any RAM and periodic adjustments to the FAR shall be based on historical fuel and purchased power costs.
2. (C) The commission may take into account any change in business risk of the electric utility resulting from discontinuance of the RAM in setting the electric utility’s allowed return on equity in any general rate proceeding in addition to any other changes in the electric utility’s business risk.

1. (4) Requirements for Electric Utilities that have a RAM. If the commission grants, modifies, or continues an electric utility’s RAM, the electric utility shall—

   1. (A) Upon thirty (30) days prior written notice to the electric utility, provide for review by staff at its corporate headquarters, or some other place mutually agreed upon by the electric utility and staff, a copy of each and every nuclear fuel, coal, natural gas, and fuel transportation contract (to the extent related to generation of electricity), the utility’s hedging policies and the utility’s internal policy for participating in a Regional Transmission Organization (RTO) ancillary services market (if applicable), including every amendment and modification to each such contract or policy that was in effect during a RAM for the electric utility; and
   2. (B) Notify the staff through EFIS of every new nuclear fuel, coal, natural gas, and fuel transportation contract and every new amendment and every new modification to currently existing contracts or to the policies referenced in subsection (4)(A) above within thirty (30) days of the effective date of the contract, amendment, or modification. The notification shall include where the contracts, amendments, modifications, and related competitive bidding materials may be reviewed.

2. (5) Periodic Reports. So long as it has a RAM in effect, each electric utility shall submit a monthly report through EFIS and to staff, OPC, and other parties. Each periodic report shall be verified by the affidavit of an electric utility representative(s) who has knowledge of the subject matter and who attests to both the veracity of the information and his/her knowledge of it. The information identified in this section shall be provided in electronic format, where available, with all links and formulas intact. Each periodic report shall contain the following information by month:

   1. (A) The billing month actual energy usage in kWh by rate class and voltage level;
   2. (B) Net base energy costs billed in base rates by rate class and voltage level along with workpapers with all links and formulas intact detailing the calculation;
   3. (C) Revenues from billed FARs by voltage level along with workpapers (with formulas intact) detailing the calculation;
   4. (D) The fuel and purchased power costs and fuel related revenues for each month, year-to-date, and prior calendar year by account and any other designation ordered by the commission. If accounts, subaccounts, and other designations are not comparable to costs and revenues listed in the electric utility’s FAC tariff sheets, the electric utility shall also include the costs as listed in the tariff sheets;

   5. (E) Energy.

      1. 1. RTO market transactions—

         1. A. Revenue net of the cost of any energy purchases in

the RTO market;

1. B. MWh’s net of the MWh’s for any energy purchases in

the RTO market.

1. 2. Physical bilateral transactions—

   1. A. Total MWh’s;
   2. B. Total revenues and costs;

2. (F) Capacity.

   1. 1. If sold within an RTO market—

      1. A. MW capacity sold net of MW capacity purchased;
      2. B. Revenue received net of the cost of capacity pur-

chased.

1. 2. Third party bilateral transactions—

   1. A. Total MW;
   2. B. Total revenue and costs;
2. (G) Reason for the purchase of capacity in the RTO markets;

3. (H) The following information for the period, by generation facility, by fuel type, and by total for the electric utility:

   1. 1. Quantity of fuel burned, with the designation of the

units in which the quantity is reported (e.g., tons, MCF, MMBtu);

1. 2. MMBtu of fuel burned;
2. 3. Average cost of fuel per MMBtu, by fuel type;
3. 4. Aggregate megawatt hours (MWhs) of net energy gen-

erated by the generating facility at each generation station, where net energy generated is the gross generation net of the station use;

1. 5. Average cost of fuel per MWh;
2. 6. Excluding nuclear fuel, the cost of fuel purchased by

fuel type and, a breakdown between the cost of the commodity, cost of freight and cost of transportation by fuel type; and

1. 7. Other fuel cost types designated in the RAM.; and
2. (I) A detailed description of the accounts or other designations utilized by the electric utility or ordered by the commission, where each fuel and purchased power cost or fuel-related revenue is recorded. The report shall identify any changes since the last periodic report to accounts or other designations of costs and revenue types utilized by the utility or otherwise ordered to be used by the commission in the general rate proceeding where the RAM was approved;

3. (J) Each revision to the electric utility’s internal policy for participating in—

   1. 1. RTO ancillary services market, if the RTO in which the

electric utility participates has such a market;

1. 2. RTO energy markets by RTO;
2. 3. RTO capacity markets by RTO;
3. 4. Financial swaps or other financial-only transactions (if

such financial transactions are included in the electric utility’s RAM);

1. (K) Any additional information that the commission has ordered the electric utility to provide in its periodic reports.

1. (6) Surveillance Monitoring Reports. So long as it has a RAM in effect, each electric utility shall submit in EFIS and submit to staff, OPC, and other parties, a surveillance monitoring report with all links and formulas intact, within fifteen (15) days after each of the electric utility’s United States Securities and Exchange Commission (SEC) 10-Q and 10-K filings are due. If an electric utility with foreign ownership has a RAM but does not file with the SEC, then the surveillance monitoring reports shall be filed in quarterly intervals as identified in the electric utility’s general rate proceedings. The surveillance monitoring report shall be verified by the affidavit of an electric utility representative(s) who has knowledge of the subject matter and who attests to both the veracity of the information and his/ her knowledge of it. These surveillance monitoring reports are confidential.

   1. (A) There are six (6) parts to the electric utility surveillance monitoring report. Each part, except Part I—Rate Base Quantifications, shall contain information for the last twelve- (12-) month period and the last quarter based on total company electric operations data and on Missouri jurisdictional operations data. Part I—Rate Base Quantifications, shall contain only information as of the ending date of the period being reported. The content of the surveillance monitoring report follows:

      1. 1. Part I—Rate Base Quantifications. The quantification of

rate base items in Part I shall be consistent with the methods and procedures used in the electric utility’s most recent rate proceeding before the commission, unless otherwise specified by the commission. Part I shall consist of specific quantifications of the following rate base items:

1. A. Plant-in-service;
2. B. Reserve for depreciation;
3. C. Materials and supplies;
4. D. Cash working capital;
5. E. Fuel inventory;
6. F. Prepayments;
7. G. Other regulatory assets;
8. H. Customer advances;
9. I. Customer deposits;
10. J. Accumulated deferred income taxes;
11. K. All other items included in the electric utility’s rate

base from its most recent general rate proceeding before the commission;

1. L. Net operating income from Part III; and
2. M. Calculation of the overall return on rate base;
3. 2. Part II—Capitalization Quantifications. Part II shall

consist of specific quantifications of the following capitalization-related items:

1. A. Common stock equity (net);
2. B. Preferred stock (par or stated value outstanding);
3. C. Long-term debt (including current maturities);
4. D. Short-term debt; and
5. E. Weighted cost of capital including component costs;
6. 3. Part III—Income Statement. Part III shall consist of an

income statement containing specific quantifications of—

1. A. Operating revenues, including revenues from sales

to industrial, commercial, and residential customers, sales for resale and all other components of total operating revenues;

1. B. Operating and maintenance expenses in fuel expense,

production expense, purchased power energy, and purchased power capacity;

1. C. Transmission expense;
2. D. Distribution expense;
3. E. Customer accounts expense;
4. F. Customer service and information expense;
5. G. Sales expense;
6. H. Administrative and general expense;
7. I. Depreciation, amortization, and decommissioning

expense;

1. J. Taxes other than income taxes;
2. K. Income taxes; and
3. L. Quantification of heating degree and cooling degree

days, both actual and normal;

1. 4. Part IV—Jurisdictional Allocation Factors. Part IV shall

consist of a list of the jurisdictional allocation factors used for determining the electric utility’s rate base, capitalization quantification, and income statement;

1. 5. Part V—Financial Data Notes. Part V shall consist of

notes to the reported financial data including, but not limited to:

1. A. Out-of-period adjustments;
2. B. Specific quantification of material variances between

actual and budget financial performance;

1. C. Specific identification and quantification of material

variances between current twelve- (12-) month period and prior twelve- (12-) month period revenue;

1. D. The expense levels of each item the commission has

ordered be tracked in the RAM;

1. E. Budgeted capital projects; and
2. F. Events that materially affect debt or equity surveil-

lance components;

1. 6. Part VI—Missouri Energy Efficiency and Investment Act

(MEEIA). An electric utility with approved MEEIA demand-side management programs and/or an approved demand-side programs investment mechanism shall include all filing requirements of 4 CSR 240-20.093(10) for the entire period of program delivery approved by the commission, the last twelve- (12-) month period, and the last quarter.

1. (B) Each surveillance monitoring report shall include any additional information the commission has ordered be provided.
2. (C) If the electric utility has any other approved cost recovery mechanisms that require submission of surveillance monitoring reports, the electric utility shall submit a single surveillance monitoring report incorporating these reporting requirements for all cost recovery mechanisms.

1. (7) Budget Report. Annually the electric utility shall submit in EFIS and provide to staff, OPC, and other parties, its approved budget for the upcoming budget year, in electronic format with all links and formulas intact and in a layout similar to its surveillance monitoring report. The budget submission shall provide a quarterly and annual quantification of the electric utility’s income statement. The budget report shall be submitted within thirty (30) days of when the electric utility’s budget is approved by the electric utility’s management or within sixty
2. (60) days of the beginning of the electric utility’s fiscal year, whichever is earliest. The budget submission shall be designated “confidential” and treated accordingly.

3. (8) Periodic Changes to Fuel Adjustment Rates. An electric utility that has a FAC shall file proposed tariff sheet(s) to adjust its FARs following each accumulation period. The FARs shall be designed to bill the electric utility’s customers, in the aggregate, the FPA if the FPA is positive, or return the FPA to the utility’s customers if the FPA is negative.

   1. (A) When an electric utility files with the commission tariff sheet(s) to change its fuel adjustment rates and serves it upon parties, the filed tariff sheet(s) shall be accompanied by—

      1. 1. Prefiled testimony that shall include:

         1. A. The proposed FARs;
         2. B. The change in the FARs;
         3. C. The impact of the proposed FARs on the monthly bill

of the electric utility’s typical residential customer, together with the definition of typical residential customer used to determine that impact;

1. D. The accumulation period NBEC, ANEC, and FPA; and
2. E. An explanation that details the factors which contrib-

uted to the FPA amount.

1. 2. The following information in electronic format, where

available, with formulas intact:

1. A. For the period of historical costs which are being used

to propose the fuel adjustment rates—

1. (I) The calendar month actual energy sales in kWh by

rate class and voltage level;

1. (II) The actual fuel costs designated in the FAC, listed

by generating station and fuel type;

1. (III) The MWh and actual purchased power costs, as

purchased power is defined in the electric utility’s FAC, differentiated between energy costs and demand costs;

1. (IV) Transmission costs designated in the electric util-

ity’s FAC;

1. (V) Net off-system sales revenues;
2. (VI) Fuel-related revenues other than off-system sales

revenues separated by type of fuel-related revenue;

1. (VII) Net base energy costs collected in permanent

rates; (VIII) Any additional requirements the commission ordered;

1. (IX) Calculation of each of the proposed fuel adjust-

ment rates;

1. (X) Calculations of the voltage differentiation in the

proposed FAC rates, if any, to account for differences in line losses by service voltage level; and

1. (XI) Extraordinary costs not to be passed through, if

any, due to such costs being an insured loss, or subject to reduction due to litigation or for any other reason;

1. B. The electric utility’s monthly short-term borrowing

rate, along with—

1. (I) An explanation of how that rate was determined;
2. (II) The calculation of the short-term borrowing rate;
3. (III) Identification of any changes in the basis(es) used

for determining the short-term borrowing rate since the last FAC rate adjustment;

1. (IV) If there is a change in the basis(es) used for de-

termining the short-term borrowing rate, a copy(ies) of the changed basis(es) or identification of where it/they may be reviewed;

1. 3. Workpapers, in electronic format, where available, with

all links and formulas intact, supporting all items in paragraphs (8)(A)1. and (8)(A)2. that are not provided in the electric utility’s section (5) periodic monthly report submissions shall be submitted through EFIS and provided to staff, OPC, and other parties;

1. (B) The electric utility shall initiate a new case with an ER designation for each periodic adjustment of its FARs;
2. (C) An electric utility with a FAC shall file an adjustment to its FARs within two (2) months of the end of each accumulation period after the effective date of the FAC;

3. (D) The tariff sheets reflecting the RAM define the costs and revenues that can be included in the RAM, subject to the following:

   1. 1. If an RTO implements a new market settlement type or

schedule covering a cost or revenue that the electric utility or another party believes possesses the characteristics of, and is of the nature of, an RTO revenue or cost approved by the commission for inclusion in the electric utility’s FAC in the previous general rate proceeding, the costs or revenues covered by the new market settlement type or schedule will be included in the utility’s FAC if the following requirements are met:

1. A. The party proposing the inclusion of costs or revenues

covered by a new market settlement type or schedule shall make a filing before the commission in the case in which the electric utility’s then-current FAC was approved giving notice of the new market settlement type or schedule no later than sixty (60) days prior to the due date for the electric utility’s next FAR filing made to adjust the electric utility’s FAR;

1. B. The filing shall include, but is not be limited to:

   1. (I) Identification of the account affected by the change;
   2. (II) A description of the new market settlement type

or schedule demonstrating that the cost or revenue it covers possesses the characteristics of, and is of the nature of, a cost or revenue allowed in the electric utility’s FAC by the commission in the most recent general rate proceeding; and

1. (III) Identification of the preexisting schedule, or mar-

ket settlement type which the new settlement type or schedule replaces or supplements;

1. C. To challenge the inclusion of a new market settle-

ment type or schedule, a party shall make a filing before the commission including the reasons why it believes the electric utility did not show that the cost or revenue covered by the new market settlement type or schedule possesses the characteristics of, and is of the nature of, a cost or revenue included in the electric utility’s FAC that was approved by the commission in the preceding general rate proceeding.

1. (I) The filing shall be made within thirty (30) days of

the electric utility’s filing.

1. (II) The party requesting the inclusion of costs or

revenues covered by a new market settlement type or schedule shall bear the burden of proof to show that the costs or revenues possess the characteristics of, and are of the nature of, costs or revenues allowed in the electric utility’s FAC by the commission in the most recent general rate proceeding.

1. (III) If a party challenges the inclusion of the costs or

revenues covered by the new market settlement type or schedule, the challenge will not delay the FAR filing schedule.

1. (IV) If the challenge is upheld by the commission, the

costs will be refunded or revenues returned along with interest in the next periodic adjustment;

1. (E) The electric utility must be current on its submission of its surveillance monitoring reports;
2. (F) Staff shall review the information filed and submitted by the electric utility in accordance with this rule and additional information obtained through discovery, if any, to determine if the proposed adjustment to the FARs is in accordance with the provisions of this rule, section 386.266, RSMo, and the FAC mechanism established, continued, or modified in the utility’s most recent general rate proceeding. In filings to adjust the FAR, the twenty- (20-) and ten- (10-) day time limits in 4 CSR 240-2.090(2) shall be reduced to fifteen (15) and seven (7) days, respectively. Within thirty (30) days after the electric utility files its testimony and tariff sheet(s) to adjust its FARs, the staff shall submit a recommendation regarding its examination and analysis to the commission;
3. (G) OPC and other parties may file a response to the electric utility’s proposed FAR adjustment within forty (40) days after the electric utility files its testimony and tariff sheet(s) to adjust its FARs;

4. (H) Within sixty (60) days after the electric utility files its testimony and tariff sheet(s) to adjust its FARs, the commission shall either—

   1. 1. Issue an interim rate adjustment order approving the

tariff sheet(s) and the adjustments to the FARs;

1. 2. Allow the tariff sheet(s) and the adjustments to the FARs

to take effect without commission order; or

1. 3. If it determines the adjustment to the FARs is not in

accordance with the provisions of this rule, section 386.266, RSMo, and the FAC mechanism established in the electric utility’s most recent general rate proceeding, reject the proposed rate sheets, suspend the timeline of the FAR adjustment filing, set a prehearing date, and order the parties to propose a procedural schedule. The commission may order the electric utility to file tariff sheet(s) to implement interim adjusted FARs to reflect any part of the proposed adjustment that is not in question;

1. (I) If the staff, OPC, or other party which receives the information that the electric utility is required to submit by this rule and as ordered by the commission in a previous proceeding, believes the information is insufficient to make a recommendation regarding the electric utility’s proposed FAR, it shall notify the electric utility within ten (10) business days of the electric utility’s filing of tariff sheet(s) to adjust the FARs and identify the information required and not submitted in compliance with that rule or order. The electric utility shall supply the information identified by the party, or shall notify the party that it believes the information provided was in compliance with the requirements of this rule and the commission’s most recent order establishing, continuing, or modifying the FAC, within ten (10) business days of the request. If the electric utility does not timely supply the information, the party asserting the failure to provide the required information must timely file a motion to compel with the commission.

   1. 1. While the commission is considering the motion to

compel, the processing timeline for the adjustment to increase the FARs shall be suspended. If the commission then issues an order requiring the information be provided, the time necessary for the information to be provided shall further extend the processing timeline for the adjustment to increase the FARs. If the commission issues an order compelling discovery, interest will not be accrued by the utility from the time the commission receives a motion to compel until the time that the utility provides the requested information. For good cause shown the commission may further suspend this timeline.

1. 2. Except as provided herein, any delay in providing

sufficient information in compliance with this rule and the commission’s most recent order establishing, continuing, or modifying the FAC in a request to decrease the FARs shall not alter the processing timeline.

1. (9) True-Ups of RAMs. The purpose of a true-up case is to accurately and appropriately remedy any overbilling or under-billing during a recovery period, including the interest accrued at the utility’s short-term borrowing rate to be returned to or collected from customers through a periodic change to FAR under section (8).

   1. (A) When an electric utility files with the commission to true-up its RAM the filing shall be accompanied by—

      1. 1. Pre-filed testimony that includes a discussion detailing

the material factors which contributed to the true-up amount;

1. 2. The following information in electronic format, where

available, with all links and formulas intact:

1. A. Any revision to the calculation of the net base energy

cost for the accumulation period;

1. B. Any other proposed adjustments or refunds not re-

lated to the calculation of the net base energy cost for the accumulation period;

1. C. The calculation of the monthly amount that was over-

billed or under-billed through its RAM;

1. D. The electric utility’s monthly short-term borrowing

rate along with—

1. (I) An explanation of how that rate was determined;
2. (II) The calculation of the short-term borrowing rate;
3. (III) Identification of any changes in the basis(es) used

for determining the short-term borrowing rate since the last RAM rate adjustment; and

1. (IV) If there is a change in the basis(es) used for de-

termining the short-term borrowing rate, a copy(ies) of the changed basis(es) or identification of where it/they may be reviewed;

1. E. Any additional information that the commission has

ordered the electric utility to include in its RAM true-up filing;

1. 3. Workpapers, in electronic format, where available, with

all links and formulas intact, supporting all items in this subsection, shall be submitted in EFIS and provided to staff, OPC, and other parties.

1. (B) The electric utility shall initiate a new file in EFIS designated as an “electric other” (EO) file number for each true-up of its RAM.
2. (C) The electric utility must be current on its submission of its periodic reporting requirements as required by section (5) and surveillance monitoring reports at the time that it files its true-up of its RAM in order for the commission to process the electric utility’s requested true-up of any overor under-billing.
3. (D) The staff shall examine and analyze the information filed and submitted by the electric utility pursuant to this rule and additional information obtained through discovery and as ordered by the commission, to determine whether the true-up amount is in accordance with the provisions of this rule, section 386.266, RSMo, and the RAM established in the electric utility’s most recent general rate proceeding. In filings to adjust the FAR, the twenty- (20-) and ten- (10-) day time limits in 4 CSR 240-2.090(2) shall be reduced to fifteen (15) and seven

1. (7) days, respectively. The staff shall submit a recommendation regarding its examination and analysis to the commission not later than thirty (30) days after the electric utility files for a true-up amount.

   1. (E) OPC and other parties may file a response to the proposed true-up amount within forty (40) days of the electric utility true-up filing.

   2. (F) Within sixty (60) days of the electric utility’s true-up filing the commission shall issue an order—

      1. 1. Approving the true-up filing and the true-up amount; or
      2. 2. If it determines that the true-up amount is incorrect,

rejecting the proposed tariff sheet(s) containing the true-up amount, suspending the timeline of the true-up filing, setting a prehearing date, and ordering the parties to propose a procedural schedule. The commission shall allow the electric utility to file tariff sheet(s) to implement interim FARs reflecting any part of the true-up amount that is not in question, and questions about the correctness of the true-up amount will not delay adjustments to FAR rates unrelated to the true-up.

1. (G) If the staff, OPC or other party which receives the information that the electric utility is required to submit by this rule and as ordered by the commission in a previous proceeding, believes the information is insufficient to make a recommendation regarding the electric utility’s true-up filing, it shall notify the electric utility within ten (10) days of the electric utility’s filing and identify the information required. The electric utility shall supply the information identified by the party, or shall notify the party that it believes the information provided was responsive to the requirements, within ten (10) days of the request. If the electric utility does not timely supply the information, the party asserting the failure to provide the required information must timely file a motion to compel with the commission.

   1. 1. While the commission is considering the motion to

compel, the processing timeline for the determination of the true-up amount shall be suspended. If the commission then issues an order requiring the information to be provided, the time necessary for the information to be provided shall further extend the processing timeline. If the commission issues an order compelling discovery, interest will not be accrued by the utility from the time the commission receives a motion to compel until the time that the utility provides the requested information. For good cause shown the commission may further suspend this timeline.

1. 2. If the party requesting the information can demonstrate

to the commission that the true-up amount will result in a reduction in the FAR, the processing timeline shall continue with the best information available. When the electric utility provides the necessary information, the FAR shall be adjusted again, if necessary, to reflect the additional information provided by the electric utility.

1. (10) Duration of RAMs and Requirement for General Rate Case. Once a RAM is approved by the commission, it shall remain in effect for a term of not more than four (4) years unless the commission earlier authorizes the modification, extension, or discontinuance of the RAM in a general rate proceeding, although an electric utility may submit proposed rate sheets to implement periodic adjustments to its FAC rates between general rate proceedings.

   1. (A) If the commission approves a RAM for an electric utility, the electric utility must file a general rate case with the effective date of new rates to be no later than four (4) years after the effective date of the commission order implementing the RAM, assuming the maximum statutory suspension of the rates so filed.

      1. 1. The four- (4-) year period shall not include any periods

in which the electric utility is prohibited from collecting any charges under the RAM, or any period for which charges collected under the RAM must be fully refunded. In the event a court determines that the RAM is unlawful and all monies collected are fully refunded as a result of such a decision, the electric utility shall be relieved of any obligation to file a general rate case. The term fully refunded as used in this section does not include amounts refunded as a result of reductions in fuel or purchased power costs minus fuel-related revenues or prudence adjustments.

1. (11) Prudence Reviews Respecting RAMs. A prudence review of the costs and revenues subject to the RAM shall be conducted no less frequently than at eighteen- (18-) month intervals.

   1. (A) All amounts ordered refunded by the commission shall include interest at the electric utility’s short-term borrowing rate.

   2. (B) The staff shall file notice within ten (10) days of starting its prudence review and shall submit a recommendation regarding its examination and analysis to the commission not later than one hundred eighty (180) days after initiating its prudence review. Parties to the prudence review proceeding shall have ten (10) days after the staff files its recommendation to request a hearing. The commission shall issue an order not later than thirty (30) days after the staff files its recommendation if no party requests a hearing.

      1. 1. If the staff, OPC, or other party auditing the RAM believes

that insufficient information has been supplied to make a recommendation regarding the prudence of the electric utility’s RAM, it may utilize discovery to obtain the information it seeks. If the electric utility does not timely supply the information, the party asserting the failure to provide the required information must timely file a motion to compel with the commission. While the commission is considering the motion to compel the processing timeline shall be suspended. If the commission then issues an order requiring the information to be provided, the time necessary for the information to be provided shall further extend the processing timeline. For good cause shown the commission may further suspend this timeline.

1. 2. If the timeline is extended due to an electric utility’s

failure to timely provide sufficient responses to discovery and a refund is due to the customers, the electric utility shall refund all imprudently incurred costs plus interest at the electric utility’s short-term borrowing rate.

1. (12) Disclosure on Customers’ Bills. Any amounts charged under a commission-approved RAM shall be separately disclosed on each customer’s bill. Proposed language regarding this disclosure shall be submitted to the commission for the commission’s approval in the general rate proceeding establishing, modifying, or continuing the RAM.

2. (13) Rate Design of the RAM. The design of the RAM rates shall reflect differences in losses incurred in the delivery of electricity at different voltage levels for the electric utility’s different rate classes as determined by periodically conducting Missouri jurisdictional system loss studies.

   1. (A) When the electric utility initially seeks authority to use a RAM, the end of the twelve- (12-) month period of actual data collected that is used in its Missouri jurisdictional system loss study must be within twenty-four (24) months of the date the utility files its general rate proceeding first requesting a RAM.
   2. (B) When the electric utility seeks to continue or modify its RAM, the end of the twelve- (12-) month period of actual data collected that is used in its Missouri jurisdictional system loss study must be no earlier than four (4) years before the date the utility files the general rate proceeding seeking to continue or modify its RAM.

3. (14) Incentive Mechanism or Performance-Based Program. During a general rate proceeding in which an electric utility has proposed establishment or modification of a RAM, or in which a RAM may be allowed to continue in effect, any party may propose for the commission’s consideration incentive mechanisms or performancebased programs to improve the efficiency and cost effectiveness of the electric utility’s fuel and purchased power procurement activities and/or off-system sales activities.

   1. (A) The incentive mechanisms or performance-based programs may or may not include some or all components of base energy costs.
   2. (B) Any incentive mechanism or performance-based program shall be structured to align the interests of the electric utility’s customers and shareholders. The anticipated benefits to the electric utility’s customers from the incentive or performance-based program shall equal or exceed the anticipated costs of the mechanism or program to the electric utility’s customers. Customer rates shall include the cost of an incentive mechanism or performance-based program in any time period above what they would be without the incentive mechanism or performance-based program.
   3. (C) If the commission approves an incentive mechanism or performance-based program, such incentive mechanism or performance-based program shall be binding on the commission for the entire term of the incentive mechanism or performance-based program. If the commission approves an incentive mechanism or performance-based program, such incentive mechanism or performance based program shall be binding on the electric utility for the entire term of the incentive mechanism or performance-based program unless otherwise ordered or conditioned by the commission.

4. (15) Pre-Existing Adjustment Mechanisms, Tariffs, and Regulatory Plans. The provisions of this rule shall not affect—

   1. (A) Any adjustment mechanism, tariff, incentive plan, or other ratemaking mechanism that was approved by the commission and in effect prior to the effective date of this rule; and
   2. (B) Any experimental regulatory plan that was approved by the commission and in effect prior to the effective date of this rule.
5. (16) Nothing in this rule shall preclude a complaint case from being filed, as provided by law. If a complaint is filed on the grounds that an electric utility is acting in violation of its approved RAM tariff sheets or on the grounds that its rates have become unjust and unreasonable, the commission shall issue a procedural schedule that includes a clear delineation of the case timeline no later than sixty (60) days from the date the complaint is filed.

6. (17) Party status and rights in RAM proceedings.

   1. (A) Each party to the most recent general rate proceeding in which the commission established, continued, or modified the electric utility’s RAM shall be a party to each subsequent related RAM rate adjustment proceeding, RAM true-up proceeding, and RAM prudence review proceeding, without applying to the commission for intervention, and shall be provided access to the periodic reports and surveillance monitoring reports required by this rule during the period of time when they are entitled to be a party to such proceedings without applying for intervention. In any subsequent general rate proceeding, such person or entity must seek and be granted status as an intervenor to be a party to that case and to consequently be a party, without seeking and being granted status as an intervenor to RAM-related proceedings initiated after that case.
   2. (B) Anyone may seek to intervene, pursuant to 4 CSR 240- 2.075, in any RAM rate adjustment proceeding, RAM true-up proceeding, RAM prudence review proceeding, or general rate proceeding to modify, continue, or discontinue a RAM. If no party objects to the intervention request within ten (10) days of when it is filed, then the applicant for intervention shall be deemed to have been granted intervention without a specific commission order, unless within the above-referenced ten- (10-) day period the commission denies the application for intervention on its own motion. If an objection to the application for intervention is filed on or before the end of the above-referenced ten- (10-) day period, the commission shall rule on the application and the objection within ten (10) days of the filing of the objection.
7. (18) Discovery. Each discovery response that a party obtains in general rate proceedings where the commission approves, modifies, rejects, continues, or discontinues a RAM and in related subsequent RAM rate adjustment proceedings, RAM true-up proceedings, and RAM prudence review proceedings may be offered as evidence in any subsequent RAM rate adjustment proceeding, RAM true-up proceeding, RAM prudence review proceeding, or general rate proceeding to modify, continue, or discontinue its RAM as if the response were made to a discovery request in that proceeding without requiring the party who made the request to resubmit the same discovery request (data request, interrogatory, request for production, request for admission, or deposition), subject to commission ruling on any evidentiary objection(s). Unless the commission orders otherwise, sua sponte or on a party’s motion, the discovery response shall have the same protection it was last afforded, by rule or by commission order.
8. (19) Supplementing and updating discovery responses in subsequent related proceedings. A party who provided a discovery response in a prior case as described in section (18) shall be under no obligation to supplement or update that response in a subsequent proceeding, unless the requesting party issues a discovery request in the subsequent case which clearly identifies the particular discovery requests to be supplemented or updated and the particular period to be covered by the updated response. A party responding to a request to supplement or update a prior proceeding discovery response shall supplement or update the discovery response where the responding party has learned or subsequently learns its response is in some material respect insufficiently detailed or incorrect.
9. (20) The commission shall establish a new case for each general rate proceeding, RAM rate adjustment proceeding, RAM true-up proceeding, and RAM prudence review proceeding.
10. (21) Right to Discovery Unaffected. In addressing certain discovery matters and the provision of certain information by electric utilities, this rule is not intended to restrict the discovery rights of any party.
11. (22) Waiver of Provisions of this Rule. Provisions of this rule may be waived by the commission for good cause.

AUTHORITY: sections 386.250, 386.266, and 393.140, RSMo 2016.* This rule originally filed as 4 CSR 240-20.090. Original rule filed June 15, 2006, effective Jan. 30, 2007. Amended: Filed May 24, 2018, effective Jan. 30, 2019. Moved to 20 CSR 4240-20.090, effective Aug. 28, 2019. *Original authority: 386.250, RSMo 1939, amended 1963, 1967, 1977, 1980, 1987, 1988, 1991, 1993, 1995, 1996; 386.266, RSMo 2005; and 393.140, RSMo 1939, amended 1949, 1967.