ARC 5475C

ARC 5475C

UTILITIES DIVISION[199]

Notice of Intended Action

Proposing rule making related to electric utility service

and providing an opportunity for public comment

The Utilities Board hereby proposes to amend Chapter 20, "Service Supplied by Electric Utilities," Iowa Administrative Code.

Legal Authority for Rule Making

This rule making is proposed under the authority provided in Iowa Code sections 476.2 and 476.6(8)"b."

State or Federal Law Implemented

This rule making implements, in whole or in part, Iowa Code chapter 476.

Purpose and Summary

The purpose of this rule making is to update the Board's electric utility service rules and establish requirements for the pass-through of federally approved electric transmission costs. The proposed amendments clarify Board rules regarding pass-through of energy costs to customers and simplify reliability requirements. In addition, the amendments remove electric cooperatives and municipal electric utilities from regulation under Chapter 20. The Board has proposed a new chapter, which was published in the Iowa Administrative Bulletin on November 18, 2020, as ARC 5281C, to regulate those utilities.

The Board issued an Order Commencing Rule Making on February 12, 2021. The order is available on the Board's electronic filing system, efs.iowa.gov, under Docket No. RMU-2019-0020.

Fiscal Impact

The proposed updates of Chapter 20 do not significantly change the rules for rate-regulated electric utilities from current rules and so should not have a significant fiscal impact.

Jobs Impact

After analysis and review of this rule making, no impact on jobs has been found.

Waivers

No waiver provision is included in the proposed amendments because the Board has a general waiver provision in rule 199—1.3(17A,474,476) that provides procedures for requesting a waiver of the rules in Chapter 20.

Public Comment

Any interested person may submit written comments concerning this proposed rule making. Written comments in response to this rule making must be received by the Board no later than 4:30 p.m. on March 16, 2021. Comments should be directed to:

Public Hearing

An oral presentation at which persons may present their views orally or in writing will be held as follows:

Persons who wish to make oral comments at the oral presentation may be asked to state their names for the record and to confine their remarks to the subject of this proposed rule making.

Any persons who intend to attend the oral presentation and have special requirements, such as those related to hearing or mobility impairments, should contact the Board and advise of specific needs.

Review by Administrative Rules Review Committee

The Administrative Rules Review Committee, a bipartisan legislative committee which oversees rule making by executive branch agencies, may, on its own motion or on written request by any individual or group, review this rule making at its regular monthly meeting or at a special meeting. The Committee's meetings are open to the public, and interested persons may be heard as provided in Iowa Code section 17A.8(6).

The following rule-making actions are proposed:

Item 1. Amend 199—Chapter 20, title, as follows:

SERVICE SUPPLIED BY ELECTRIC UTILITIES REQUIRED TO BE RATE-REGULATED

Item 2. Amend rule 199—20.1(476) as follows:

199—20.1(476) General information.

20.1(1) Authorization of rules. Iowa Code chapter 476 provides that the Iowa utilities board shall establish all needful, just and reasonable rules, not inconsistent with law, to govern the exercise of its powers and duties, the practice and procedure before it, and to govern the form, content and filing of reports, documents and other papers necessary to carry out the provisions of this law.

a.Iowa Code chapter 478 provides that the Iowa utilities board shall have power to make and enforce rules relating to the location, construction, operation and maintenance of certain electrical transmission lines.

The application of the rules in this chapter to municipally owned utilities furnishing electricity is limited by Iowa Code section 476.1B, and the application of the rules in this chapter to electric utilities with fewer than 10,000 customers and to electric cooperative associations is limited by the provisions of Iowa Code section 476.1A.

b. Electric utilities with fewer than 10,000 customers subject to board regulation pursuant to Iowa Code section 476.1A are subject to the regulatory requirements set out in 199—Chapter 27 for electric cooperatives.

20.1(2) Application of rules. The rules shall apply to any electric utility required to be rate-regulated operating within the state of Iowa subject to Iowa Code chapter 476, and to the construction, operation and maintenance of electric transmission lines to the extent provided in Iowa Code chapter 478, and shall supersede all tariffs on file with the board which are in conflict with these rules.

a.These rules are intended to promote safe and adequate service to the public, to provide standards for uniform and reasonable practices by utilities, and to establish a basis for determining the reasonableness of such demands as may be made by the public upon the utilities.

b.A request to waive the application of any rule on a permanent or temporary basis may be made in accordance with 199—1.3(17A,474,476).

c.The adoption of these rules shall in no way preclude the board from altering or amending them pursuant to statute or from making such modifications with respect to their application as may be found necessary to meet exceptional conditions.

d.These rules shall in no way relieve any utility from any of its duties under the laws of this state.

20.1(3) and 20.1(4) No change.

Item 3. Amend subrule 20.2(2) as follows:

20.2(2) Tariffs to be filed with the board. The schedules of rates and rules of rate-regulated electric utilities shall be filed with the board and shall be classified, designated, arranged and submitted so as to conform to the requirements of this chapter. Provisions of the schedules shall be definite and so stated as to minimize ambiguity or the possibility of misinterpretation. The form, identification and content of tariffs shall be in accordance with these rules. A rate-regulated electric utility's current tariff will be made available through the board's electronic filing system.

Utilities which are not subject to the rate regulation provided for by Iowa Code chapter 476 shall not be required to file schedules of rates, rules, or contracts primarily concerned with a rate schedule with the board and shall not be subject to the provisions related to rate regulations, but nothing contained in these rules shall be deemed to relieve any utility of the requirement of furnishing any of these same schedules or contracts which are needed by the board in the performance of the board's duties upon request to do so by the board.

Item 4. Amend subrule 20.3(8) as follows:

20.3(8) Service areas. Service areas are defined by the boundaries on service area maps. Paper Electronic maps are available for viewing during regular business hours at the board's offices and available for purchase at the cost of reproduction. Maps are also available for viewing on the board's website. These service area maps are adopted as part of this rule and are incorporated in this rule by this reference.

Item 5. Amend subrule 20.3(9) as follows:

20.3(9) Petition for modification Modification of service area and answers.

a.An exclusive service area is subject to modification through a contested case proceeding which may be commenced by filing a petition for modification of service area with the board. The board may commence a service area modification proceeding on its own motion.

b.Any electric utility or municipal corporation may file a petition for modification of service area , which shall contain (1) a legal description of the service area desired, (2) a designation of the utilities involved in each boundary section, and(3) a justification for the proposed service area modification, and (4) an electronic file, containing geospatial data, in a format compatible with geographic information system (GIS) software such as a shapefile file, geodatabase, or KML file, of the proposed service area boundaries. The justification shall include a detailed statement of why the proposed modification is in the public interest. A map showing the affected areas which complies with paragraph 20.3(11)"a" shall be attached to the petition as an exhibit.

c.Filing of the petition with the board, and service to other parties, shall be in accordance with 199—Chapter 14.

d.All parties shall file an An answer which complies to a petition for a service area modification shall comply with 199—subrule 7.5(1) 199—subrule 7.9(2).

e. Electric utilities may agree to service area modifications by contract pursuant to Iowa Code section 476.25(2). Contracts to be enforceable require board approval. The board shall approve a contract if the board finds that the contract will eliminate or avoid unnecessary duplication of facilities, will provide adequate electric service to all areas and customers affected, will promote the efficient and economical use and development of the electric systems of the contracting utilities, and is in the public interest.

Item 6. Amend subrule 20.4(2) as follows:

20.4(2) Customer contact employee qualifications. Each utility shall promptly and courteously resolve inquiries for information or complaints. Employees who receive customer telephone calls and office visits shall be qualified and trained in screening and resolving complaints, to avoid a preliminary recitation of the entire complaint to employees without ability and authority to act. The employee shall provide identification to the customer that will enable the customer to reach that employee again if needed.

a.Each utility shall notify its customers, by bill insert or notice on the bill form, of the address and telephone number where a utility representative qualified to assist in resolving the complaint can be reached. The bill insert or notice shall also include the following statement: "If (utility name) does not resolve your complaint, you may request assistance from the Iowa Utilities Board by calling (515)725-7321, or toll-free 1-877-565-4450, or by writing to 1375 E. Court Avenue, Des Moines, Iowa 50319-0069, or by email to customer@iub.iowa.gov."

The bill insert or notice for municipal utilities shall include the following statement: "If your complaint is related to service disconnection, safety, or renewable energy, and (utility name) does not resolve your complaint, you may request assistance from the Iowa Utilities Board by calling (515)725-7321, or toll-free 1-877-565-4450, by writing to 1375 E. Court Avenue, Des Moines, Iowa 50319-0069, or by email to customer@iub.iowa.gov."

The bill insert or notice for non-rate-regulated rural electric cooperatives shall include the following statement: "If your complaint is related to the (utility name) service rather than its rates, and (utility name) does not resolve your complaint, you may request assistance from the Iowa Utilities Board by calling (515)725-7321, or toll-free 1-877-565-4450, by writing to 1375 E. Court Avenue, Des Moines, Iowa 50319-0069, or by email to customer@iub.iowa.gov."

b.The bill insert or notice on the bill shall be provided monthly by utilities serving more than 50,000 Iowa retail customers and no less than annually by all other electric utilities. Any utility which does not use the standard statement described in this subrule shall file its proposed statement in its tariff for approval. A utility that bills by postcard may place an advertisement in a local newspaper of general circulation or a customer newsletter instead of a mailing. The advertisement must be of a type size that is easily legible and conspicuous and must contain the information set forth above.

Item 7. Amend subparagraph 20.4(15)"d"(3), question 3, as follows:

3. How do I apply for low-income energy assistance? (Residential customers only)

a. Contact the local community action agency in your area (see attached list) or visit humanrights.iowa.gov/dcaa/where-apply contact the division of community action agencies at the Iowa Department of Human Rights, Lucas State Office Building, Des Moines, Iowa 50319; telephone (515)281-3861. To prevent disconnection, you must contact the utility prior to disconnection of your service.

b. To avoid disconnection, you must apply for energy assistance or weatherization before your service is shut off. Notify your utility that you may be eligible and have applied for energy assistance. Once your service has been disconnected, it will not be reconnected based on approval for energy assistance.

c. Being certified eligible for energy assistance will prevent your service from being disconnected from November 1 through April 1.

d. If you have additional questions, contact the Division of Community Action Agencies at the Iowa Department of Human Rights, Lucas State Office Building, Des Moines, Iowa 50319; telephone (515)281-3861.

Item 8. Amend subrule 20.8(1) as follows:

20.8(1) Protective measures. Each utility shall exercise reasonable care to reduce those hazards inherent in connection with its utility service and to which its employees, its customers, and the general public may be subjected and shall adopt and execute a safety program designed to protect the public and fitted to the size and type of its operations. A utility shall include in its safety program procedures for notifying the board and the public of an incident involving a component of a wind turbine, solar facility, storage facility, or any other generating facility where the incident has affected adjacent property owners or members of the public.

Item 9. Amend rule 199—20.9(476) as follows:

199—20.9(476) Electric energy sliding scale or automatic adjustment. A rate-regulated utility's sliding scale or automatic The electric energy adjustment of the unit charge for electric energy shall be an energy adjustment clause.

20.9(1) Applicability. A rate-regulated utility's sliding scale or automatic electric energy adjustment of electric utility energy rates shall recover from consumers only those costs which:

a.Are incurred in supplying energy;

b.Are beyond direct control of management;

c.Are subject to sudden important change in level;

d.Are an important factor in determining the total cost to serve; and

e.Are readily, precisely, and continuously segregated in the accounts of the utility.

20.9(2) Energy adjustment clause for rate-regulated utility. Prior to each billing cycle any period in which a utility proposes to change the adjustment amount for each energy unit delivered to the customer, a rate-regulated the utility shall determine and file for board approval the adjustment amount to be charged for each energy unit consumed delivered under rates set by the board. The filing shall include all journal entries, invoices (except invoices for fuel, freight, and transportation), worksheets, and detailed supporting data used to determine the amount of the adjustment. Spreadsheets, workbooks, and databases included in filings shall include all cell formulae and cell references. The estimated amount of fossil fuel should be detailed to reflect the amount of fuel, transportation, emission allowances, and other costs.

a.The utility shall keep and maintain journal entries should reflect the following to reflect a breakdown for each type of fuel: actual cost of fuel, transportation costs, and other costs. Items identified as other costs should be described and their inclusion as fuel costs should be justified must be approved by the board. The board may direct that journal entries be filed. The utility shall also file detailed supporting data:

1. (1)To show the actual amount of sales of energy by month for which an adjustment was utilized, and

2. (2)To support the energy cost adjustment balance utilized in the monthly energy adjustment clause filings.

a. b.The energy adjustment shall provide for change of the price per kilowatt hour consumed kilowatt-hour delivered under rates set by the board based upon the formulas provided below in the utility's tariff. The energy adjustment factor shall be rounded on a consistent basis to either the nearest 0.01¢/kWh or 0.001¢/kWh. The tariff shall define the components of the formula(s) and shall include reference to the specific accounts of the Uniform System of Accounts for each component.

(1)For each period as specified in the tariff, the calculation shall be include but not be limited to:

E0 is the energy adjustment charge to be used in the next customer billing cycle rounded on a consistent basis to either the nearest 0.01¢/kWh or 0.001¢/kWh. For deliveries at voltages higher than secondary line voltages, appropriate factors should be applied to the adjustment charge to recognize the lower losses associated with these deliveries.

EC0 is the estimated expense for energy in the month during which E0 will be used.

EC1 is the estimated expense for energy in the month prior to the month of EC0.

EQ0 is the estimated electric energy to be consumed or delivered and entered in accounts 440, 442, 444-7, excluding energy from distinct interchange deliveries entered into account 447 and including intrautility energy service as included in accounts 448 and 929 of the Uniform System of Accounts during the month in which E0 will be used.

EQ1 is the estimated electric energy to be consumed or delivered and entered in accounts 440, 442, 444-7, excluding energy from distinct interchange deliveries entered in account 447 and including intrautility energy service as included in accounts 448 and 929 of the Uniform System of Accounts during the month prior to EQ0.

EJ0 is the estimated electric energy to be consumed under rates set by the board in the month during which the energy adjustment charge (E0) will be used in bill calculations.

EJ1 is the estimated electric energy to be consumed under rates set by the board in the month prior to the month of EJ0.

A1 is the beginning of the month energy cost adjustment account balance for the month of estimated consumption EJ1. This would be the most recent month's balance available from actual accounting data.

B is the amount of the electric energy cost included in the base rates of a utility's rate schedules.

1.The estimated energy cost and revenues;

2.The estimated electric energy to be delivered and entered in accounts 440, 442, and 444-7, excluding energy from distinct interchange deliveries entered into account 447, and including intrautility energy service as included in accounts 448 and 929 of the Uniform System of Accounts during the month in which the energy adjustment charge will be used; and

3.The energy cost adjustment account balance.

(2)The base formula for the energy adjustment factor shall be:

Energy adjustment factor = (energy cost adjustment account balance + estimated energy costs and revenues) / estimated energy delivered

b. c.The estimated energy cost (EC0 + EC1) and revenues shall be the estimated cost and revenues associated with EQ0 and EQ1 determined as the cost of:

(1)Fossil and nuclear fuel consumed in the utility's own plants and the utility's share of fossil and nuclear fuel consumed in jointly owned or leased plants. Fossil fuel shall include natural gas used for electric generation and the cost of fossil fuel transferred from account 151 to account 501 or 547 of the Uniform System of Accounts for Electric Utilities. Nuclear fuel shall be that shown in account 518 of the Uniform System of Accounts except that if account 518 contains any expense for fossil fuel which has already been included in the cost of fossil fuel, it shall be deducted from the account. (Paragraph C of account 518 includes the cost of other fuels used for ancillary steam facilities.)

(2)The cost of steam purchased, or transferred from another department of the utility or from others under a joint facility operating agreement, for use in prime movers producing electric energy (accounts 503 and 521).

(3)A deduction shall be made of the expenses of producing steam chargeable to others, to other utility departments under a joint operating agreement, or to other electric accounts outside the steam generation group of accounts (accounts 504 and 522).

(4)The cost of water used for hydraulic power generation. Water cost shall be limited to items of account 536 of the Uniform System of Accounts. For pumped storage projects , the energy cost of pumping is included. Pumping energy cost shall be determined from the applicable costs of subparagraphs of paragraph 20.9(2)"b." 20.9(2)"c."

(5)The energy costs paid for energy purchased under arrangements or contracts for capacity and energy, as entered into account 555 of the Uniform System of Accounts, less the energy revenues to be recovered from corresponding sales, as entered in account 447 of the Uniform System of Accounts.

(6)Purchases from AEP alternative energy production facilities under rule 199—15.11(476).

(7)The weighted average costs of inventoried allowances used in generating electricity.

(8)The gains and losses, as described in subrule 20.17(9), from allowance transactions occurring during the month. Allowance transactions shall include vintage trades and emission for emission trades.

(9)Eligible costs or credits associated with the utility's annual reconciliation of its alternate energy purchase program under 199—paragraph 15.17(4)"b."

(10)Federal production tax credits unless the board approves different ratemaking treatment.

(11)Other costs and revenues as specified in the utility's tariff and approved by the board. For all other costs and revenues, the utility shall provide the type of cost, the dollar amount, and reference to the board order approving the cost to be included in the energy adjustment clause (EAC).

c. d.The energy cost adjustment account balance (A) shall be the cumulative balance of any excess or deficiency which arises out of the difference between board recognized energy cost recovery and the amount recovered through application of energy charges to consumption under rates set by the board. Each monthly entry (D) into the energy cost adjustment account shall be the dollar amount determined from solution of the following equation (with proper adjustment for those deliveries at high voltage which for billing purposes recognized the lower losses associated with the high voltage deliveries). The calculation for the energy cost adjustment account balances shall include but is not limited to:

C2 is the actual expense for energy, calculated as set forth in 20.9(2)"b," in the month prior to EJ1 of 20.9(2)"a."

J2 is the actual energy consumed in the prior month under rates set by the board and recorded in accounts 440, 442 and 444-6 of the Uniform System of Accounts.

Q2 is the actual total energy consumed or delivered in the prior month and recorded in accounts 440, 442, 444-7, excluding energy from distinct interchange deliveries entered in account 447, and including intrautility energy service as included in accounts 448 and 929 of the Uniform System of Accounts.

E2 is the energy adjustment charge used for billing in the prior month.

B is the amount of the electric energy cost included in the base rates of a utility's rate schedules.

(1)The actual energy expense for the prior period and recorded in accounts 440, 442 and 444-6 of the Uniform System of Accounts;

(2)The actual electric energy delivered for the prior period and recorded in accounts 440, 442, and 444-7, excluding energy from distinct interchange deliveries entered into account 447, and including intrautility energy service as included in accounts 448 and 929 of the Uniform System of Accounts; and

(3)The beginning energy cost adjustment account balance (overrecovered or underrecovered amount) for the current period.

d. e.Reserve account for nuclear generation. A rate-regulated utility owning nuclear generation or purchasing energy under a participation power agreement on nuclear generation may establish a reserve account. The reserve account will spread the higher cost of energy used to replace that the energy normally received from nuclear sources. A surcharge would be added to each kilowatt hour kilowatt-hour from the nuclear source. The surcharges collected are credited to the reserve account. During an outage or reduced level of operation, replacement energy cost would be offset through debit to the reserve account. The debit would be based upon the cost differential between replacement energy cost and the average cost (including the surcharge) of energy from the nuclear capacity. A reserve account shall have credit and debit limitations equal in dollar amounts to the total cost differential for replacement energy during a normal refueling outage.

e. f.A rate-regulated utility desiring to collect expensed allowance costs and the gains and losses from allowance transactions through the energy adjustment must file with the board monthly reports including:

(1)The number and weighted average unit cost of allowances used during the month to offset emissions from the utility's affected units;

(2)The number and unit price of allowances purchased during the month;

(3)The number and unit price of allowances sold during the month;

(4)The weighted average unit cost of allowances remaining in inventory;

(5)The dollar amount of any gain from an allowance sale occurring during the month;

(6)The dollar amount of any loss from an allowance sale occurring during the month; and

(7)Documentation of any gain or loss from an allowance sale occurring during the month.

f. g.A rate-regulated utility which proposes a new sliding scale or automatic adjustment clause of electric utility energy rates shall conform such clause with the rules The energy adjustment clause factor may include other automatic adjustment mechanisms as approved by the board.

20.9(3) Optional energy clause for a rate-regulated utility which does not own generation Utilities not making monthly changes to the adjustment amount. A rate-regulated utility which does not own generation may adopt the energy adjustment clause of this subrule in lieu of that set forth in subrule 20.9(2). Prior to each billing cycle, the rate-regulated utility shall determine and file for board approval the adjustment amount to be charged for each energy unit consumed under rates set by the board. The filing shall include all journal entries, invoices (except invoices for fuel, freight, and transportation), worksheets, and detailed supporting data used to determine the amount of the adjustment. The items identified as other costs should be described and their inclusion as energy costs should be justified. The utility shall also file detailed supporting data Utilities that do not file monthly adjustments shall:

1.To show the actual amount of sales of energy by month for which an adjustment was utilized, and

2.To support the energy cost adjustment balance utilized in the monthly energy adjustment clause filings.

a. The energy adjustment charge shall provide for change of the price per kilowatt-hour consumed to equal the average cost per kilowatt hour delivered by the utility's system. The calculation shall be:

E0 is the energy adjustment charge to be used in the next customer billing cycle rounded on a consistent basis to either the nearest 0.01¢/kWh or 0.001¢/kWh. For deliveries at voltages higher than secondary line voltages, appropriate factors should be applied to the adjustment charge to recognize the lower losses associated with these deliveries.

C2, C3 and C4 are the charges by the wholesale suppliers as recorded in account 555 offset by energy revenues from distinct interchange deliveries entered in account 447 of the Uniform System of Accounts for the first three of the four months prior to the month in which E0 will be used.

Q2, Q3 and Q4 are the total electric energy delivered by the utility system, excluding energy from distinct interchange deliveries entered in account 447 during each of the months in which the expenses C2, C3 and C4 were incurred.

B is the amount of the electric energy cost included in the base rates of a utility's rate schedules.

b. A utility purchasing its total electric energy requirements may establish an energy cost adjustment account for which the cumulative balance is the excess or deficiency arising from the difference between commission-recognized energy cost recovery and the amount recovered through application of energy charges on jurisdictional consumption.

For a utility electing to use an energy cost adjustment account the calculation shall be:

E0 is the energy adjustment charge to be used in the next customer billing cycle rounded on a consistent basis to either the nearest 0.01¢/kWh or 0.001¢/kWh. For deliveries at voltages higher than secondary line voltages, appropriate factors should be applied to the adjustment charge to recognize the lower losses associated with these deliveries.

C2, C3 and C4 are the charges by the wholesale suppliers as recorded in account 555 offset by energy revenues from distinct interchange deliveries entered in account 447 of the Uniform System of Accounts for the first three of the four months prior to the month in which E0 will be used.

Q2, Q3 and Q4 are the total electric energy delivered by the utility system, excluding energy from distinct interchange deliveries entered in account 447 during each of the months in which the expenses C2, C3 and C4 were incurred.

A2 is the end of the month energy cost adjustment account balance for the month of consumption J2. This would be the most recent month's balance available from actual accounting data.

J2, J3 and J4 are electric energy consumed under rates set by the board in the months corresponding to C2, C3 and C4.

B is the amount of the electric energy cost included in the base rates of a utility's rate schedules.

c. The end of the month energy cost adjustment account balance (A) shall be the cumulative balance of any excess or deficiency which arises out of the difference between board recognized energy cost recovery and the amount recovered through application of energy charges to consumption under rates set by the board.

Each monthly entry (D) into the energy cost adjustment account shall be the dollar amount determined from solution of the following equation (with proper adjustment for those deliveries at high voltage which for billing purposes recognized the lower losses associated with the high voltage deliveries).

C2 is the prior month charges by the wholesale suppliers as recorded in account 555 of the Uniform System of Accounts offset by energy revenues from distinct interchange deliveries entered in account 447.

J2 is the electric energy consumed under jurisdictional rates in the prior month.

Q2 is the electric energy delivered by the utility system, excluding energy from distinct interchange deliveries entered in account 447 in the prior month.

E2 is the energy adjustment charge used for billing in the prior month.

B is the amount of the electric energy cost included in the base rates of a utility's rate schedules.

d. A utility with special conditions may petition the board for a waiver which would recognize its unique circumstances.

e. A utility which does not own generation and proposes a new sliding scale or automatic adjustment clause of electric utility rates shall conform such clause with the rules.

a. File the information pursuant to subrule 20.9(2) on a quarterly basis.

b. File an annual reconciliation of the EAC factor and an update to the EAC factor. The date of the annual reconciliation and update shall be specified in the utility's tariff. The reconciliation shall follow the requirements of subrule 20.9(2).

c. Include a semiannual adjustment if the absolute value of the cumulative over recovery or under recovery amount is greater than 20 percent of the forecasted net recoverable energy costs for the EAC year. The semiannual adjustment filing shall be filed six months after the annual reconciliation and update filing and shall follow the requirements of subrule 20.9(2), but will be limited to the remaining months of the year. The semiannual factor updates may utilize updated forecasts for the costs and sales for the remainder of the year.

20.9(4) Review of energy adjustment clause. At least biennially, but no more than annually, the board will shall require each utility that owns generation and utilizes an energy adjustment clause to provide fuel, freight, and transportation invoices from two months of the previous calendar year. The utility shall include an explanation of and demonstrate how these invoices correspond to the energy adjustment clause calculations. The explanation shall include storage injections and withdrawals and average cost of fuel and transportation included in the energy adjustment clause calculations. The board will notify each utility by May 1 as to which two months' invoices will be required. Two copies of these These invoices shall be filed with the board no later than the subsequent November 1.

This rule is intended to implement Iowa Code section 476.6(12).

Item 10. Adopt the following new rule 199—20.16(476):

199—20.16(476) Exterior flood lighting.

20.16(1) Newly installed lighting. All newly installed public utility-owned exterior flood lighting shall be solid-state lighting or lighting with equivalent or better energy efficiency.

20.16(2) In-service lighting replacement schedule. In-service lighting shall be replaced with solid-state lighting or lighting with equivalent or better energy efficiency when worn out due to ballast, lamp, or fixture failure for any other reason, such as vandalism or storm damage.

20.16(3) Efficacy standards. Lighting other than solid-state has equivalent or better efficacy if one or more of the following can be established:

a. For fixtures, the mean lumens-per-watt lamp rating is greater than 100; or

b. The new lighting uses no more energy per installation than comparable, suitably sized solid-state; or

c. The new lighting luminaries have a mean efficacy rating equal to or greater than 100 lumens per watt according to a Department of Energy (DOE) Lighting Facts label, testing under the DOE Commercially Available LED Product Evaluation and Reporting Program (CALiPER), Design Lights Consortium (DLC) or any other testing agency that follows Illuminating Engineering Society of North America LM-79-08 test procedures.

Item 11. Amend rule 199—20.18(476,478) as follows:

199—20.18(476,478) Service reliability requirements for electric utilities.

20.18(1) Applicability. This rule is applicable to investor-owned electric utilities and electric cooperative corporations and associations operating within the state of Iowa subject to Iowa Code chapter 476 and to the construction, operation, and maintenance of electric transmission lines by electric utilities as defined in subrule 20.18(4) to the extent provided in Iowa Code chapter 478.

20.18(2) Purpose and scope. Reliable electric service is of high importance to the health, safety, and welfare of the citizens of Iowa. The purpose of this rule is to establish requirements for assessing the standards of reliability of the transmission and distribution systems and facilities that are under the board's jurisdiction. This rule establishes reporting requirements to provide consumers, the board, and electric utilities with methodology for monitoring reliability and ensuring quality of electric service within an electric utility's operating area. This rule provides definitions and requirements for maintenance of interruption data, retention of records, and report filing.

20.18(3) General obligations.

a. Each electric utility shall make reasonable efforts to avoid and prevent interruptions of service. However, when interruptions occur, service shall be reestablished within the shortest time practicable, consistent with safety.

b. The electric utility's electrical transmission and distribution facilities shall be designed, constructed, maintained, and electrically reinforced and supplemented as required to reliably perform the power delivery burden placed upon them in the storm and traffic hazard environment in which they are located.

c. Each electric utility shall carry on an effective preventive maintenance program and shall be capable of emergency repair work on a scale which its storm and traffic damage record indicates as appropriate to its scope of operations and to the physical condition of its transmission and distribution facilities.

d. In appraising the reliability of the electric utility's transmission and distribution system, the board will consider the condition of the physical property and the size, training, supervision, availability, equipment, and mobility of the maintenance forces, all as demonstrated in actual cases of storm and traffic damage to the facilities.

e. d.Each electric utility shall keep records of interruptions of service on its primary distribution system and shall make an analysis of the records for the purpose of determining steps to be taken to prevent recurrence of such interruptions.

f. e.Each electric utility shall make reasonable efforts to reduce the risk of future interruptions by taking into account the age, condition, design, and performance of transmission and distribution facilities and providing adequate investment in the maintenance, repair, replacement, and upgrade of facilities and equipment.

g. f.Any electric utility unable to comply with applicable provisions of this rule may file a waiver request pursuant to rule 199—1.3(17A,474,476).

20.18(4) Definitions. Terms and formulas when used in this rule are defined as follows:

"Customer" means (1) any person, firm, association, or corporation, (2) any agency of the federal, state, or local government, or (3) any legal entity responsible by law for payment of the electric service from the electric utility which has a separately metered electrical service point for which a bill is provided. Electrical service point means the point of connection between the electric utility's equipment and the customer's equipment. Each meter equals one customer. Retail customers are end-use customers who purchase and ultimately consume electricity.

"Customer average interruption duration index (CAIDI)" means the average interruption duration for those customers who experience interruptions during the year. It is calculated by dividing the annual sum of all customer interruption durations by the total number of customer interruptions.

"Distribution system" means that part of the electric system owned or operated by an electric utility and designed to operate at a nominal voltage of 25,000 volts or less.

"Electric utility" means investor-owned electric utilities and electric cooperative corporations and associations owning, controlling, operating, or using transmission and distribution facilities and equipment subject to the board's jurisdiction.

"GIS" means a geospatial information system. This is an information management framework that allows the integration of various data and geospatial information.

"Interrupting device" means a device capable of being reclosed whose purpose is to interrupt faults and restore service or disconnect loads. These devices can be manual, automatic, or motor-operated. Examples may include transmission breakers, feeder breakers, line reclosers, motor-operated switches, fuses, or other devices.

"Interruption" means a loss of service to one or more customers or other facilities and is the result of one or more component outages. The types of interruption include momentary event, sustained, and scheduled. The following interruption causes shall not be included in the calculation of the reliability indices:

1.Interruptions intentionally initiated pursuant to the provisions of an interruptible service tariff or contract and affecting only those customers taking electric service under such tariff or contract;

2.Interruptions due to nonpayment of a bill;

3.Interruptions due to tampering with service equipment;

4.Interruptions due to denied access to service equipment located on the affected customer's private property;

5.Interruptions due to hazardous conditions located on the affected customer's private property;

6.Interruptions due to a request by the affected customer;

7.Interruptions due to a request by a law enforcement agency, fire department, other governmental agency responsible for public welfare, or any agency or authority responsible for bulk power system security;

8.Interruptions caused by the failure of a customer's equipment; the operation of a customer's equipment in a manner inconsistent with law, an approved tariff, rule, regulation, or an agreement between the customer and the electric utility; or the failure of a customer to take a required action that would have avoided the interruption, such as failing to notify the company of an increase in load when required to do so by a tariff or contract.

"Interruption duration" as used herein in regard to sustained outages means a period of time measured in one-minute increments that starts when an electric utility is notified or becomes aware of an interruption and ends when an electric utility restores electric service. Durations of less than five minutes shall not be reported in sustained outages.

"Interruption, momentary Momentary interruption" means single operation of an interrupting device that results in a voltage of zero. For example, two breaker or recloser operations equals two momentary interruptions. A momentary interruption is one in which power is restored automatically.

"Interruption, momentary Momentary event interruption" means an interruption of electric service to one or more customers of duration limited to the period required to restore service by an interrupting device. Note: Such switching operations must be completed in a specified time not to exceed five minutes. This definition includes all reclosing operations that occur within five minutes of the first interruption. For example, if a recloser or breaker operates two, three, or four times and then holds, the event shall be considered one momentary event interruption.

"Interruption, scheduled Scheduled interruption" means an interruption of electric power that results when a transmission or distribution component is deliberately taken out of service at a selected time, usually for the purposes of construction, preventive maintenance, or repair. If it is possible to defer the interruption, the interruption is considered a scheduled interruption.

"Interruption, sustained Sustained interruption" means any interruption not classified as a momentary event interruption. It is an interruption of electric service that is not automatically or instantaneously restored, with duration of greater than five minutes.

"Loss of service" means the loss of electrical power, i.e., a complete loss of voltage, to one or more customers. This does not include any of the power quality issues such as sags, swells, impulses, or harmonics. Also see definition of "interruption."

"Major event" will be declared whenever extensive physical damage to transmission and distribution facilities has occurred within an electric utility's operating area due to unusually severe and abnormal weather or event and:

1.Wind speed exceeds 90 mph for the affected area, or

2.One-half inch of ice is present and wind speed exceeds 40 mph for the affected area, or

3.Ten percent of the affected area total customer count is incurring a loss of service for a length of time to exceed five hours, or

4.20,000 customers in a metropolitan area are incurring a loss of service for a length of time to exceed five hours.

"Meter" means, unless otherwise qualified, a device that measures and registers the integral of an electrical quantity with respect to time.

"Metropolitan area" means any community, or group of contiguous communities, with a population of 20,000 individuals or more.

"Momentary average interruption frequency index (MAIFI)" means the average number of momentary electric service interruptions for each customer during the year. It is calculated by dividing the total number of customer momentary interruptions by the total number of customers served.

"OMS" is a computerized outage management system.

"Operating area" means a geographical area defined by the electric utility that is a distinct area for administration, operation, or data collection with respect to the facilities serving, or the service provided within, the geographical area.

"Outage" means the state of a component when it is not available to perform its intended function due to some event directly associated with that component. An outage may or may not cause an interruption of service to customers, depending on system configuration.

"Power quality" means the characteristics of electric power received by the customer, with the exception of sustained interruptions and momentary event interruptions. Characteristics of electric power that detract from its quality include waveform irregularities and voltage variations, either prolonged or transient. Power quality problems shall include, but are not limited to, disturbances such as high or low voltage, voltage spikes and transients, flickers and voltage sags, surges and short-time overvoltages, as well as harmonics and noise.

"Rural circuit" means a circuit not defined as an urban circuit.

"System average interruption duration index (SAIDI)" means the average interruption duration per customer served during the year. It is calculated by dividing the sum of the customer interruption durations by the total number of customers served during the year.

"System average interruption frequency index (SAIFI)" means the average number of interruptions per customer during the year. It is calculated by dividing the total annual number of customer interruptions by the total number of customers served during the year.

"Total number of customers served" means the total number of customers served on the last day of the reporting period.

"Urban circuit" means a circuit where both 75 percent or more of its customers and 75 percent or more of its primary circuit miles are located within a metropolitan area.

20.18(5) Record-keeping requirements.

a. Required records for electric utilities with over 50,000 Iowa retail customers.

(1)Each electric utility shall maintain a geospatial information system (GIS) and an outage management system (OMS) sufficient to determine a history of sustained electric service interruptions experienced by each customer. The OMS shall have the ability to access data for each customer in order to determine a history of electric service interruptions. Data shall be sortable by each of, and in any combination with, the following factors:

1.State jurisdiction;

2.Operating area (if any);

3.Substation;

4.Circuit;

5.Number of interruptions in reporting period; and

6.Number of hours of interruptions in reporting period.

(2)Records on interruptions shall be sufficient to determine the following:

1.Starting date and time the utility became aware of the interruption;

2.Duration of the interruption;

3.Date and time service was restored;

4.Number of customers affected;

5.Description of the cause of the interruption;

6.Operating areas affected;

7.Circuit number(s) of the distribution circuit(s) affected;

8.Service account number or other unique identifier of each customer affected;

9.Address of each affected customer location;

10.Weather conditions at time of interruption;

11.System component(s) involved (e.g., transmission line, substation, overhead primary main, underground primary main, transformer); and

12.Whether the interruption was planned or unplanned.

(3)Each electric utility shall maintain as much information as feasible on momentary interruptions.

(4)Each electric utility shall keep information on cause codes, weather codes, isolating device codes, and equipment failed codes.

1.The minimum interruption cause code set should include: animals, lightning, major event, scheduled, trees, overload, error, supply, equipment, other, unknown, and earthquake.

2.The minimum interruption weather code set should include: wind, lightning, heat, ice/snow, rain, clear day, and tornado/hurricane.

3.The minimum interruption isolating device set should include: breaker, recloser, fuse, sectionalizer, switch, and elbow.

4.The minimum interruption equipment failed code set should include: cable, transformer, conductor, splice, lightning arrester, switches, cross arm, pole, insulator, connector, other, and unknown.

5.Utilities may augment the code sets listed above to enhance tracking.

(5)An electric utility shall retain for seven years the records required by 20.18(5)"a"(1) through (4).

(6)Each electric utility shall record the date of installation of major facilities (poles, conductors, cable, and transformers) installed on or after April 1, 2003, and integrate that data into its GIS database.

b. Required records for all other electric utilities.

(1)Each electric utility, other than those providing only wholesale electric service, shall record and maintain sufficient records and reports that will enable it to calculate for the most recent seven-year period the average annual hours of interruption per customer due to causes in each of the following four major categories: power supplier, major storm, scheduled, and all other. Those electric utilities that provide only wholesale electric service shall provide their wholesale customers with the information necessary to allow those customers to ascertain the cause of power supply-related outages.

The category "scheduled" refers to interruptions resulting when a distribution transformer, line, or owned substation is deliberately taken out of service at a selected time for maintenance or other reasons.

The interruptions resulting from either scheduled or unscheduled outages on lines or substations owned by the power supplier are to be accounted for in the "power supplier" category.

The category "major storm" represents service interruptions from conditions that cause many concurrent outages because of snow, ice, or wind loads that exceed design assumptions for the lines.

The "all other" category includes outages primarily resulting from emergency conditions due to equipment breakdown, malfunction, or human error.

(2)When recording interruptions, each electric utility, other than those providing only wholesale electric service, shall use detailed standard codes for interruption analysis recommended by the United States Department of Agriculture, Rural Utilities Service (RUS) Bulletin 1730A-119, Tables 1 and 2, including the major cause categories of equipment or installation, age or deterioration, weather, birds or animals, member (or public), and unknown. The utility shall also include the subcategories recommended by RUS for each of these major cause categories.

(3)Each electric utility, other than those providing only wholesale electric service, shall also maintain and record data sufficient to enable it to compute systemwide calculated indices for SAIFI-, SAIDI-, and CAIDI-type measurements, once with the data associated with "major storms" and once without.

c. b.Each electric utility shall make its records of customer interruptions available to the board as needed upon request.

20.18(6) No change.

20.18(7) Annual reliability and service quality report for utilities with more than 50,000 Iowa retail customers. Each electric utility with over 50,000 Iowa retail customers shall submit to the board on or before May 1 of each year an annual reliability report for the previous calendar year for the Iowa jurisdiction. The report shall include the following information:

a. Description of service area. Urban and rural Iowa service territory customer count, Iowa operating area customer count, if applicable, and major communities served within each operating area.

b. System reliability performance.

(1)An overall assessment of the reliability performance, including the urban and rural SAIFI, SAIDI, and CAIDI reliability indices for the previous calendar year for the Iowa service territory and each defined Iowa operating area, if applicable. This assessment shall include outages at the substation, transmission, and generation levels of the system that directly result in sustained interruptions to customers on the distribution system. These indices shall be calculated twice, once with the data associated with major events and once without. This assessment should contain tabular and graphical presentations of the trend for each index as well as the trends of the major causes of interruptions.

(2)The urban and rural SAIFI, SAIDI, and CAIDI reliability average indices for the previous five calendar years for the Iowa service territory and each defined Iowa operating area, if applicable. The reliability average indices shall include outages at the substation, transmission, and generation levels of the system that directly result in sustained interruptions to customers on the distribution system. Calculation of the five-year average shall start with data from the year covered by the first Annual Reliability Report submittal so that by the fifth Annual Reliability Report submittal a complete five-year average shall be available. These indices shall be calculated twice, once with the data associated with major events and once without.

(3)The MAIFI reliability indices for the previous five calendar years for the Iowa service territory and each defined Iowa operating area for which momentary interruptions are tracked. The first annual report should specify which portions of the system are monitored for momentary interruptions, identify and describe the quality of data used, and update as needed in subsequent reports.

c. Reporting on customer outages.

(1)The reporting electric utility shall provide tables and graphical representations showing, in ascending order, the total number of customers that experienced set numbers of sustained interruptions during the year (i.e., the number of customers who experienced zero interruptions, the number of customers who experienced one interruption, two interruptions, three interruptions, and so on). The utility shall provide this for each of the following:

1.All Iowa customers, excluding major events.

2.All Iowa customers, including major events.

(2)The reporting electric utility shall provide tables and graphical representations showing, in ascending order, the total number of customers that experienced a set range of total annual sustained interruption duration during the year (i.e., the number of customers who experienced zero hours total duration, the number of customers who experienced greater than 0.0833 but less than 0.5 hour total duration, the number of customers who experienced greater than 0.5 but less than 1.0 hour total duration, and so on, reflecting half-hour increments of duration). The utility shall provide this for each of the following:

1.All Iowa customers, excluding major events.

2.All Iowa customers, including major events.

d. Major event summary. For each major event that occurred in the reporting period, the following information shall be provided:

(1)A description of the area(s) impacted by each major event;

(2)The total number of customers interrupted by each major event;

(3)The total number of customer-minutes interrupted by each major event; and

(4)Updated damage cost estimates to the electric utility's facilities.

e. Information on transmission and distribution facilities.

(1)Total circuit miles of electric distribution line in service at year's end, segregated by voltage level. Reasonable groupings of lines with similar voltage levels, such as but not limited to 12,000- and 13,000-volt three-phase facilities, are acceptable.

(2)Total circuit miles of electric transmission line in service at year's end, segregated by voltage level.

f. Plans and status report. A plan for service quality improvements, including costs, for the electric utility's transmission and distribution facilities that will ensure quality, safe, and reliable delivery of energy to customers.

g. Capital expenditure information. Reporting of capital expenditure information shall start with data from the year covered by the first Annual Reliability Report submittal so that by the fifth Annual Reliability Report submittal five years of data shall be available in each subsequent annual report.

(1)Each electric utility shall report on an annual basis the total of:

1.Capital investment in the electric utility's Iowa-based transmission and distribution infrastructure approved by its board of directors or other appropriate authority. If any amounts approved by the board of directors are designated for use in a recovery from a major event, those amounts shall be identified in addition to the total.

2.Capital investment expenditures in the electric utility's Iowa-based transmission and distribution infrastructure. If any expenditures were utilized in a recovery from a major event, those amounts shall be identified in addition to the total.

(2)Each electric utility shall report the same capital expenditure data from the past five years in the same fashion as in 20.18(7)"g"(1).

h. Maintenance. Reporting of maintenance information shall start with data from the year covered by the first Annual Reliability Report submittal so that by the fifth Annual Reliability Report submittal five years of data shall be available in each subsequent annual report.

(1)Total maintenance budgets and expenditures for distribution, and for transmission, for each operating area, if applicable, and for the electric utility's entire Iowa system for the past five years. If any maintenance budgets and expenditures are designated for use in a recovery from a major event, or were used in a recovery from a major event, respectively, those amounts shall be identified in addition to the totals.

(2)Tree trimming.

1.The budget and expenditures described in 20.18(7)"h"(1) shall be stated in such a way that the total annual tree trimming budget expenditures shall be identifiable for each operating area and for the electric utility's entire Iowa system for the past five years.

2.Total annual projected and actual miles of transmission line and of distribution line for which trees were trimmed for the reporting year for each operating area and for the electric utility's entire Iowa system for the reporting year, compared to the past five years. If the utility has utilized, or would prefer to utilize, an alternative method or methods of tracking physical tree trimming progress, it may propose the use of that method or methods to the board in a request for waiver.

3.In the event the utility's actual tree trimming performance, based on how the utility tracks its tree trimming as described in 20.18(7)"h"(2)"1," lags behind its planned trimming schedule by more than six months, the utility shall be required to file for the board's approval additional tree trimming status reports on a quarterly basis. Such reports shall describe the steps the utility will take to remediate its tree trimming performance and backlog. The additional quarterly reports shall continue until the utility's backlog has been reduced to zero.

i. The annual reliability report shall include the number of poles inspected, the number rejected, and the number replaced.

20.18(8) Annual report for all electric utilities not reporting pursuant to 20.18(7).

a. Each electric utility shall adopt and have approved by its board of directors or other governing authority a reliability plan. The plan shall be updated not less than annually.

b. By April 1 of each year, each electric utility shall prepare for its board of directors or other governing authority a reliability report. A copy of the annual report shall be filed with the board for informational purposes, shall be made publicly available in its entirety to customers/consumer owners, and shall report on the reliability indices in 20.18(5)"b"(3) for each of the five previous calendar years.

20.18(9) 20.18(7) Inquiries about electric service reliability.

a. For electric utilities with over 50,000 Iowa retail customers. A customer may request a report from an electric utility about the service reliability of the circuit supplying the customer's own meter. Within 20 working days of receipt of the request, the electric utility shall supply the report to the customer at a reasonable cost. The report should identify which interruptions (number and durations) are due to major events.

b. Other utilities are encouraged to adopt similar responses to the extent it is administratively feasible.

Item 12. Amend subrule 20.19(1) as follows:

20.19(1) Notification. The notification requirements in subrules 20.19(1) and 20.19(2) are for the timely collection of electric outage information that may be useful to emergency management agencies in providing for the welfare of individual Iowa citizens. Each electric utility shall notify the board when it is projected that an outage may result in a loss of service for more than six hours and the outage meets one of the following criteria:

a. For all utilities, loss of service for more than six hours to substantially all of a municipality, including the surrounding area served by the same utility. A utility may use loss of service to 75 percent or more of customers within a municipality, including the surrounding area served by the utility, to meet this criterion;

b. For utilities with 50,000 or more customers, loss of service for more than six hours to 20 percent of the customers in a utility's established zone or loss of service to more than 5,000 customers in a metropolitan area, whichever is less;

c. For utilities with more than 4,000 customers and fewer than 50,000 customers, loss of service for more than six hours to 25 percent or more of the utility's customers;

d. c.A major event as defined in subrule 20.18(4); or

e. d.Any other outage considered significant by the electric utility. This includes loss of service for more than six hours to significant public health and safety facilities known to the utility at the time of the notification, even when the outage does not meet the criteria in paragraphs 20.19(1)"a" through "d." and "b."

Item 13. Adopt the following new rule 199—20.21(476):

199—20.21(476) Transmission cost adjustment (TCA).

20.21(1) Transmission cost adjustment. Pursuant to Iowa Code section 476.6(8)"b," public utilities may automatically adjust rates and charges to recover transmission-related costs incurred by or charged to the public utility consistent with a tariff or agreement that is subject to the jurisdiction of the Federal Energy Regulatory Commission, provided that a schedule showing the automatic adjustment of rates and charges is first filed with and approved by the board. Transmission cost adjustments shall be computed and tracked separately for each customer classification or grouping previously approved by the board and shall use the same unit of measure as the utility's tariffed rates. Changes in the customer classification and grouping on file are not automatic and require prior approval by the board. If any eligible cost is recovered outside the TCA, the cost may not be recovered through the TCA until the cost is removed from its current recovery mechanism. All eligible costs shall be moved to the TCA during the utility's next rate case unless the utility elects to discontinue use of the TCA mechanism.

20.21(2) TCA annual factor. An annual TCA factor update shall be filed as a TF docket at least 30 days prior to the beginning of the utility's TCA year. The TCA update shall include information describing which eligible TCA costs are being recovered through the TCA and, if not recovered through the TCA, where eligible costs are being recovered. The annual TCA factors for each customer classification or grouping shall be based upon forecasted transmission costs allocated to Iowa customers, forecasted Iowa sales or demand, and allocation factors approved by the board. The forecasted allocation factors shall be based on a three-year average of the actual allocation factors for each of the three previous calendar years. For customers billed by kilowatt-hours, the factors shall be developed on a kilowatt-hour basis. For customers billed by kilowatt, the factors shall be developed on a kilowatt basis. In addition, the following is required to be included with this filing:

a. A listing of all transmission costs that are incurred by or charged to the public utility and are consistent with a tariff or agreement that is subject to the jurisdiction of the Federal Energy Regulatory Commission, detailing where each transmission cost is currently being recovered (e.g., base rates, TCA).

b. A time series analysis of each transmission cost eligible for inclusion in the TCA, detailing monthly cost fluctuations, beginning with the implementation of the utility's transmission rider.

20.21(3) Annual reconciliation. Within four months after the effective date of annual TCA factors, a utility shall file an annual reconciliation based upon actual costs and revenues attributed to Iowa customers for the prior calendar year. The annual reconciliation shall be filed in the same TF docket identified for the annual filing required in subrule 20.21(2). The reconciliation shall include updated allocators for each customer classification or grouping based on actual load data from the prior calendar year. The actual costs for the prior calendar year shall be allocated to each customer class based upon the updated allocation factors. The utility shall compare the actual transmission costs allocated to each customer class with the actual revenue billed through the TCA by customer class net of the prior year's reconciliation dollar amount for each customer class. Any resulting overcollection or undercollection for each class shall be divided by the forecasted sales or demand for each customer class for the remainder of the TCA period. The resulting adjustments shall be added to the effective TCA factors which were approved in the TCA annual factor filing under subrule 20.21(2). The adjusted TCA factor for customers billed by kilowatt-hours shall be developed on a kilowatt-hour basis, and for customers billed on a kilowatt basis, the adjusted TCA factor shall be developed on a kilowatt basis.

20.21(4) Other adjustments to the TCA factor. A utility may propose other adjustments to the TCA factor throughout the 12-month TCA period to assist with accurate recovery of forecasted costs and revenues, subject to board approval. Any midyear adjustments shall be filed in the same TF docket as the annual filing. If a utility proposes an adjustment to the TCA factor, other than the reconciliation required in subrule 20.21(3), the utility shall provide an explanation for the proposed adjustment and provide information to support the proposed adjustment. For any customer billed by kilowatt-hours, the proposed adjustment shall be developed on a kilowatt-hour basis. For any customer billed on a kilowatt basis, the proposed adjustment shall be developed on a kilowatt basis.

20.21(5) Quarterly informational filings. By the end of the month following the end of each calendar quarter, the utility must file a report containing, at minimum, the current cumulative overcollection or undercollection balance, support for the overcollection or undercollection calculation, the total transmission cost for the current calendar year by category, and the supporting invoices and documentation for the most recent calendar quarter. The reports shall be filed in the same TF docket as the annual TCA filing.

20.21(6) Semiannual transmission reports. Each year at the beginning, and midpoint of a utility's TCA year, each utility shall file a report detailing the utility's transmission-related activities. These reports shall detail the utility's recent efforts to mitigate transmission costs and influence policy to the benefit of the utility and its ratepayers.